WASP 2001 manual

Well Productivity
AWARENESS
WELL PRODUCTIVITY AWARENESS SCHOOL
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recording, or otherwise), without the prior written admission of
TRACS International Training Ltd. and BP Exploration.
Revision 2: 2001
TABLE OF CONTENTS
INTRODUCTION
3
Course Objectives
Economic Importance of Well Productivity
Introduction to Notes
Acknowledgments
4
6
7
7
OVERVIEW OF WELL PRODUCTION
9
Well Type
Influence of Geology
How Wells Produce
Formation Damage/'Skin'
Types of Formation Damage
Module Summary
11
14
20
25
31
35
DRILLING THE RESERVOIR
37
Drilling Fluids
Fractures
Drilling Underbalanced
Coring
Module Summary
39
55
57
60
63
COMPLETIONS
65
History
Completion Types
Multilateral Wells
Geosteering
Completion Practices
Module Summary
STIMULATION
Acidisation
Microbal Treatments
Hydraulic Fracturing
Module Summary
66
67
71
76
80
119
121
123
139
141
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WELL PRODUCTIVITY AWARENESS SCHOOL
PRODUCTION RELATED FORMATION
DAMAGE
Precipitation
Fines Migration
Phase-Related Permeability Reduction
Stress Induced Permeability Change
Injection Wells
Module Summary
WORKOVERS
Types
Workover Practices
Water Shut Off Treatments
Coiled Tubing
Module Summary
SUMMARY
Where Do We Go From Here?
Communication
GLOSSARY
157
159
167
168
170
171
172
173
174
176
188
190
200
201
218
219
207
INTRODUCTION
Revision 2: 2001
Introduction
4
Course Objectives
4
Economic Importance of
Well Productivity
6
Introduction to Notes
7
Acknowledgments
7
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WELL PRODUCTIVITY AWARENESS SCHOOL
Introduction
Course Objectives
The objective of the course is to make all participants aware of the following:
•
•
How your job can impact on well productivity
Where you can make a difference
By enhancing your knowledge of Well Productivity and Formation Damage, the
course will make you aware of the consequences of your actions when you are
involved in an operation; be it a planning role in the office, or an operating role
on the rig.
Well Productivity is influenced by your actions throughout the life of a well;
♦
♦
♦
♦
♦
♦
Drilling
Testing
Completion
Production
Workover
Stimulation
The planning or operational decisions you make impact the whole life of
the well ; not just its immediate future.
This course involves both Operator and Contractor/Service Company personnel,
because everyone needs to be involved. Contributions from the floor are
welcomed, to combine local knowledge and problems with the course contents.
There is increasing emphasis for contractors and service companies to provide
a ‘product’, ‘an undamaged well’, rather than just a service or a piece of
equipment. The responsibility for planning, drilling and operating a successful
well is shifting from the Operator to the Contractor/Service company. This
success is important to:
•
•
Gain more work for your particular company.
To encourage the Operator to develop more marginal fields.
The drilling of successful undamaged wells will mean a secure future.
PROFITABLE FIELD DEVELOPMENT – MORE WORK – JOBS
4
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INTRODUCTION
Potential rates
If the formation is damaged, the
plateau rate cannot be sustained.
Cash flow is diminished
Profitability declines
Agreed plateau rate
With damage
No damage
Too little, too late
Money must be
spent to
stimulate the well.
Therefore lower
profitability.
Abandonment
0
2
4
6
8
10
12
14
16
Production time (years)
ECONOMIC IMPORTANCE OF WELL PRODUCTIVITY
Well Productivity
Awareness - The Team
Mud
Cementer
Drilling Engr
Logger
Stimulation
Engr
Geologist
Fluids
Engr
Rig
Hands
Others
Logging Engr
Reservoir
Engr
Driller
Q
Company
Man
Revision 2: 2001
Completions
Engr
Tool
Pusher
A
Why should formation damage
concern you?
Because it means less
production
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WELL PRODUCTIVITY AWARENESS SCHOOL
Economic Importance of Well Productivity
It has always been known that formation damage or well impairment leads to
lower production rates and, thereby, a loss of revenue. BP quantified this loss in
financial terms (for their operated fields and seven partner-operated fields) in a
report written in January 1991. They concluded that:
“The potential ‘net present cost’ of formation damage to BPX, assessed over
the remaining life of currently producing fields, is estimated to be in the
region of $1.5 billion, before the effect of taxation”.
The above calculation was arrived at by taking into account:
•
•
Expenditure on remedial/inhibitive treatments
Loss of value resulting from deferred production (and therefore
deferred cash flow)
A key assumption was that ‘formation damage did not result in any LOST
production’. The pre-tax figure of $1.5 billion is therefore conservative.
Some of this loss is already being avoided with procedures underway, and some
of the loss may never be prevented; however there is potential for
considerable improvement .
THIS IMPROVEMENT IS THE RESPONSIBILITY OF EVERYONE.
Every oil company suffers from well impairment. One company in the US Gulf
Coast increased its well productivity from 2 to 20 stb/d/psi through concerted
efforts to improve well completion techniques and reduce formation damage.
This means that an average well would produce at 30,000 bbls/day instead of just
3000 bbls/day. A major oil company estimated that if formation damage had not
occurred (or could be removed) in their gravel-packed wells they could be
producing an extra million barrels
of oil per day worldwide ≅ $20,000,000/day.
We believe that enhanced awareness of the problem, and the cost savings and
increased production emanating from that knowledge, will be the ultimate
dividend from Well Productivity Awareness training.
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INTRODUCTION
Introduction to Notes
These notes roughly follow the course presentation and provide a reference
document. Not every viewgraph shown during the course is included in this
book, nor is every illustration in this book used as a viewgraph. All the exercises
done during the course will be handed out at the time.
There is a Glossary after the Summary Section, which attempts to cover all of
the terms with which you may be unfamiliar.
Acknowledgements
This course was compiled using information gathered from BP’s 'Basics of
Damage and Stimulation' (PPTO42) school and Mr. Peter Greaves prepared the
manual with the assistance of BP Research Centre (UTG). The project has
involved many different disciplines, and has received input from John Mason,
Phil Smith, Bill McLellan, Sandy Petrie, Ian Pitkethly and James Cobbett.
Several service companies have been generous contributors, most noticeably
Baker-Hughes INTEQ. The Schlumberger organisations have provided graphics
and presentation materials from their 'Oilfield Review', and from their own
training centres. Halliburton and Sperry Sun have also contributed materials
for the school.
TRACS International Training Ltd.
February 2001
Revision 2: 2001
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WELL PRODUCTIVITY AWARENESS SCHOOL
8
Revision 1: January 1995
O V E RVIEW OF WELL PRODUCTION
Overview of Well Prroduction 11
Well Type
Exploration
Appraisal
Development
Influence of Geology
The Reservoir Porosity and Permeability
Rock Type
Rock Analysis
Reservoir Geometry and
Permeability Distribution
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11
11
13
13
14
14
14
17
20
How Wells Produce
20
Formation Damage/'Skin'
25
Definitions
a. Linear Flow vs. Radial Flow
b. Formation Damage
c. Skin
d. Flow Efficiency
e. Productivity Index
f. What is optimum Skin Factor?
25
25
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27
29
29
31
Types of Formation Damage
31
MODULE SUMMARY
35
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WELL PRODUCTIVITY AWARENESS SCHOOL
Radio location
antenna
Floating firing
line
Radar reflector
tail marker
Shot
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Fathometer
Geophone
cable
MARINE REFLECTION SHOOTING
Dry
Hole
Oil
Well
Seismic
reflection
time
Top Balder
Base Tertiary
Base Chalk
Base Cretaceous
Base Reservoir
Top Zechstein
0
1 km
Migrated seismic section through an oil field
2000
Shales
Chalk
3000
Shales
Sand
Shales
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4000
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5000
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Caprock (seal)
Oil
Source rock
Water
Reservoir
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0
1 km
6000
Cross section through the oil field, drawn along the line of the seismic section
(No vertical exaggeration)
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O V E RVIEW OF WELL PRODUCTION
Overview of Well Production
At the end of this module you should be aware of:
*
*
*
*
*
The main reservoir characteristics that affect well productivity
How oil flows from the reservoir into the well
The importance of the near wellbore region
What formation damage is
How to compare the productivity of different wells
Well Type
Exploration
Prior to any drilling, the geophysicists of the Exploration Department have shot
seismic and have interpreted the results. The interpretation of the seismic will
define a structure to be drilled. The geologists will ascertain whether or not there
is likely to be a reservoir rock and a source rock.
An exploration well is the first one to be drilled on a prospect. The main aims of
the well are to establish whether hydrocarbons are present. The geological data
taken from cuttings, cores and electric logs are the prime objectives of the well.
If the well is successful in finding hydrocarbons it may be production tested. Any
formation damage will become evident during the testing of the well (although it
may also have caused some log interpretation problems earlier); in an extreme
case severe formation damage could mean a valuable field is completely missed.
In an exploration well, the aim is to obtain the above information at the lowest
cost. Good quality data are required; this takes priority in well design and
execution. Most exploration wells are currently plugged and abandoned
(although there is an increasing trend both on land and offshore to keep
successful exploration wells, and therefore formation damage should be
minimised as much as is practicably possible).
EXPLORATION WELL
Drilled for geological information, often plugged and abandoned
but increasingly kept for production.
Formation Damage: Not critical if well is to be P&A'd. However
poor hole condition and deep fluid invasion will hamper log
interpretation. Skin values recorded during well testing require
interpretation. Cores should be cut in the reservoir.
APPRAISAL WELL to test the western extension of the field.
Cores are cut in the reservoir. In the design stage, attempts should
be made to reduce damage caused in the Exploration Well (high
skins).
WATER INJECTION
WELL Water may be
injected into the aquifer
below the hydrocarbons
to maintain reservoir
pressure. Formation
damage is often
by-passed by small
induced fractures.
Subsea Completion
P
Exploration Well
Appraisal Well
Subsea Completion
TYPES OF WELL
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Development Well
Injection Well
DEVELOPMENT WELL
It is critical that the design and
execution of the well minimises
damage. The well completion must
optimise/maximise well productivity.
Platform
P
APPRAISAL WELL to test
downdip extension of oil column.
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WELL PRODUCTIVITY AWARENESS SCHOOL
A
A Structure
Structure
•
•
•
•
•
A
A Cap
Cap rock
rock
• Impermeable
• Widespread
Anticline
Dome
Fault trap
Sedimentary trap
Salt diapir
A
A Reservoir
Reservoir
• Porosity
• Permeability
• Hydrocarbon Saturation
Oil
A Kitchen?
A Structure
(Source
Rock)
Water
• Generation of hydrocarbons
countless millions of years
ago
OWC
WHAT MAKES AN OIL/GAS FIELD?
a) Stage 1 : Diagrammatic section across strata before folding begins
Sea level
Sea
Sandstones etc
Limestones
Salts, marls, anhydrites etc
Anhydrite (Cap rock)
Limestone reservoir
Shale formation
All strata flat, oil in limestone beginning to separate out from water and take its
place in the more porous bands. Note also the general tendency for the oil to
migrate upwards via joints. It will be held up finally by the completely impervious
b) Stage 2 : Diagrammatic section across gently folded strata
Early stage in folding
Gas seepage
Conglomerates
Sandstones etc
Limestones
Salt, marls, anhydrites etc
Anhydrite (Cap rock)
Limestone reservoir
Shale formation
c) Stage 3 : Diagrammatic section across more intensely folded strata
Conglomerates
Anticline
Spill
point
Sandstones etc
Limestones
Salt, marls, anhydrites etc
Anhydrite (Cap rock)
Limestone reservoir
Shale formation
Syncline
Showing disharmonic folding of upper beds due to plasticity and flow of salt,
marl and anhydrite formation.
Oil
Gas
Water
HOW AN OILFIELD DEVELOPS IN THE COURSE OF AN EARTH FOLDING MOVEMENT
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O V E RVIEW OF WELL PRODUCTION
Appraisal
An appraisal well is drilled as the intermediate stage between exploration and
production, to determine the size of a field and its reservoir properties and how
much the wells will produce. Since the geology of the area is now better known,
the drilling and completion of the well can be better designed to achieve a
minimally damaged well. This should further enhance the quality of the data, to
allow the geologists and reservoir engineers to have greater confidence in their
production predictions for the life of the field. Poor quality data could lead to
incorrect decisions being made about important factors such as the number of wells,
number of platforms and plateau production rates. If a damaged appraisal well
flows at low rates then the Operator may decide not to develop the field, because
of a lack of confidence in the reservoir, and whether or not it can be drilled
without damage.
Remember: MORE DEVELOPMENT – MORE WORK –
MORE JOBS.
Development
The development plan is now written and the number of wells
(producers/injectors) has been defined. The production from (or injection into)
these wells has been predicted using a ‘skin factor’ to allow for formation damage
and completion efficiency. The economic viability of the field is based upon these
predictions. If the development wells are damaged more than predicted, the field
stands a chance of being unprofitable. If the industry – you the oil company
engineers, contractors and service companies – cannot drill, complete and operate
these wells as per the specification, the field could be uneconomic. It will be
abandoned prematurely – and the next field of its kind will not be developed.
Minimising formation damage is most critical in field development wells,
but also very important in appraisal wells.
Formation damage must also be
minimised in exploration wells, but only after considering the priority need for
goal data.
Principal Ways By Which Formation Damage Costs
Money
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Type of Well
Type of Cost
Exploration
Missed oilfields
Poor quality data
Appraisal
Poor quality data
More appraisal wells
Remedial treatments
Poor facilities design
Development/
Production
More production wells
Lower plateau rate
Remedial treatments
Lower reserves
Lower water injectivity
Costly facility modification
Premature abandonment
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WELL PRODUCTIVITY AWARENESS SCHOOL
Influence of Geology
The Reservoir Porosity and Permeability
Except in very rare exceptions (fractured granite), hydrocarbons are found in
sedimentary rocks . Sedimentary rocks are laid down as ‘pieces’ (grains) or
‘clastics’ with time, usually in an aqueous (water-borne) environment. The
exception to the aqueous environment is the aeolian, or wind transported,
environment. Modern day examples of sedimentary environments are beaches,
sand bars, lagoons, swamps, estuaries, deltas, rivers and deserts.
The two most important factors that make a good reservoir are porosity and
permeability: the porosity is the percentage of void space in the rock where fluids
are stored, and the permeability is a measure of the interconnection of the voids.
Porosity can be measured in the well using electric logs; permeability is far more
difficult (a formation tester can measure permeability). Both properties can be
measured in the laboratory on good core samples.
The pore space (p o ro s i t y ) in a hydrocarbon reservoir is not filled entirely with oil
or gas; there will be some water present. This is known as ‘Sw’, the ‘Water
Saturation’. The Sw is the percentage pore space containing water.
It is the porosity that
effects the volume of
oil/gas in place.
Porosity is the void space in
the rock, expressed as a
percentage of the rock volume
Permeability is a measure
of how easy it is for fluids to
flow through the pore system
It is the permeability
that affects well
productivity
Pore throats are narrow
restrictions between grains
which connect larger voids
POROSITY AND PERMEABILITY
The permeability , ‘k’, is expressed in milliDarcies, and measures the ability of
fluid to pass through the rock. The connections between the voids of the rock
are known as pore throats – these MUST be kept open.
Rock Type
Hydrocarbons are usually found in sandstone and carbonate reservoirs; although
there are a few rare exceptions such as fractured granite, volcanic tuff and oil
shales. Within the simple definition of sandstone and carbonates there are many
variations:
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O V E RVIEW OF WELL PRODUCTION
Sandstone
Carbonate
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•
•
•
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•
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Grain Size
Grain shapes
Degree of Cementation
Cleanliness
Clay Content
Heterogeneity
(rock variability)
Mineral Type (Calcite/Dolomite)
Particle Size
Degree of Cementation
Type of Cementation
Diagenesis (changes in the rock)
Induration (fusing of rock grains)
Heterogeneity
Clay Content
Sandstones are granular sedimentary rocks with grain sizes between 0.0625 and
2mm (‘sand’ is a size classification). The pore space, where hydrocarbons can be
held, is between the grains. The grains are mainly composed of quartz, but
feldspar, chert, mica and other rock fragments are also common. Clay minerals
are often present.
Degree of grain
cementation
Grain size
and sorting
Grain
shape
Clay content
- type
- distribution
SANDSTONES – WHAT YOU NEED TO KNOW
The grains in a sandstone may be cemented together during burial (diagenetic
modification). Cements include quartz, carbonates (e.g. calcites and dolomite) and
clays. The pore system may be lined with, or filled by, clay minerals such as
kaolinite, smectite, chlorite, or illite.
Conglomerates are similar to sandstones but have much bigger grains (pebble
grade = 4-64mm). The space between the pebbles may be partially or completely
filled by sand grains. These rocks can also form reservoirs.
Mudstones are sedimentary rocks which consist of particles finer than sand grade
(less than 0.0625mm) and include both silt and clay grade material. Most of the
particles in mudstones are clay minerals. Mudstones are commonly referred to as
shales . Though mudstones have porosity, they have negligible permeability
(usually less than 1 mD) so they normally form sealing barriers both within and at
the boundaries of the reservoir.
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15
WELL PRODUCTIVITY AWARENESS SCHOOL
Carbonates are composed of carbonate minerals (e.g. calcite and dolomite).
The carbonate is commonly in the form of shells or other skeletal material. Porosity
can be inter-particle (in between the particles, as in sandstones) or intra-particle
due to the dissolution of grains (secondary porosity). Compared to sandstones,
carbonate rock pores are often poorly connected and matrix permeability is low,
but fractures are more common. There are various types of carbonate:
Grain replacement
(dolomitization)
Grain
dissolution
Grains
- size
- type
Degree of
cementation
CARBONATES - WHAT YOU NEED TO KNOW
•
•
•
•
Limestone
Dolomite
Chalk
Marl
Made of calcite (CaCO3)
Made of dolomite (CaMg(CO3)2)
Soft, fine grained limestone made of calcite
Rock made of calcite and clay minerals
Clay Minerals are fine grained lattices of layered silicates. They may occur in
sandstones either in patches (e.g. where they have replaced less stable grains) or
as a pore lining (e.g. the hairy illite seen in the Magnus and Southern N. Sea
fields). The distribution and type of clays is just as important as the amount of
clays when considering whether or not a rock is sensitive to damage. Clays are an
important consideration as to whether a formation is 'sensitive'.
The main types of clay mineral are:
When the clay is in an isolated
clast it is less likely to cause a
formation damage problem even
if it is a swelling clay like smectite
DISTRIBUTION OF CLAYS
Use rock analysis to investigate
potential formation damage
problems.
16
There may be less clay in this sample, but if it
is a smectite (swelling) it will block the pores if
it is allowed to swell. Alternatively if it is a ‘hairy’
illite clay it could entrap fines and similarly cause
a blockage
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O V E RVIEW OF WELL PRODUCTION
•
•
•
•
Kaolinite – plate booklets prone
to migrate
Illite
– fibres prone to catch
moving fines
Chlorite – random platelets (often
iron rich/beware during
acidisation)
Smectite – prone to swell and block
pore throats
ILLITE
CHLORITE
KAOLINITE
Montmorillonite – so often the guilty party in hole problems – falls within the
smectite group of clays. Bentonite, used for drilling, is a smectite.
Rock Analysis
The microscopic details of the rocks are not known at the exploration stage of
drilling. However, if a reservoir is encountered, a good core (including preserved
core) should be obtained for close examination. The geologists are naturally
keen to see what rocks they have, and to age-date them; the reservoir engineer
may subject the core to ‘special core analysis’ (using preserved core) to obtain all
the parameters necessary for his reserves calculations (porosity, permeability,
relative permeability, capillary pressure curves, etc.); and the drilling engineers,
completion engineers, mud engineers – indeed all the petroleum and drilling
engineers – should be interested in the core to investigate potential formation
damage, to improve the design of any subsequent wells.
To this end the following analyses may be carried out:
•
•
Revision 2: 2001
Thin Section
–
–
–
Microscopy
pore spaces visible using a blue resin
minerals identified with polarised light microscope
gives 2D picture of pore structure, location of cements
and clays
– different clay minerals not distinguished
Scanning Electron Microscopy (SEM)
– 3D view of rock surface
– identifies type and distribution of clay minerals
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WELL PRODUCTIVITY AWARENESS SCHOOL
Fault trap
Stratigraphic
Normal fault
Reverse fault
B
Impermeable
Compression
Tension
1
A
Impermeable
1
3
2
x
3
2
Plan
x1
Porous and
permeable
4
x1
x1
Oil
Water
Water
Section
x1
x
Oil
Two kinds of faults are shown, a normal fault resulting
from tension on the left and a reverse or compression
fault on the right. In both cases the effect is to seal off
a permeable bed (2) by bringing it opposite an
impermeable one (1) across the fault so allowing an
accumulation of oil (3) to be trapped. The distance
indicated by (4) shows the horizontal displacement of
beds caused by fault movement.
Permeable
Plan
x
4
x
Section
This illustration shows the plan and section of two oil
traps caused by changes in rock permeability. On the left
a permeable zone is entirely surrounded by
impermeable rock, such conditions are found where
fossil reefs occur. On the right a lithological change
occurs along an arc - possibly parallel to a fossil shoreline.
Salt dome
Compression
Salt plug
Before compaction
This shows how beds are domed up over a
piercement salt plug which has torn its way through
the lower beds. Oil or gas traps can occur wherever
a permeable bed is truncated by the salt plug or in
the anticlines over the crest of the plug.
After compaction
This illustration shows the changes in beds deposited
on an irregular sea floor after compaction caused by
additional overburdening. It will be noted that the
thinning is greatest over the buried crests.
Reef (Carbonate)
Unconformity
Inferred current direction
One series of rocks has been deposited, tilted and
eroded off. Subsequently a second series has been
laid down over the eroded surface and the whole
subjected to further tilting. Traps occur at the
unconformity surface when a permeable bed is
sealed by the lowest impermeable bed of the upper
series.
This illustration shows a reef with one side washed
clean by current action whilst on the lee side beds
of coral detritus are accumulating. Such conditions
are found where reefs contain a lagoon. Traps can
occur in the reef itself or in the beds of detritus.
VARIOUS KINDS OF OIL TRAPS
SAND BODY DISTRIBUTION
Less Productive Well
Productive Well
BARRIERS TO FLOW WILL INFLUENCE THE
MOVEMENT OF OIL AND WATER
Shale barrier of
field-wide extent
Well missed channel sand.
No flow when tested
Field will drain as two large
separate compartments
Well hit coarse-grained
channel sand
Test rate: 1500 stb/day
FRACTURES
need to know the direction of OPEN fractures (not just all fractures)
ALL FRACTURES
OPEN FRACTURES ONLY
N
OIL
N
OWC
Shale barriers
WATER
LESS PRODUCTIVE WELL
Horizontal section drilled
NW-SE to cut all fractures
Test rate: only 295 stb/day
“upper compartment”
“lower compartment”
PRODUCTIVE WELL
Horizontal section drilled
NE-SW to cut open fractures
Test rate: 7300 stb/day
Fractures
18
Wellbore
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O V E RVIEW OF WELL PRODUCTION
•
•
X-ray Diffraction (XRD)
– identifies minerals present
– special clay fraction analysis may be requested
Mercury Porosimetry
– determines distribution of pore throat sizes
– mercury is injected at stepwise increasing pressures
– large pores fill first, smaller pores fill at successively
higher pressures
– volumes injected at different pressures give an indication
of pore size distribution
– useful for establishing whether solids will penetrate a rock
or form a filter cake
It is wise to check how the samples have been prepared;
for instance gold is sometimes used to prepare SEM
specimens – to bleed away excessive electron beam
charging. Gold tends to collapse the clays giving a false
impression of porosity and permeability.
Where clay swelling is thought to be a potential cause of formation damage, not
only is the amount and type of clay important, but so is its location. For example,
a sample may contain 5% swelling smectite clay, but if that clay is located in one
isolated mudstone clast then the sensitivity to damage is small. Alternatively, if 3%
smectite lines the whole pore system, then damage potential is high.
Fines migration damage sensitivity is not so easy to determine by looking at
rock samples. Firstly, potentially mobile fines are not restricted to clay minerals,
and can include any small minerals, for example microcrystalline quartz, feldspar
crystals and fragments of partly degraded grains (e.g. microporous chert). Clays
are, however, very important (and potentially mobile) fines, so they figure
strongly in any assessment of damage sensitivity.
To assess fines sensitivity, the questions to ask are:
•
•
Are there any fines in the rock?
How susceptible are they to mobilisation?
If fines are in discreet patches, such as where kaolinite aggregates have replaced
feldspar grains, or partially degraded chert grains, then the potential for fines
problems will be less than if the fines line or partially fill the major pores. If the
fines have been enclosed by a later cement, then they are unlikely to be
mobilised unless that cement is disturbed.
It pays to view a reasonable number of samples/specimens of the rock to get a
representative picture of the formation; one or two slides/SEM/XRD are not enough.
The above describes what can be done to actually look at and define the rock.
There are also tests than can be done on core plugs, such as ‘return permeability’
tests and these are described later in this book.
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WELL PRODUCTIVITY AWARENESS SCHOOL
Reservoir Geometry and Permeability Distribution
Geological characteristics can influence well performance in two main ways:
Permeability distribution – flow units, layering, tight (cemented) zones, high
permeability streaks, fractures
Boundaries
– faults, slumps, unconformities
It is important to have a good understanding of these characteristics. We cannot
change the geology but we can adapt our field development plans to make the
best use of what we’ve got. A thorough knowledge of all these features can help
us to adopt drilling and completion procedures to minimise formation damage.
Variations in permeability
and reservoir geometry within the drainage radius of
a well can have a major effect on well performance. An example would be a
sealing fault very close to the well which would cause a slope change (part of the
test interpretation procedure) on a well test pressure plot which might be wrongly
interpreted as damage. The location of faults and/or the characterisation of
fractures is important to well test interpretation.
Permeability Layering influences well performance. If layering is defined by
permeability barriers, then some layers could remain undrained if the completion
does not account for the barriers to flow. If the layering is defined by variations
in permeability, rather than barriers, then the contrast between horizontal and
vertical permeability will influence well performance. The determination of the
Kv/Kh ratio (permeability anisotropy: vertical/horizontal) from routine core
analysis data is an important part of geological characterisation. However Kv/Kh
changes depending on what scale you are considering: over reservoir thickness
the Kv/Kh is usually much less than Kv/Kh in core plugs.
How Wells Produce
A well produces oil or gas when the pressure of the oil or gas in the reservoir
pushes the fluids to surface. If the pressure of the reservoir is insufficient to get
the fluids to surface, then the well has to be pumped or gas-lifted (artificial lift).
Whilst drilling a well the hydrostatic pressure of the drilling fluid is used to
suppress the reservoir pressure that will later bring the hydrocarbons to surface.
Once a reservoir is on production, the reservoir pressure may decline as the
energy in the system is gradually exhausted by the production of fluids. If the
reservoir has an ‘active’ drive system, such as a massive charged water reservoir
below the oil, then the pressure will not decline as fast and the production will
remain healthy – all other factors remaining equal. It is however, often necessary
to maintain reservoir pressure by injecting water into the reservoir below the oil.
When a well is producing there are pressure losses in the system. The ones that
concern well productivity are:
a)
b)
20
in the formation
up the tubing
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O V E RVIEW OF WELL PRODUCTION
Pwh, Wellhead
flowing pressure
Pressure losses in
the tubing
Pw, Bottomhole
flowing pressure
Pr, Fluid pressure
at reservoir boundary
Pressure losses in
the reservoir
PRESSURE DROPS CONTROLLING WELL PERFORMANCE
The pressure drops are usually plotted against flowrate to give:
a)
b)
the inflow performance relationship or IPR
the tubing performance curve or lift curve
The intersection of these two curves gives the flowrate at which the well will produce.
Any damage to the well will change the IPR. Factors such as tubing size and wellhead
pressure will change the lift curve. The drawdown on a well is the pressure
difference between the wellbore and the reservoir, that causes the oil or gas to flow
into the well from the reservoir.
Tubing Performance Curves: Calculated by computer or
taken from tables, to predict the pressure loss up the tubing.
Depends upon rate, type of fluid (oil vs gas), gas-oil-ratio,
water content etc. for different tubing sizes.
Bottom hole
flowing
pressure
If bottom hole
flowing pressure is
the same as the
reservoir pressure
the well will not
flow
31/2"
Natural flowrate: in
this particular case
the well will flow
naturally at this
rate with this tubing
in the hole
Pw
Pr
41/2"
51/2"
The lift curve = 'required pressure'
(For a particular sized tubing)
drawdown
Pump pressure (If a higher rate is required)
As the bottom hole
pressure is reduced
the well begins to
flow -pushed by the
reservoir pressure.
The greater the
drawdown the
greater the flow
The IPR = 'Available pressure'
Flowrate
Barrels of Oil per Day
INFLOW PERFORMANCE RELATIONSHIP (IPR) AND TUBING PERFORMANCE CURVES
Note: Although the radial flow equation is linear, the IPR line is not a straight line. This is because the IPR equation
makes some assumptions. For instance in a real oil well the increasing drawdown (lower bottom hole pressure)
may lead to more gas being evolved in the near wellbore region, causing higher gas saturations and more
resistance to oil flow.
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WELL PRODUCTIVITY AWARENESS SCHOOL
How Wells Produce - Water Drive
a)
b)
Cap rock
Oil
Water
At an early stage of production.
At a later stage where the rising water has reached the foot of
the well with the result that it has gone to water. The height
of the water column in the well is a measure of the pressure
of the water zone.
How Wells Produce - Solution Gas Drive
a)
b)
Gas zone where
pressure has fallen
below saturation
pressure due to
production and gas is
coming out of solution
Ingress of water
from aquifer
restricted or
non-existent
With the formation and
expansion of the gas cap
a liner must be put in to
extend casing below the
gas/oil level as the well
would otherwise produce
gas only
Cap rock
Oil
Water
Early stage in solution gas drive production.
22
A later stage where a gas cap has formed due to gas coming
out of solution in the reservoir when the pressure falls below
saturation pressure.
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O V E RVIEW OF WELL PRODUCTION
Diagrams showing the arrangement of gas, oil and
water in typical dome-shaped structures
a)
Gas cap
Gas/oil
contact
Oil/water
contact
Cap rock
Aquifer
Cross section through an oil reservoir
Oil
Oil/water contact
b)
4
Water
Gas/oil contact
2
Gas
8
6
1
5
7
3
Wells which struck oil - No.1 (discovery well) 2, 5, 7 and 8
Well No.3 struck oil and then passed into water
Underground contours
(usually marked in feet
below sea level)
Contour map defining size and shape of reservoir as indicated by the drilling of the
discovery well and 7 appraisal wells
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WELL PRODUCTIVITY AWARENESS SCHOOL
∆p
Flow
Core Length L
Pump
Flowrate
Q
Core
Area A
Q=
Ak ∆p
µL
LINEAR FLOW
radius of damaged region
radius of the well
rd
rw
undamaged
reservoir
kd =
permeability of
damaged
region
RADIAL FLOW
Imagine the drainage area
of this well. Oil that is one
thousand feet away has
plenty of room to travel
through the reservoir to the
wellbore. BUT as it gets
closer and closer there is
less and less room. The
near wellbore region
therefore becomes crucial:
damage this and you
severely impair the wells
productivity.
NEAR WELLBORE DAMAGE
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O V E RVIEW OF WELL PRODUCTION
The pressure losses in the formation are dealt with more fully in Section entitled
‘Formation Damage/Skin’.
The production of oil will be impaired or reduced by the production of water .
Water production may be unavoidable due to the nature of the reservoir; however
efforts should always be made to complete a well to minimise water production.
In an oil well, efforts are usually made to minimise the production of gas, which
can also impact upon the well productivity.
Formation Damage/‘Skin’
Definitions
a) Linear Flow vs Radial Flow
Imagine the passage of a fluid (gas or liquid) through a porous medium, say a
cylindrically shaped piece of rock. The fluid needs pressure to force it from one
end of the cylinder to the other and it needs an interconnection of holes (the
permeability) through the rock to allow the passage of the fluid. The rate at
which the fluid passes through the rock will depend upon the:
•
•
•
•
•
cross-sectional area, A
permeability, k
pressure drop across the block, ∆p
the length of the block, L
the viscosity, µ (the thicker it is the slower it will pass through)
This is linear flow . Henri Darcy studied the subject and gave his name to the
measurement of permeability, the Darcy.
However, when fluid is flowing from a distance (the reservoir limit) to the
wellbore it is described as radial flow . The diagram opposite illustrates radial
flow into a well. The more detailed diagram on the following page illustrates the
calculation of radial flow. The equation that makes up the calculation is
described in the following section.
It can be seen that the pressure drop in the reservoir (psi/ft) increases
significantly as you move closer to the wellbore – and this is for an undamaged
well. If there is 'damage' in the near wellbore region the pressure drop will be
even greater, thus reducing production.
b) Formation Damage
Formation damage may be defined as:
“A reduction of permeability around a wellbore, which is
the consequence of drilling, completion, injection,
attempted stimulation, or production of that well”
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WELL PRODUCTIVITY AWARENESS SCHOOL
AN EXAMPLE OF RADIAL FLOW UNDAMAGED WELL
Darcy's Law
Undamaged Well
100mD Permeability
Zero Skin
Q=
0.00708kh (Pr-Pw)
Bµ (Logn [re/rw]+S)
20,000 stb/day
8.5" hole
Reservoir
Thickness
= 50ft
Distance from well
(feet)
1 ft
100 ft
1000 ft
Flow velocity
(ft/day)
1600
16
1.6
Pressure drop
(psi/ft)
900
5.6
0.6
100
1000
1 10
Reservoir Pressure
pressure
7000psia
Radius
Radius (ft)
7000
1300psi
6000
5000
Pressure 4000
(psia)
Bottomhole flowing
pressure 2500psia
3000
2000
1000
0
1300psi
1300psi
600psi pressure drop in 8 inches
Notice the huge pressure drop in the last eight inches
around the wellbore. You can imagine how badly the
well productivity would be affected if this pressure
drop was even greater due to formation damage
As an illustration; if this well were damaged and had a
skin of +2, this 600psi would become 1200psi. Thus
to achieve 20,000 stb/d, the well would have to be
drawn down to a further 1120 psi. The bottom hole
flowing pressure would have to be 1380psi. This may
not be possible in reality. Also, this may bring the
bottom hole pressure below the bubble point, at which
point gas comes out of the oil and further hinders
production and lowers productivity.
More realistically you would continue to produce at the
same drawdown (4500 psi) but you would only
produce 16000 bopd.
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O V E RVIEW OF WELL PRODUCTION
The previous section spoke of the Inflow Performance Relationship.
To understand the term skin we need to define the IPR and see where the
relationship to skin lies.
The inflow performance for an oil well is derived from analysing radial flow:
Q=
0.00708 kh(Pr - Pw)
Bµ(Logn{re/rw} + S )
where:
Q
k
h
Pr
Pw
B
=
=
=
=
=
=
µ
re
rw
S
=
=
=
=
flowrate in stock tank barrels/day (stb/d)
permeability in mD (millDarcy, 1000’th of a Darcy)
vertical formation thickness in ft
reservoir pressure at boundary in psia
bottom hole flowing pressure in psia
formation volume factor in reservoir barrels/stock tank barrel
(rb/stb)
viscosity in centipoise (cP)
drainage radius of reservoir in feet
wellbore radius in feet
Skin – a dimensionless number
Shaded items are fixed values for a particular reservoir
The constant 0.00708 is a conversion for the oilfield units used here.
This equation is known as the steady state radial flow equation for oil, where the
reservoir pressure is held constant, as would be the case in a waterflood. This
equation will give us the flowrate for an ideal vertical well, fully completed
(open-hole) with no formation damage (if S=0). There are similar equations for
pseudo-steady state flow and for gas wells.
The 'skin' of a well can only be calculated from analysis of a well test. It cannot
be physically measured. Good data on how skin changes over time may lead to
a timely discovery of a developing formation damage problem.
c) Skin
The skin was ‘discovered’ in the early days of well testing. An extra pressure
drop was observed close to the well in addition to that expected from ideal radial
flow. Since this pressure drop will vary with the flowrate and the viscosity of the
fluids, it is useful to define this in terms of a dimensionless skin .
S=
0.00708 kh ∆P skin
QµB
A positive skin means that the pressure drop in the formation close to the
wellbore is greater (and the productivity therefore lower) than an ‘undamaged’
well having zero skin. A negative skin factor means that productivity is higher
than the zero skin case.
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WELL PRODUCTIVITY AWARENESS SCHOOL
The skin can be a mechanical skin due to formation damage, or a skin due to
the completion geometry (including the effects of 'partial completion' well
orientation, perforations etc. See the Completions Section).
There can also be a ‘non-Darcy’ skin, for example skin in a high rate gas well
due to turbulence causing an extra (frictional) pressure drop.
For example:
Skin
0
+2
+4
+8
+24
+100
+1000
-1
-3
-4
-6
Rate (bpd)
10,000
8000
6667
5,000
2,500
740
80
11,400
16,000
20,000
40,000
'(ideal)'
no damage
increasing damage
increasing stimulation
Note that skin can be positive to infinity, but negative to about -6, possibly -7.
The theoretical minimum is -8.
The diagram below illustrates ‘skin’ around a wellbore. Because the reservoir
pressure is required to ‘push’ the hydrocarbons through this extra barrier, less
energy is available to get the fluid to surface, so for a given drawdown on the
well, less hydrocarbons will make it to surface.
SKIN: Formation Damage
is commonly around
eighteen inches from the
well - although it is
dangerous to generalise.
It can go several feet into
the reservoir.
rs
rw
undamaged
rw = wellbore radius
rs = radius of damage
p = pressure
P wf = wellbore flowing pressure
Actual pressure
Pressure when no
skin present
∆pskin = Additional pressure
drop due to skin effect
damaged
Skin region
P wf
distance from centre of well
PRESSURE DROP DUE TO SKIN
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O V E RVIEW OF WELL PRODUCTION
In real life, an additional pressure drop around the wellbore may not simply be
overcome by applying more drawdown, since reservoir or regulatory constraints
may prevent this or indeed the tubing lift curve may make this untenable.
d) Flow Efficiency
Although the skin is a useful mathematical concept, it does not give a good feel
for the effect of well damage on flowrates. The flow efficiency is a more useful
quantity:
Flow Efficiency =
Flowrate with actual skin
Flowrate with zero skin
=
Logn(r e/rw)
Logn(r e/rw) + S
=
8
(to a good approximation)
8+S
The flowrates, corresponding to actual and zero skins, must be measured at the
same drawdown.
The figure of 8 is derived from the expression Logn(re/rw), which can only
reach a maximum figure of 7 or 8. For instance, an 81/2” hole with a drainage
radius of 1000 ft gives an Logn(re/rw) of 7.94. This also explains why a
negative skin cannot exceed -8.
e) Productivity Index
From the slope of the IPR, the ‘Productivity Index’ (PI) can be calculated - it is a
measure of the oil flow rate (bpd) that will be obtained for every psi of
drawdown: for oil, measured as stock tank barrels of oil per day per psi of
drawdown (stb/d/psi). A stock tank barrel is a surface barrel as opposed to a
reservoir barrel. Oil will ‘shrink’ as it comes to the surface.
In a good reservoir the
drawdown leads to a far
higher production rate ‘q’.
Its productivity is greater,
stated in bbls of oil per day
per psi of drawdown
PRODUCTIVITY INDEX
P
w
1000
800
Large Productivity index
(Expressed as stb/day/psi for oil)
This well will flow at 5100 bopd
with a drawdown of 475 psi
PI = 10.74 b/d/psi
600
400
∆p = the drawdown
the well is subject to
the difference
between the
reservoir pressure
and the bottom hole
flowing pressure
200
PRODUCTIVITY INDEX
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Small Productivity Index
This well will flow at
1100 bopd with a
drawdown of 475 psi
PI = 2.32 b/d/psi
1000
2000
3000
4000
5000
6000
Flow Rate, bpd
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WELL PRODUCTIVITY AWARENESS SCHOOL
PROCESS
TYPE
Fines Migration
FLUID-ROCK
INTERACTIONS
RELATIVE
PERMEABILITY
REDUCTION
PHYSICAL PORE
SIZE REDUCTION
Wettability change due
to surfactant adsorption
Clay Swelling
Solids Invasion
Adsorption/precipitation
of large molecules
(e.g. polymers)
FLUID-FLUID
INTERACTIONS
Scale Formation
Fluid saturation change
Emulsion Formation
and fluid block
Sludge Formation
PRESSURE/
TEMPERATURE
CHANGE
MECHANICAL
PROCESSES
Scale Formation
Gas breakout
Wax Formation
Condensate banking
Asphaltene Formation
Water coning
Stress-induced
permeability change
Perforation plugging
FORMATION DAMAGE CLASSIFICATION BY PROCESS
Tubing
Gravel pack/
perforations
Formation
Scales
Organic deposits
Bacteria
Silts and clays
Emulsion
Water block
Wettability change
TYPES OF DAMAGE AND WHERE THEY CAN OCCUR
30
Schlumberger Oilfield Review
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O V E RVIEW OF WELL PRODUCTION
PI =
Q
(Pr - Pw)
In the radial flow equation it is possible to influence:
1.
2.
3.
4.
5.
the reservoir pressure (e.g. by water injection).
the bottom hole flowing pressure.
the drainage radius (i.e. well spacing)
the wellbore radius
the skin factor
f) What is the optimum Skin Factor?
No skin factor is ‘optimum’. The table below shows some typical Skin Factors
Situation
Typical Skin Factor
Badly damaged or partially completed well
+500
Damaged well
+2
to
+20
Good initial completion – unstimulated
+2
Lightly acidised
0
to
-2
Typical deviated well
-0.5
to
Natural fractures or small propped frac
-3
-3
+20
to
to
-1
to
-5
Types of Formation Damage
Within the definition of Formation Damage there are many mechanisms. These
can be divided into two groups by the way in which the permeability is reduced:
1. Physical reduction in pore/pore throat size.
a.
b.
c.
d.
e.
f.
g.
h.
i.
j.
k.
l.
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Drilling mud solids invasion into the formation
Drilling mud filtrate invasion into the formation
Cement filtrate invasion (not deep/not serious if perforations good)
Completion/workover solids invasion into the formation
Completion/workover fluid invasion into the formation
Perforation damaged zone
Plugging of formation with native clays
Asphaltene or paraffin precipitation in formation/perforations
Scale precipitation in the formation/perforations
Creation or injection of emulsion in/into the formation
Growth or injection of bacteria
Compaction of reservoir with production
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WELL PRODUCTIVITY AWARENESS SCHOOL
2. Relative permeability reduction – reduction in the permeability to
hydrocarbons in the presence of other pore-filling fluids.
a.
b.
c.
d.
e.
f.
Water coning
Condensate banking
Wettability change
Emulsion formation
Fluid saturation change and fluid blocking
Relative permeability changes
If a well is damaged, it is not just a matter of ‘sucking it harder’ (increasing the
drawdown) to achieve the required flowrates, because other factors may prevent
this. In some fields, for instance, if the bottom hole flowing pressure is reduced
too far the pressure drops below the ‘bubble point’ of the oil, and gas breaks out,
causing production problems and a lowering of the efficiency of the well. In
some fields there will simply not be enough pressure to overcome formation
damage, and artificial lift may become necessary. In some countries there is a
government limit to the amount of drawdown to which a well may be subjected.
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O V E RVIEW OF WELL PRODUCTION
INVASION OR STIMULATION IN NEAR-WELLBORE REGION
•
What happens if fluid invasion from the wellbore damages the permeability of
the formation (top graph)?
•
What happens if fluids, say acid, cause an increase in permeability in the near
wellbore region (bottom graph)?
EFFECT OF ‘DAMAGE’ ON WELL PRODUCTIVITY
Permeability
reduction
1.0
20%
0.9
40%
0.8
60%
0.7
0.6
The well is
producing at
50% of its
undamaged
capacity.
0.5
0.4
0.0
0.5
80%
1.0
1.5
2.0
2.5
Depth of altered zone (ft)
EFFECT OF STIMULATION ON AN UNDAMAGED WELL
1.3
Permeability
increase
The well is
producing 10%
more than in its
unstimulated
state.
1.2
1.1
100%
80%
60%
40%
20%
0%
1.0
0.9
0.8
0.0
0.5
1.0
1.5
2.0
2.5
Depth of altered zone (ft)
NOTE that in both the above graphs the damage or stimulation effect changes
noticeably over the interval from zero to approximately 1.5 ft of invasion, after that
the productivity ratio is little affected by further invasion.
NOTE also that 'damage' has a far greater detrimental effect on productivity than
'stimulation' has a benefit.
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33
WELL PRODUCTIVITY AWARENESS SCHOOL
UNDAMAGED WELL
Production Rate 8910 stb/day Skin = 0
Open Hole
No damage
Fully Completed
Vertical
WASP-1: Our Typical Well, with rates
calculated using the radial
flow equation for oil
SAME WELL WITH SKIN
Production Rate 7130 stb/day Skin = +2
Open Hole
Fully Completed
Vertical
SAME WELL WITH GREATER SKIN
Production Rate 2850 stb/day Skin = +17
Open Hole
Fully Completed
Vertical
In the above two examples we observe a skin of +2 and +17 respectively. At this
stage we do not know what has caused the skin. It is necessary to investigate how
the wells were drilled/completed/produced to investigate why there is this higher
than expected pressure drop in the near-wellbore region, as compared with the
ideal, open hole, fully completed, undamaged vertical well above.
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O V E RVIEW OF WELL PRODUCTION
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WELL PRODUCTIVITY AWARENESS SCHOOL
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DRILLING THE RESER V O I R
Drilling the Reservoir
Drilling Fluids
39
Types of Drilling Fluid
Filter Cake
Near Wellbore Permeability Reduction
39
40
42
a. Solids Invasion
b. Filtrate Invasion
42
43
Depth of Invaded Zone
48
a.
b.
c.
d.
e.
f.
g.
48
49
49
49
50
51
Mud Formulation
Open Hole Time
Open Hole Size
Overbalance
Invasion Profile
Calculation of Depth
Calculation of Depth of Invasion
vs Damage vs Skin
Depth of the Damaged Zone
Drilling Fluid Maintenance
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39
52
52
53
Fractures
55
Drilling Underbalanced
57
Coring
60
MODULE SUMMARY
63
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WELL PRODUCTIVITY AWARENESS SCHOOL
Primary requirements of a drilling mud
To maintain
borehole stability
To minimise loss of fluid
to the formation
To suspend solids
under static conditions
To remove drilled
cuttings from the hole
To control
formation pressure
To lubricate the drill string
To keep the bit cool
Drilling Mud Classification
Drilling
Muds
Oil based
muds
All Oil
Muds
Invert Oil
Emulsion Muds
Low Toxicity Synthetic OilOil
Based Muds
38
Water based
Muds
Diesel
OIl
Polymer
Muds
Clay
Inhibiting
Glycol
Muds
Clay
Muds
Non
Damaging
Dispersed
Non
dispersed
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DRILLING THE RESER V O I R
Drilling the Reservoir
At the end of this module you should be aware of:
•
•
•
•
•
•
Why formation damage can occur when drilling the reservoir
The types of formation damage caused by various drilling fluids
How to select a drilling fluid for a reservoir section
The importance of natural fractures in reservoir formations
The impact of mud damage on well productivity
The maximum skin that invasion of mud filtrate can cause
Drilling Fluids
The potential for damaging the reservoir has started!
As soon as the bit hits the reservoir, we can start to damage productivity! Before
reaching the reservoir, the drilling team has only been worried about the
suitability of the mud to drill the hole at an optimum speed, with an acceptable
degree of safety, whilst providing an in-gauge hole suitable for wireline logging
and a good cement job. Now that the reservoir is about to be entered,
formation damage also needs to be considered
. There must be a change
from a $/ft mentality to a well quality mentality.
A 'reservoir drilling' meeting should be held on the rig to clarify objectives,
likely problems and possible solutions before drilling into the reservoir .
Types of Drilling Fluid
The type of drilling fluid used in a well depends on the well type. The expected
lithology, well trajectory, bottom hole temperature and pressure all impact on
fluid selection. Legislation nowadays also plays a part in fluid selection as oilbased muds are effectively banned in some areas.
The many types of drilling fluids can be split into two broad categories:
1. Water based mud
Covers a large number of fluids based on fresh water, sea water or
brines; viscosified with bentonite or polymers. These systems can be
‘dispersed’ or ‘non-dispersed’, designed for shale inhibition, formulated
for use at high temperatures and other specific requirements.
Water based muds are constantly being developed to try to match the
superior clay inhibition and lubricity properties of oil-based muds. The
development of glycol and silicate muds is for this reason.
Dispersants such as lignosulphonates also disperse formation clays and
thereby mobilise fines. Avoid the use of dispersants if possible.
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39
WELL PRODUCTIVITY AWARENESS SCHOOL
2. Oil based mud (OBM)
These do not have so many variations. They do not affect clays by
salinity change, but surfactants in the mud can induce fines migration
and/or relative permeability problems. Beware of using excess
surfactants for this reason.
Synthetic oil based muds have been developed to obtain the properties of OBM
without the environmental drawbacks. These muds have only been partially
successful since they themselves can pollute to a certain extent.
What are the main functions of a drilling fluid?
a) Cuttings transport
b) Control of subsurface pressures
c) Maintenance of hole stability
d) Cooling and lubrication of the bit
e) To minimise invasion of fluids into permeable formations
In terms of well productivity we are primarily interested in ‘e’: the invasion of
fluids into the formation. Items ‘a’ and ‘c’ are of some importance to well
productivity since poor hole conditions could lead to a poor cement job with
future consequences on the production from the well (see Section entitled
“Completion Practices”).
Drilling mud is a necessary evil: many reservoirs are susceptible to formation damage
from the invasion of mud filtrate (or the chemical additives carried along with the
filtrate into the near wellbore region). Why is the permeability reduced? Read on.
Note : In this section, the concept of ‘Underbalanced Drilling’ is introduced to
avoid the use of mud with an overbalance, and therefore prevent the invasion of
fluids into the formation.
Filter Cake
When a well is drilled overbalanced (the common practice), the hydrostatic
pressure of the mud is greater than the pore pressure - to ensure adequate well
control. Hence there is a driving force for mud to enter the formation.
Fluid loss from the wellbore occurs in two phases. When a formation is first
exposed to drilling mud there is a high rate of fluid loss (known as the ‘spurt
loss’ ) until a filter cake is formed. Once the filter cake is formed two types of
filtration can occur: static or dynamic filtration.
Static filtration is where the mud in the well is not being circulated; for
example, when the pipe is out of the hole during logging. Mud solids
build up against the formation until they form an impermeable barrier.
The filter cake also compacts with time and becomes less permeable.
The invasion of filtrate during static filtration is very small.
Dynamic filtration , which accounts for most of the fluid lost, is where
the mud is being circulated and the surface of the filter cake is
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DRILLING THE RESER V O I R
constantly being destroyed and renewed (pipe rotation/reciprocation
would increase the erosion of the filter cake). An equilibrium condition
leads to a constant rate of filtration (qcrit); that is at a steady mud
circulation rate there will be a steady rate of filtrate invasion.
Hydrostatic Pressure
(P2 )
P2 > P1
External filter cake
D
R
I
L
L
S
T
R
I
N
G
Pore pressure
(P1)
(less than P2)
Formation
sand grain
Hydrostatic pressure
(P2)
Internal filter cake
FILTER CAKE
As the mud is circulated past the borehole wall
it partially destroys the mud cake. More filtrate
enters the formation as more cake is
temporarily built. This leads to a constant
dynamic fluid loss.
A 'rough' BHA with many stabilisers and
Outside Diameter changes can also cause
destruction of filter cake leading to greater
dynamic filtration.
LIMIT THE DESTRUCTION OF THE FILTER CAKE
• Check the hydraulics; maybe alter them to be less aggressive
• Check the Bottom Hole Assembly (BHA) used for drilling the reservoir;
the more stabilisers the more the destruction of the filter-cake.
• Consider changing the BHA just prior to drilling the reservoir, and
drill the reservoir in one run without making a bit change.
As a well is drilled, the shearing of the mud declines in steps, resulting in
progressively thicker cake and lower values of qcrit. The formation is exposed to
highly turbulent flow caused by jetting near the bit, then rapid flow opposite the
drill collars, and finally laminar flow opposite the drillpipe.
However, wellbores host a constantly changing environment. Under some
conditions wall shear stress increases – for example following an increase in the
pump rate or a change in mud properties. Experiments show that laminar flow of
mud containing solids – such as barite particles, sand grains, or drilled rock chips
– or turbulent flow of any mud is sufficient to erode the mud cake until a new
equilibrium is established with a higher qcrit; [the more solids there are in the mud,
and the faster you circulate leads to more (potentially damaging) filtrate invasion].
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41
WELL PRODUCTIVITY AWARENESS SCHOOL
10
Spurt loss
at bit face
10-1
Loss opposite
stabilizers
10-3
Loss near bit
(turbulent flow)
Loss opposite drillpipe
while circulating
10-5
Static filtration
after pulling
out of hole
10-7
30 sec
6 min
1 hr
1 day
~5 days
41 days
Time
History of filtrate loss rate into a permeable zone with a pie chart showing
total invasion volume lost during drilling. Loss declines with time because
shearing action at a given depth declines as the bit goes deeper. Most
fluid loss (largest pie slice) takes place during dynamic filtration, when
drillpipe is opposite the zone.
STATIC FILTRATION VS DYNAMIC FILTRATION
Schlumberger Oilfield Review
Near Wellbore Permeability Reduction
a) Solids Invasion
Drilling fluids have a significant solids content (10 – 20% v/v) which cover a
broad particle size distribution. The whole mud cannot usually invade into the
formation as many of the particles are larger than the pore throat size in the rock
matrix. Consequently a ‘filter cake’ is deposited on the surface of the rock. Even
particles with a diameter of 1/3 of the average pore throat size can bridge
externally. However, particles sized between 1/3 and 1/7 of the average pore
throat size can enter the pore network and cause internal blocking.
A Particle that is greater
than 1/3 the size of the pore
throat will plug. It will stop at
the entrance. They form a
filter cake. Should be
produced back.
FLUID
HYDROSTATIC
PRESSURE
A particle that is between 1/3
and 1/7 of the size the pore
throat will tend to BRIDGE.
They will stop somewhere
close to the wellbore. They
are not easy to remove.
They may have to be treated
with chemicals.
A particle that is less than
1/7 of the size of the pore
throat will pass through
(and back, hopefully)
without plugging
Formation
Sand Grain
PORE THROAT
Formation
Sand Grain
PARTICLE SIZE VS. PORE THROAT PLUGGING
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DRILLING THE RESER V O I R
Solids plugging can dramatically reduce permeability, but due to the rapid
entrapment of the solids and the build up of an external filter cake only a small
amount of solids invasion occurs. Consequently damage from solids is usually
very shallow (less than 2 inches) and is not normally important in perforated
completions; but in non-perforated completions (see Section entitled “Completion
Types”), solids damage can be very important.
Hydrostatic
Pressure
0 sec
2 sec
4 sec
6 sec
8 sec
63 sec
reservoir of mud
(concentrated clay particles)
invaded core (brown denotes invasion
of clay particles from the mud)
Core
core sample
Spurt invasion in a very high permeability limestone (top) revealed
in a series of time-lapse nuclear magnetic resonance scans at
2-second intervals. Color denotes water relaxation time and is
interpreted to indicate concentration of clay particles: blue is
highest concentration, brown to white decreasing concentration.
The blue rectangle is a mud reservoir, situated at the top of the
sample, indicated by an outlined rectangle. The scans show that
clay particles invade the rock within seconds, and after 8 seconds
little further change is observed.
Simulations of spurt invasion (bottom) show pore bridging by mud
particles (red) very close to the rock service. A few particles
penetrate much further prior to bridging. Once the internal cake
is formed, its composition is unlikely to change even if the mud
solids composition is changed, for instance by adding barite.
25%
41%
50%
Schlumberger Oilfield Review
Porosity
'SPURT' INVASION OF SOLIDS
Illustrated as nuclear magnetic resonance scans
SEM studies have shown that plugging of just 15-20% of the pores and pore
throats can cause significant damage. The solids will preferentially fill the most
porous and permeable part of the formation first.
Note that bentonite, a common constituent of drilling mud, can continue to
hydrate for more than 24 hrs. If this goes on inside the rock matrix it may well
block the pore space; therefore pre-hydration is always a good idea.
b) Filtrate Invasion
Once the filter cake has formed, it filters the mud so that only filtrate invades the
formation – thus begins the filtration phase.
Invasion , the process by which wellbore fluids leak off into permeable
formations, is a necessary evil. To the reservoir engineer/petrophysicist, it
impedes accurate formation measurements. To the drilling engineer, the filter
Revision 2: 2001
43
WELL PRODUCTIVITY AWARENESS SCHOOL
cake may assist in the maintenance of wellbore stability; but to all of us interested
in well productivity the solids and the filtrate invasion represent potential
formation damage.
Shale particle
Silt grain
Pore-lining clay
Quartz grain
Authigenic
clay
Core
Formation
water bank
Mud filtrate
bank
Undisturbed
formation
Wellbore
Invasion
Salinity front
Water saturation,
%
Saturation front
0
Oil
100
Water volume
fraction, %
0
Filtrate
Formation water
100
Saturation/salinity fronts and fluid banks visualized as water-base filtrate invades water-wet,
hydrocarbon-bearing formation. The microscopic schematics (top) illustrate the distribution
of fluids in various types of pore geometries. Oil is green, formation water is blue and filtrate
is orange. Schlumberger Oilfield Review
FILTRATE INVASION
Pictorial illustration of the invasion process
In most reservoirs, mud filtrate is the main portion of the mud which invades to a
significant distance. To cause damage, mud filtrate must adversely interact with
either the reservoir fluids or the reservoir rock. In some cases this damage is
‘temporary’. Such damage may disappear when the filtrate is produced back with
the early hydrocarbons; too often this is not the case.
The filtrate causes damage by physical blocking of pores and pore throats or by
changing relative permeability, for example:
a) Swelling and Dispersion of Clays in the Formation
Formation clays can swell when they are in contact with incompatible invading
fluids, especially fresh water. This reduces the pore throat size and the
permeability. Clay swelling is irreversible – they cannot be shrunk back!
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DRILLING THE RESER V O I R
Fresh water or
low salinity
solution will
invade between
the layers of the
clay and cause
them to swell.
Layer spacing
Before = 5 microns
After = 50 microns
Clay will swell
SCHEMATIC ILLUSTRATION OF SWELLING CLAYS
(Note - microscopic scale)
As mentioned in the Rock Type Section, smectite clays are more prone to
swelling than others. To reduce the swelling problems, use more saline muds,
salts such as potassium chloride or encapsulating polymers.
Potassium will cause clays/shales
to swell the least.
100
Na+
75
K+
Ca2+
In low salinity sodium brine a clay/shale will
swell - the layer spacing will increase. The
formation may be damaged if the clays now
block the pore throats
50
25
0
0
10
20
30
40
50
Layer Spacing, 10-10 metres
Montmorillonite is a smectite clay and very prone to swelling.
CLAY SWELLING
Montmorillonite - Expansion in Low Salinity Brine
Chemically induced clay migration may occur if the invading fluid causes dispersion
of formation clays. The movement of the clays may block pore thr
oats. For
most clays, dispersion only occurs when the salinity of the invading fluid is below a
critical concentration (that of the native clay-wetting formation water), or chemical
dispersants such as lignosulphonate are present in the filtrate. Siliceous fines can
also be migrated by the invading fluids; the presence of dispersants or surfa c t a n t s
i n c reases the likelihood of fines being liberated
. If you have these in the mud,
experiment in the laboratory to find the minimum concentration necessary.
Note that the clays within a sandstone may not swell enough to cause drilling
problems (e.g. tight hole, sloughing), but unbeknown to the driller their growth
may be seriously impairing future productivity. Thus the mud engineer and all
other concerned parties should ensure that an inhibited fluid is used to drill
through any reservoir that may have swelling clays, even if it is not flanked by
problematical shales.
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45
WELL PRODUCTIVITY AWARENESS SCHOOL
Single Phase Flow (water)
(Low Rate)
(High Rate)
Flow
SAND
Flow
Pore Throat
Plugging
Fines
Fines
If fines or clay particles are
mobilised they stand a
better chance of flowing out
of the formation without
bridging if the well is
brought on stream slowly.
Flow
Oil flow after Low Rate Cleanup
Oil Flow
Immobilized
Fines contained in
water permeability
around sand grains
Flow
Oil Flow
Sand Grain
Interstitial Water
FINES OR CLAY PLUGGING
Flow of Water Wet Fines (after Kreuger)
If clays and/or fines are mobilised they may be produced out with the
hydrocarbons. If the well is brought on stream at a controlled slow rate, there is
less likelihood of the debris plugging the pore throats.
Some muds react adversely with cement and viscosify alarmingly. This may be
happening within the formation due to a reaction with calcium. Bearing in mind
the 'reverse funnel' effect: what goes in may not come out. Check to see if your
mud filtrate reacts with calcium (in this formation?) to cause a viscous blocking
effect.
Return permeability tests
are the best way to see if a mud filtrate will damage
a formation. The permeability of a preserved core from the reservoir is
measured, prior to a sample of the mud filtrate being forced through the core
under pressure. The core is then flushed with hydrocarbons to simulate
production and the return permeability measured. This is a very important
measure of checking the damage potential of your mud. It could save you
millions of dollars in a field development. Do several tests with several cores.
b) Scale Precipitation
If incompatible formation water and mud filtrate are mixed, scale can precipitate
– this can restrict or block pores. A knowledge of the chemistry of the formation
water and the drilling fluid will assist in the prevention or identification of scale.
The most common scales are insoluble sulphates and carbonates; namely calcium
and barium salts. Sea water has a high sulphate content and should not be
used in reservoirs where scale precipitation could be a problem.
In a
formation containing barium, even tiny amounts of seawater can cause
irreversible damage due to barium sulphate precipitation.
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DRILLING THE RESER V O I R
Na+
Insoluble salts will plug
the formation. If you
inadvertently mix a mud
chemical with a
formation chemical that
results in a red cross or
a brown tick here, you
will be damaging the
formation.
K+
Barium is frequently
found in formation
waters.
Ba2+
Mg2+
Ca2+
OH -
Cl -
HCO3-
CO32-
SO 42-
✓
✓
✗
✓
✓
✓
✓
✓
✓
✓
✓
✓
✓
✓
✓
✓
✓
✗
✗
✗
✓
✓
✓
✓
✗
✓ Soluble
✓ Slightly soluble
Sulphate is
found in
seawater.
Use seawater
indiscriminately
in the drilling
mud or the
completions
fluid and
insoluble barium
sulphate will
precipitate in
the formation
✗ Insoluble
SOLUBILITY OF COMMON INORGANIC SALTS
c) Fluid Saturation Changes
The invading fluid can change the original fluid saturation, and hence the
permeability to oil; at worst it can cause ‘fluid blocks’. Damage due to relative
permeability changes is often a temporary effect; however, the higher the
viscosity of the invading fluid the longer it will take for the initial permeability to
be recovered. In a long interval it may prove difficult to clean-up all of the
section and parts of the reservoir may never produce as the oil/gas will
preferentially channel through the cleaned-up zone only.
1.0
0.9
●
Relative
permeability to oil.
0.8
As the amount of fluid
invasion increases, so does
the water saturation. As the
water saturation increases
the relative permeability to
oil decreases, ie. the oil has
more difficulty in flowing out
of the formation. The
formation is ”damaged”.
0.7
kro
0.6
0.5
Connate water
saturation.
Formation water
inherent to this rock.
It wil never go below
27% in this particular
formation. Such
water may be found
bound to sand grains
for instance.
0.4
0.3
0.2
krw
●
0.1
●
●
0.0
0.0
0.1
0.2
0.3
0.4
●
●
● ●●
● ●
●
●●
0.5
0.6
●
●●
●●
●
Relative
permeability to
water.
● ●●●●
0.7
0.8
0.9
1.0
Residual oil saturation.
In this particular formation,
there will always be a
minimum of 23% oil, where
the rock is oil-bearing. The
mud filtrate cannot flush
away this oil.
Water saturation, fraction pore space
FORMATION DAMAGE DUE TO FLUID SATURATION CHANGE
Oil-Water Relative Permeability
The effective permeability to oil is reduced if the wettability of the rock surface is
changed from water-wet to oil-wet. The majority of reservoir rocks are originally
water-wet due to their sedimentary nature and the depositional environment in
which they were formed. Carbonate reservoirs can be oil-wet or both oil- and
water-wet (mixed wettability).
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47
WELL PRODUCTIVITY AWARENESS SCHOOL
Formation damage can therefore occur if the invading fluid can change the
wettability of the rock. Oil based muds contain surfactants in the mud filtrate,
which can cause wettability changes. Corrosion inhibitors in completion brines,
or in acid stimulation fluids; can also cause this problem. An oil-based mud in a
water-wet gas sand can cause problems with relative permeability changes;
therefore careful research should be done before using this combination.
d) Chemical Adsorption
Adsorption of polymers onto the rock matrix can also cause formation damage,
due to pore size reduction. This is most likely to happen in water based muds.
e) Emulsion Production
Mixing of formation water with the mud filtrate can create emulsions. These
emulsions are viscous and may significantly reduce permeability by pore
blocking. The formation of an emulsion generally requires high shear rates for
effective mixing; thus emulsions are not generally a problem with drilling muds
invading a formation.
Depth of the Invaded Zone
Several factors control the amount of filtrate lost to a formation:
Higher circulation rates = more invasion
Large + changing BHA = more invasion
2001
5
12
19
26
6
13
20
27
7
14
21
28
1
8
15
22
29
2
9
16
23
30
3
10
17
24
31
4
11
18
25
Borehole
dynamics
Overbalance
Open Hole Time
More time
– More invasion
Filter cake
permeability
Open hole size
Larger bit size gives
larger area to invade
Invasion profile: cylindrical not conical
FACTORS AFFECTING THE DEPTH OF THE INVADED ZONE
DO EVERYTHING YOU CAN TO LIMIT FILTRATE INVASION
IN THE RESERVOIR
a) Mud Formulation
The filtration rate must be controlled, both to minimise potential formation
damage and to minimise drilling problems such as tight hole and stuck pipe.
Fluid loss additives are used to produce thin, low permeability filter cakes. Filter
48
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DRILLING THE RESER V O I R
cake permeabilities are typically 100 to 100,000 times less than reservoir
permeability. The filter cake usually controls the rate of invasion, independently
of formation permeability.
Formation
Permeability
(mD)
100
10000
10
1000
1
100
0.1
10
0.01
1
0.001
0.1
0.0001
0.00001
0.000001
0.0001
0.01
1
Filter Cake Permeability
100
(mD)
Most filter cakes have
permeability in this
region. The invasion rate
is therefore fairly
independent of the
formation permeability.
INVASION RATE VERSUS FILTER CAKE PERMEABILITY
b) Open Hole Time
The amount of fluid lost will be greater if the filtration process occurs for a longer
time. The longer the mud is circulated in open hole the more fluid will invade.
Apart from the money saved on rig time, this is another argument for limiting
check trips and unnecessary circulating on bottom.
LIMIT OPEN HOLE TIME – RESERVOIR EXPOSURE
c) Open Hole Size
The rate of filtrate invasion also depends on the ‘filter area’ available. The larger
the hole size, the greater the rate of loss. Hole size should not be ignored –
check the caliper logs.
d) Overbalance
This is the driving force for the filtration process. However the filtration rate does
not increase linearly with overbalance. For water-based muds it is thought that
invasion rates are fairly independent of overbalance above 500 psi, due to
compression of the filter cake.
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49
WELL PRODUCTIVITY AWARENESS SCHOOL
In water-based muds there
is a very slight increase in
filtration rate with increased
overbalance.
OBM
1000 psi
0
0
∆p
Differential Pressure
Increasing
IMPACT OF OVERBALANCE ON INVASION RATE
e) Invasion Profile
The profile of invasion will be fairly uniform along the well. The invasion of
filtrate will fill up pore space, and the further from the well it goes, the more
pores there are to fill. Thus the invasion profile is generally cylindrical not
conical.
The shallow and deep reading wireline resistivity tools record the cylindrical
invaded zone after drilling has ceased.
The permeability of the rock does not normally affect the invasion profile
because invasion is controlled by the much lower permeability of the filter cake.
Solids Invasion
Filtrate Invasion
High Porosity
Medium Porosity
This diagram
assumes that each
of these sand layers
is the same
thickness, and that
the same volume of
fluid has invaded
each layer.
Low Porosity
INVASION PROFILE
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DRILLING THE RESER V O I R
f) Calculation of Invasion Depth
In non-fractured reservoirs a calculation can be made of the depth of invasion if
the volume of mud lost downhole whilst drilling the reservoir is known. The
volume lost is the filtrate that has invaded the formation.
Vol inv =
(1 − Sor )h( rs2 − rw2 )
Where,
Volinv
φ
Sor
h
rw
rs
=
=
=
=
=
=
Volume of invasion in cubic feet
Average formation porosity (fraction)
Residual Oil Saturation (fraction)
Height of formation in feet
Radius of wellbore in feet
Depth of invasion in feet (measured from centre of
wellbore)
Note: 1 bbl = 5.6148cuft.
The following table shows the volume of invasion (in barrels) per 100ft of
formation, for a range of porosities and invasion depths. The figures below do not
take into account the residual oil saturation.
Porosity
(%)
0.2
0.5
1
Depth of Invasion (feet)
2
5
10
20
50
2781
3708
4635
5562
17024
22699
28374
34049
Filtrate Loss Volume (bbls/100 ft of formation)
12
16
20
24
1.2
1.6
2.0
2.4
4.1
5.4
6.8
8.1
11.5
15.3
19.1
22.9
36.4
48.5
60.6
72.7
191.6
255.5
319.4
383.3
719.0
958.7
1198
1436
8.5 inch wellbore
Excluding losses to fractures, it is clear that an invasion depth of 50ft is
inconceivable – it would take more than 20,000 barrels of fluid to be lost
downhole every 100ft! In reality, less than 1000 barrels of mud is usually lost
throughout an interval (including surface losses). Hence, an upper limit of 5 feet
can be used for most practical purposes
BP studies estimated filtrate invasion to be between 12 and 24 inches.
In exceptional cases the invasion can go deeper than 5 ft.
If possible, try and calculate the fluid losses whilst drilling the reservoir (use the
mudloggers). Using the calculation you might be able to crudely estimate the
depth of invasion. By doing so, you will have a better idea of the impact of filtrate
invasion on well productivity and how deep the perforations must go to get past
the damage.
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WELL PRODUCTIVITY AWARENESS SCHOOL
g) Calculation of Depth of Invasion vs. Damage vs. Skin
The skin factor for damage caused by filtrate invasion in a vertical open hole well is
defined as:
where
S = (k/kd-1) Logn(rd/rw)
kd = permeability of damaged region
rd = radius of damaged region (measured from centre of wellbore)
rd
rw
kd =
permeability of
damaged
region
NEAR WELLBORE DAMAGE
This equation can be derived from the radial flow equation. Note that the
magnitude of the skin is dependent on:
1. the ratio of the undamaged to the damaged permeability, i.e. to how
damaging the mud is.
2. the depth (rd-rw) of damage, i.e. the ‘fluid loss’ of the mud.
To calculate the reasonable upper limit of damage due to filtrate invasion, imagine
3 ft of invasion. If this filtrate was 90% damaging (i.e. reducing a permeability of
100 mD to 10 mD) then the above formula would give a skin of +20. This
illustrates that the maximum possible skin from filtrate invasion in reality is
approximately +20. Any skins much higher than this must also have an element of
completion skin (see Section on “Completions”).
Depth of the Damaged Zone
The depth of the damaged zone is not necessarily the same as the depth of the
invaded zone. Firstly the invading fluid may be non-damaging; thus the log analysts
may witness a deeply invaded zone, yet formation impairment may be minimal.
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DRILLING THE RESER V O I R
Secondly, if the formation damage has been caused by incompatible water, the
damaged zone will be the same as the invaded zone, since the supply of
damaging fluid is constant. However if the damage is caused by a surfactant in a
mud, then the near wellbore formation will adsorb the surfactant and the deeper
invading fluid will be less-damaging.
Well A
Well B
Invaded Zone
Any formation damaged
caused by solids will not be the
same as the invasion depth
Damaged zone here is equal to
invaded zone since damage
was caused by incompatibility
of mud filtrate with formation
water
Damaged Zone
Solids Zone
Damaged zone is less than
Invaded zone here, since
damage is due to surfactant in
an oil based mud – which is
consumed and depletes
DEPTH OF THE DAMAGED ZONE
Drilling Fluid Design/Maintenance
The subject of mud maintenance is too large to be covered in these notes, given
the huge variety of mud types that exist. However some general comments can
be made for drilling fluids used for the reservoir interval:
• Consider whether the mud needs to be different across the reservoir as
compared with the sections above.
• Check both API fluid loss and HTHP fluid loss. Minimise through the reservoir.
• Keep solids content as low as practicably possible.
• Keep the mud simple – the less that is in there, the less that can damage. For
instance, if a chemical additive has been necessary higher up the hole, try to
remove it before reaching the reservoir.
• Be aware of the potential formation damage problems.
• Don't change the mud from the formula designed and tested to optimise return
permeability.
• Consider changing out the mud to drill the reservoir – this may be an
economically viable alternative given the financial implications of formation
damage and loss of productivity.
Remember to treat the reservoir differently from all that has been drilled above.
Switch from a $/ft mentality to a QUALITY mentality.
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WELL PRODUCTIVITY AWARENESS SCHOOL
RELATIVE MERITS AND DAMAGE POTENTIAL OF DRILLING FLUIDS
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DRILLING THE RESER V O I R
Fractures
Some reservoirs, notably carbonates, have a very low matrix permeability, and
production depends on flow through a network of microfractures and fractures.
The fractures are mostly less than 10 microns in width, but may be much wider.
Because of the uncertainty of fracture size, and because of the geometry involved,
bridging fractures is more difficult than bridging porous media. If the fractures are
not bridged, fine mud particles invade the fracture and filter internally against the
sides of the fracture until it is filled with mud cake. Such internal mud cakes are
not easily removed by backflow, and productivity is greatly impaired. Such
reservoirs must therefore be drilled with a fluid whose solids are degradable, or that
can be destroyed by acid (calcium carbonate) or low salinity fluids (sized salts).
A fractured formation is a good formation. It may be difficult to drill, but by the
same token it is easy to produce – provided that the fractures have not been
blocked by mud! Geologists go looking for fractures in field developments; the
extent of fracturing can make or break a field development. The fractures created
back in geological time may have been filled at a later date by geological fluids
depositing other rocks such as calcite, which would make fractures impermeable
and of little use to oil production. The illustration below shows how fractures
can occur naturally in geological time.
Fracturing in a folded bed
Cross fracture
Oblique
fractures
Longitudinal or
strike fracture
Whole mud losses downhole can only occur to naturally fractured or vuggy
formations (unless the drilling mud is too heavy or the Equivalent Circulating
Density [ECD] too high, and fractures are induced in the formation). Mud solids
or Lost Circulation Material (LCM) can penetrate into fractures to a much greater
depth than the perforations will reach giving very high skin factors.
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WELL PRODUCTIVITY AWARENESS SCHOOL
Beware of inducing factures
– Mud weight or ECD too high
Invasion/Damage will be deeper than perforations
can reach
– Use soluble LCM if possible
Try to identify fractures whilst drilling
– Mudloggers + drillers to monitor mud losses accurately
– (down to 1bbl or less)
– Keep detailed record
– (importance may only be evident at a later date)
- Drillstring vibrations
Design completion to suit fractures
FRACTURES
Production from fractures can dominate the productivity of a well, especially in
low permeability formations. It is therefore vital that any fractures are identified.
Some fractures are observed in wireline logs and cores; however a vital piece of
information can be the mud log; where the mud loggers should observe and
record even the slightest mud loss. The fractures usually become plugged and
may not be seen on wireline logs or initial testing.
Mud
Losses
1900
2000
The mudloggers
observed a two
barrel mud loss at
this depth.
Initial
DST
Post-Acid
DST
55
2
25
0
0
16
0
4
1
0
0
0
0
92
2100
Post acid test indicates that
natural fractures have been
cleaned up and dominant
production is from this level.
1
350 bpd
6640 bpd
IMPORTANCE OF PRODUCTION FROM CONDUCTIVE FRACTURES
Note that fractured zones of fields are difficult to predict and map; therefore any
help that the drillers can give to the geologists is most welcome.
If there are natural fractures in your well it is imperative that your perforation
design takes this into account, so that you connect the natural fractures to the
wellbore.
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DRILLING THE RESER V O I R
Drilling Underbalanced
If a well is drilled with a hydrostatic head that is less than formation pressure,
then mud solids, cuttings or fluid will not invade the formation, thus formation
damage is avoided.
The primary device that is needed is a rotating blowout preventer or a rotating
control head used also for air/foam drilling.
Rotating BOP specifications
Maximum static pressure
Maximum pressure while drilling
Optimum working pressure while drilling
Working pressure while stripping
Maximum rotating speed
Through bore without kelly packer insert
Side port outlet flange
BOP stack flange mount
2,000 psi
1,500 psi
1,000 psi
1,000 psi
100 rpm
11 in.
71/16 in., 5,000 psi API
11 or 135/8 in., 5,000 psi API
Kelly or drillpipe
Kelly or drillpipe
Seals
Bearing assembly
Quick change
packer assembly
Inner packer
Hydraulic fluid
Outer packer
Bearing
Mechanical seal
Stripper rubber
Mudflow
Tool joint
Mudflow
Tooljoint
ROTATING HEAD
SCHEMATIC
ROTATING BLOWOUT PREVENTER
SCHEMATIC
The practice of underbalanced drilling or ‘flow drilling’ allows wells to flow oil
and gas through the choke line at a controlled rate whilst drilling ahead. The
rotating BOP has been developed to handle up to 1500 psi of surface back
pressure whilst drilling with air, gas, nitrogen, foam, water or light fluids.
One of the problems with drilling with jointed drillpipe through a rotating head
or BOP, is the pressure limitation of the seal around the pipe.
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57
WELL PRODUCTIVITY AWARENESS SCHOOL
PRESSURE
RATINGS
Rotary rig/rotating head
Rotary rig/rotary BOP
Coiled Tubing Drilling
Continuous Duty
Pressure Rating (psi)
1000
1500
5000
A well is often brought under primary control – an overbalance is established –
when a bit is tripped. This leads to losses into the formation, which is not
protected by a filter cake. The overbalance during tripping is necessary for safety
and because it is time consuming and wears the sealing elements to strip an
external upset jointed drillstring.
Whilst under-balanced drilling is advantageous for the reservoir and other factors
detailed earlier, it does have the complication of not being suitable for 'heaving'
or 'sloughing' shales that need hydrostatic pressure to keep them in check.
Therefore if there are such formations above the reservoir they must be cased off
first before drilling underbalanced.
Underbalanced drilling is being used primarily in pressure depleted reservoirs
which have strong reservoir rocks with a minimal risk of wellbore collapse.
In Canada, the practice of underbalanced drilling is widespread; indeed reservoirs
are often drilled with the well flowing! The cash flow can pay for the well.
OPERATIONAL REQUIREMENTS
(PATENTS PENDING)
Flarestack
Gas
Liquids
Solids
3 Stage Separator
Sample
Catchers
Top Drive
System/
Power
Swivel
Oil Tanks
Nitrogen
Pumper
Water Tanks/
Kill Tank
R-BOP/
Double Ann
Choke
Manifold
System
Nitrogen
Pumper
Drilling Fluid
Tank
Rig Pumps
Cutting
Returns
Northland Production Testing Ltd.
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DRILLING THE RESER V O I R
Fluid Selection
• Clear fluids used; occasionally with polymers to assist hole cleaning.
• Underbalanced drilling without gas lift is possible with water down to
8.34 ppg and oil down to 6.95 ppg. Below this density requires drilling with
foam, mist or air unless the well has a high GOR.
• Clear fluids are preferred due to reduced wellbore damage if lost circulation
or imbibition does occur.
• If a well is flowing oil whilst drilling with a polymerised foamed fluid there is
a risk of emulsions forming.
• Directional measurements via MWD through the drilling fluid are possible
with water, oil or gas lift. If foam is used, the connection has to be wireline
(possible in coiled tubing).
• Reservoir pressure needs to be accurately known, to calculate underbalance,
taking into account cuttings loading, friction pressures etc.
Potential Difficulties
• Spontaneous Countercurrent Imbibition: capillary pressure may cause
movement of fluids from the wellbore into the formation despite the
underbalance. Possible damage.
• Hydrogen Sulphide (if present): if well is flowing, H2S comes to surface.
• Wellbore Stability: Not well understood. Rule of thumb states that if hole
porosity is greater than 30% the rock may not be stable enough to be drilled
underbalanced.
• An overbalanced fluid has to be put in place to log the well – unless run on
coiled tubing through pressure equipment.
Rewards
Alaskan examples:
Well
I
– offset well drilled overbalanced =
– underbalanced (CT) drilling =
Reference:
Revision 2: 2001
1200 bopd
4000 bopd
Well
II
1500
4600
Underbalanced Drilling With Coiled Tubing and Well
Productivity.
L.J. Leising and E.A. Rike, Dowell Schlumberger.
SPE 28870 .
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WELL PRODUCTIVITY AWARENESS SCHOOL
Coring
Coring can be time consuming and expensive – but it is very important. Cores
are not just in the domain of the geologist and the reservoir engineer; all parties
interested in well productivity should be interested in the core.
AIR CORING
Air Coring uses standard coring equipment with
specialised core bits and modified operating
techniques. The difference between air coring
and conventional coring is that the drilling fluid is
air, air mist, or foam rather than a liquid mud.
Coring and wellsite core handling should follow the best possible practices
because the value of all core analysis is limited by this initial operation.
The major problems encountered during coring, handling and preserving
reservoir rocks are:
1. designing a bottomhole coring assembly and drilling fluid programme to
minimise mud invasion and maximise drilling parameters
2. selecting a non-reactive core preservation material and method to prevent
fluid loss or the absorption of contaminants (e.g. wettability altering drilling
fluid components)
3. applying appropriate core handling and preservation methods based on rock
type, degree of consolidation, and fluid type
There is not one best method for handling and preserving cores. Core
preservation is an attempt to maintain core before analysis, in the same condition
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DRILLING THE RESER V O I R
that existed when it was removed from the core barrel. Rock types that require
special procedures for coring and wellsite preservation are:
•
•
•
•
•
•
•
unconsolidated rocks - both heavy and light oil
vuggy carbonates
evaporites
fractured rock
rocks rich in clay minerals
shale
low permeability rock (tight gas sand)
There are many ways to preserve core and all should be investigated to find the
most suitable. Freezing of cores is the most common and perhaps controversial
method of preserving cores; whatever its potential difficulties and problems it is
the only way of preserving and handling unconsolidated rock for core plugging.
Before a coring job, assemble a multi-disciplinary team
• drillers
• drilling engineers
• reservoir engineers
• geologists
• core analysts
• mud loggers/core catchers
Discuss all aspects of the job early on in the planning stage. Draw up detailed
procedures and have a step-by-step programme available on the rig.
The better your core - the better the core evaluation – the better the results – the
higher the future well productivity. Good cores are vital for return permeability
tests to help the choice of drilling fluid to find the one that is least damaging.
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WELL PRODUCTIVITY AWARENESS SCHOOL
WASP-1
Same Well with Filtrate Invasion
Same Well with Greater Depth of Invasion
Production Rate 8009 bopd Skin = +0.9
Production Rate 7665 bopd Skin = +1.3
Open Hole
40% Permeability Reduction
1 Foot of Invasion
Filter Cake Removed
Fully Completed
Vertical
Same Well but with Greater Damage
Same Well with Greater Damage to a Greater Depth
Production Rate 5320 bopd Skin = +5.4
Production Rate 4570 bopd Skin = +7.6
Open Hole
80% Permeability Reduction
1 Foot of Invasion
Filter Cake Removed
Fully Completed
Vertical
62
Open Hole
40% Permeability Reduction
2 Feet of Invasion
Filter Cake Removed
Fully Completed
Vertical
Open Hole
80% Permeability Reduction
2 Feet of Invasion
Filter Cake Removed
Fully Completed
Vertical
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DRILLING THE RESER V O I R
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WELL PRODUCTIVITY AWARENESS SCHOOL
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COMPLETIONS
Completions
History
66
Completion Types
67
Well Design
Multilateral Wells
Geosteering
Completion Design
67
71
76
77
a. Open Hole Completion
b. Uncemented Liner
c. Cased and Perforated
78
78
79
Completion Practices
80
Casing and Cement
Completion Fluids
81
83
a. Types
b. Importance of Cleaniness/Filtering
c. Displacement
84
84
87
Perforating
87
a.
b.
c.
d.
e.
f.
g.
h.
History of Perforating
Perforating Charges
Delivery Systems
Perforating Skin
Perforating Through Drilling Damage
Perforation Tunnel Length
Underbalanced Perforating
Overbalanced Perforating
Sand Control
a.
b.
c.
d.
Internal and External Gravel Packs
Sand Control Using Chemical Methods
Frac-Pack
Cleanliness
MODULE SUMMARY
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66
88
88
90
91
94
94
96
100
105
105
109
110
112
119
65
WELL PRODUCTIVITY AWARENESS SCHOOL
Completions
At the end of this module you should be aware of:
•
•
•
•
•
•
The main types of completions used
When zonal isolation is important and how it is achieved
Why special completion fluids are used
How wells are perforated
Typical skin factors associated with the main completion types
How high skins can result from mud damage combined with a
completion skin
In this module we will discuss 'the completion' as the overall design for
maximising the well productivity. We are not concerned here with the selection
of tubing, packers, tubing accessories and artificial lift methods.
Well Design: VERTICAL – DEVIATED – HORIZONTAL
Completion
UNCEMENTED
Barefoot
CASED AND CEMENTED
PERFORATED
Gravel Pack
Fracture
stimulation
Pre-packed screen
Uncemented Liner
Gravel-pack
Natural
PRODUCE THE WELL
COMPLETION TYPES
History
The first oil wells were drilled vertically and completed ‘barefoot’; that is without
casing. Completion methods were very crude. Early photographs of discoveries
in the USA show plumes of oil gushing from wells. When the initial surge of
‘black gold’ had died down or been suppressed, the 'completion' of the well
simply meant it was capped with a valve and the discovery put on production.
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COMPLETIONS
In those early days the science of reservoir engineering was in its infancy and
formation damage was not something that most of the ‘wildcatters’ knew about or
worried about.
As the business of oil well drilling progressed, more and more wells were
completed with a cemented string of casing, and the casing perforated to establish
communication with the formation. This was found to be beneficial to long term
production. Sand control problems led to the emergence of gravel packing and
sand consolidation treatments.
Tubing
Casing goes
back to the
surface
Casing
Liner
hanger
Liner does
not come
back to
surface
Shoe
Packer
Cap
rock
Oil Zone
Cement
sheath
Barefoot
Completion
Open hole
Screen Liner
Completion
Cemented liner
(perforated)
Completion
Cemented
Casing
Completion
COMPLETION PRACTICES
Deviated wells were drilled for a variety of reasons, but principally to develop
offshore fields from platforms. Although horizontal wells were first attempted in
Russia in the 1950’s, it is only in fairly recent times that there has been a major
move to drilling horizontal or high angle wells in some reservoirs. Many of these
horizontal or high angle wells have reverted to the ‘old’ methods of completing
wells barefoot or with uncemented liners, be they slotted or perforated. More
modern hardware, such as wire-wrapped screens, or pre-packed screens can also
be run.
Completion Types
Well Design
Leaving aside the necessity of a platform well to reach a certain distant part of the
reservoir, a well can be vertical, high-angle or horizontal as part of the
overall completion design.
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WELL PRODUCTIVITY AWARENESS SCHOOL
A vertical well is the easiest to drill, but a high angle or horizontal well may be
beneficial for productivity.
When there is no formation damage a high angle or horizontal well should have a
negative skin. However, if you do damage such a well during drilling or
completing then positive skins will result.
Vertical Well
cheapest
simple to operate
optimum design for
hydraulic fracturing
Reasons For Drilling Horizontal wells
To avoid water
trying to cone
ideal for homogenous
thick reservoir
to drain thin
reservoir
to drain oil rim
to minimise
drawdowns
minimise wells
required for field
development
fractured
reservoirs
To effectively drain
high permeability layer
(or thin reservoir).
Reasons For Drilling High Angle Wells
to more effectively
drain an anisotropic
reservoir
To effectively drain
a lensed reservoir.
to minimise wells
required for a field
development
WELL DESIGN
A horizontal well
is particularly suited to the following developments:
• Thin reservoirs, or thin oil columns, where the Kv/Kh (vertical/horizontal
permeability) ratio is not too low, and there are no significant barriers to
vertical permeability (e.g. shale streaks),
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COMPLETIONS
• Reservoirs prone to water coning or gas cusping,
• Reservoirs prone to sand production,
• Where reservoir quality varies laterally and a horizontal well gives a better
chance of finding ‘sweet spots’,
• In combination with extended reach drilling and geosteering, to drain different
reservoir blocks, or reservoirs, in one well,
• In fractured reservoirs, where a horizontal well gives a better chance of
intersecting fractures, and
• In combination with extended reach drilling, to develop fields in
environmentally sensitive areas, or from an offshore platform, where the
number and surface location of wells is severely restricted.
High angle wells (over 75 deg.) can be used for many of the same purposes as
horizontal wells, but additionally are suitable for :
• Thick reservoirs where the Kv/Kh (vertical/horizontal permeability) ratio is
low, and/or there are significant barriers to vertical permeability (e.g. shale
streaks),
• Lensed reservoirs, and
• Layered reservoirs.
Common sense, and field experience, show that horizontal wells generally
produce much more than vertical ones, due to the greater area of sand-face
exposed. Obviously the radial flow equation for vertical wells does not apply to
horizontal wells, so a different approach must be used to estimating the flow from
horizontal wells.
In a 1984 SPE paper, Giger, Reiss and Jourdan presented an analytical approach
to estimating the inflow performance of horizontal wells. Their ‘horizontal well
inflow performance’ algorithm was accompanied by an equation to allow the
‘Productivity Ratio’ of a horizontal well to be estimated. This, the ratio of the
productivity index of a horizontal well to that of an otherwise similar vertical one,
increases with the length of the horizontal section.
Giger et als basic algorithm incorporated a number of simplifying assumptions,
including :
•
•
•
•
•
Zero skin/formation damage,
Vertical and horizontal permeabilities the same,
A homogeneous and isotropic reservoir,
Uniform contributions from all parts of the perforated interval, and
A uniform draw-down across the completed interval.
Giger et al provided a modification to allow for differences between vertical and
horizontal permeability, and this allowed their approach to be used extensively
for analysing horizontal well productivities in the 1980's. However, for the wells
with much longer horizontal sections now common, often in situations where
none of the above assumptions would be reasonable, Giger et als approach is of
limited use.
With, according to one estimate, one in five new wells being drilled horizontal,
a good understanding of the inflow performance of horizontal wells is very
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69
WELL PRODUCTIVITY AWARENESS SCHOOL
HORIZONTAL WELL
The Vertical Well in the same reservoir
produced only 8910 bopd
Production Rate 14260 bopd Skin = -3
❏
❏
❏
❏
❏
❏
Open Hole
40% Permeability Reduction
2 Feet of Invasion
Filter Cake Removed
Fully Completed
2500 ft Horizontal Section
Note: Do not worry if you cannot understand all the
complicated equations. It is more important that you
understand the principle; that a horizontal well will
produce more than a vertical well, all other factors
being equal.
important, for example when deciding whether to develop a field with vertical or
horizontal wells. Though the analytical approach, pioneered by Giger et al, is of
limited use in predicting well productivities, it is still useful for sensitivity analysis
and ranking. Where there is sufficient reservoir data, and man-power and
budget, reservoir simulation on a computer, also applicable to analysis of multilateral well projects, is often used. Where a number of horizontal wells have
already been drilled in an area, the performance of these wells may provide a
good estimate of the productivity of the next one.
The effect of formation damage in horizontal completions has, in the past, been
commonly ignored, both because of the much higher productivity of horizontal
wells and because it is impossible to obtain a unique estimate of skin from a
horizontal well test. However, production logging is now often used together
with well tests to get some idea of which parts of a horizontal well bore are
contributing effectively and which not, and, hence, which parts of the formation
are damaged. BP companies now place increasing emphasis on the avoidance of
damage and sand-face/perforation clean up of horizontal well bores.
Productivity prediction remains very imprecise for any single horizontal well.
Recent examples include a field where 30% of the horizontal wells one area
performed no better than vertical wells and, also, one horizontal well where
water broke through after only one week, compared with a predicted two years.
However, with ‘productivity ratios’ typically in the range of 2 to 4 for conventional
reservoirs, up to 6 to 12 for fractured reservoirs, compared with ‘cost ratios’
typically in the range of 1.5 to 4, interest in horizontal wells, and in understanding
their performance, can only intensify.
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COMPLETIONS
PRODUCTIVITY INDICES RATIOS
HORIZONTAL AND VERTICAL COMPLETIONS
Completion Interval Length
(feet)
Productivity Ratio Horizontal/Vertical
(J h /J v )
100
200
400
800
1000
1.5
2.1
3.4
4.7
5.7
Reservoir radius (re)
= 933 feet
Formation thickness (h)= 50 feet
Drill hole radius (rw) = 0.33 feet
Homogeneous formation, Single phase flow
Multilateral Wells
a)
Summary
In a similar way to horizontal wells, multilateral wells increase well productivity
primarily by increasing the length of the reservoir section exposed in a well.
Other beneficial effects include the possibility of draining more than one
reservoir, or more than one block within a reservoir, from one well. A
‘multilateral’ well, is one with one or more laterals, that is one or more subsidiary
well-bores off the main well-bore. Laterals are usually horizontal or highly
deviated, and may be drilled as part of the initial drilling programme for a well, or
as a later deepening or work-over project.
Though the first multilateral well was drilled in California in the 1930’s, it is only
in the past few years that multilateral drilling and completion technology has
developed to the point where a range of sophisticated drilling, casing, cementing
and completion options are offered by service companies. Though under
development, no currently available system provides a pressure-tight seal,
independent of cement and of the completion, at the junction between the main
well bore and the lateral. Though recently available from service companies,
most multilateral completions installed to date do not permit selective re-entry,
through the completion, via coiled tubing to laterals. Without this selective reentry, attempts, for example, to circulate drilling mud out of a lateral are reduced
to ‘poke and hope’ with coiled tubing; something that is not always successful!
Selective re-entry permits a range of intervention techniques to be applied, again
using coiled tubing, so, for example, a lateral producing water can be plugged
off, to allow dry oil to be produced from a well that might otherwise have a high
water-cut and perhaps not flow at all without a pump.
The record for the number of laterals in one well is probably ten, drilled by the
Russians as long ago as 1953, with similar wells being drilled in the USA in the
late 1980’s. However, such older multilateral wells were usually completed openhole, with little or no possibility for re-entering the laterals. Though open-hole
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WELL PRODUCTIVITY AWARENESS SCHOOL
Conventional Wells
Multibore/Lateral Well
Well 1
Well 1
Well 2
Well 2
completions are still common, for example currently at Wytch Farm, wells with
cased and cemented laterals more usually have one or two laterals only, that is in
addition to the primary well bore. This may also be producing, or have been
plugged off through the reservoir if the laterals were drilled from an old wateredout well, for example as at FA 1-2, in the Forties field in the North Sea. This well
was re-entered by BP in 1996, and side-tracked out of a window milled in the
existing intermediate casing. Two laterals were then drilled to different parts of
the reservoir, and completed with cemented and perforated liners.
Though most of the emphasis has been on the technology, the economic
justification for multilateral wells lies in the additional production. Predicting
production from multilateral wells is complicated, especially as, when these are in
the same reservoir, production from one lateral will be reduced by production
from the other(s). As for horizontal wells, production is best predicted via
reservoir simulation, when data quality permits. Whereas a horizontal well
typically costs 40% more than a vertical well and produces three times as much
oil, a multilateral well might cost 60% more than a vertical well and produce five
times as much. Obviously, the deeper the well, the more cost-efficient is it to
drill the reservoir horizontally or multilaterally. Though readily available,
multilateral well technology is still on a steep learning curve, so comparative costs
will drop, especially for operators with limited multilateral experience.
Multilateral wells are already enabling the development of fields which would
otherwise be uneconomic, such as BPs Badami field in Alaska.
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COMPLETIONS
b)
Applications
Principal applications for multilateral wells include :
• Improving the drainage architecture in a single reservoir,
• Accessing discontinuous intervals/blocks in a single reservoir,
• Draining more than one reservoir in a well,
• Improving the efficiency of Enhanced Oil Recovery projects,
• In combination with extended reach drilling, to develop fields from an
offshore platform, or in environmentally sensitive areas, where the number
and surface location of wells is severely restricted, and
• As a means to re-use redundant wells, which have for example watered out,
but which are near to undrained reserves.
c)
Technology
The technology can be considered under three headings, Drilling, Completion
and Intervention/Workover.
The drilling technology is well developed, with systems offered by a number of
service companies. In new wells, special windows can be installed with the main
casing, to avoid having to mill windows. Special locator/orienting collars are
installed below the windows, to allow the windows to be correctly oriented,
using a survey tool, before the casing is cemented. A whipstock, run on drillpipe, is then set in the locator/orienting collar, across the window, to divert
drilling tools out through the window. Once a lateral has been has drilled
directionally, it may be left open, a slotted uncemented liner or sand control
screen installed, or a liner cemented in place. With cased laterals, the liner stub,
protruding into the main casing, must then be milled out, and the whipstock
milled out or retrieved. In old wells, and with some systems in new wells also,
pre-installed windows and locator/orienting collars are not used, and a special
packer incorporating a locator/orienting assembly must be set in the main casing,
after orientation with a survey tool, and a window milled, before the lateral can
be drilled. If desired, the whole procedure can then be repeated to drill further
laterals out of the same main casing.
Most multilateral wells have then been equipped with conventional completions,
with the packer, if used, above the upper lateral. However, this currently
provides no possibility for re-entering laterals through the completion, and only
very limited options even if the completion is pulled. Selective access to laterals,
via coiled tubing, would increase the value of multilateral wells, by making
possible selective stimulation, perforation, production logging, drilling deeper
with coiled tubing and plugging of water-producing intervals. The paucity of
intervention options may in the past have limited the spread of multilateral
technology in situations where expensive wells, incorporating cased and
cemented high angle or horizontal laterals, would be appropriate. Some two
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WELL PRODUCTIVITY AWARENESS SCHOOL
DRAINING A SINGLE RESERVOIR MORE EFFICIENTLY
UP-DIP AND DOWN-DIP LATERALS
Drilling multiple laterals in a single reservoir greatly increases
formation exposure and allows drainage over a larger area
compared to a single lateral. In fractured reservoirs, additional
laterals increase the probability of intercepting and draining
different fracture systems. The number and geometry of
laterals depends on the shape and characteristics of the
reservoir. In the above example from the North Sea, a triple
lateral well was drilled as a series of open hole sidetracks. The
first lateral was turned to the right, the second lateral was
sidetracked from the first lateral to the left, and the third or
‘main’ lateral was sidetracked from the second lateral and drilled
straight ahead. Initial figures indicated a productivity of 2 to 3
times that of a conventional horizontal well in the same field.
Odd-shaped leases or restrictions on surface locations can
make drilling multiple laterals a preferred option. In South
Texas, dual laterals drilled up-dip and down-dip are the most
economic and efficient way of draining some leases. The
vertical portion of the well is drilled to the top of the target, a
fractured chalk reservoir, and casing is set. The up-dip lateral
is drilled first at an angle above 90° to follow the formation dip.
Next, the down-dip lateral is started as an open hole sidetrack
and drilled to TD using the same bottom hole assembly used to
drill the up-dip lateral. Multiple laterals can also be drilled as
re-entries out of existing straight hole procedures, typically
through a window milled in casing. The window is oriented
halfway between the planned directions of the laterals.
THE LATERAL TIE-BACK SYSTEM
DRAINING MULTIPLE RESERVOIRS
The Lateral Tie-Back System was recently used in Canada to
complete a well drilled with three lateral branches extending
from a main wellbore. The main horizontal wellbore was drilled
with an 83/4" bit, and cased using a 7" slotted liner with three
LTBS casing window systems installed 300 m apart. The
windows were oriented in the same direction. The first lateral
"branch" was completed open hole, with a slotted enclosure
isolating the lateral. The second and third laterals were drilled
and completed with 3 1/2" slotted liners hung from the 7" liner.
Including the main wellbore, 2,850 m of reservoir was exposed.
The total time from drilling to completion was just over 11 days.
Multiple reservoirs can be produced using the same vertical
well with stacked laterals drilled into the different producing
horizons. Depending on completion requirements, the laterals
can be drilled in open hole as sidetracks, through windows
milled in casing, or through the LTBS windows. In the example
above, the laterals below the casing shoe are drilled first as a
series of open hole sidetracks using the same steerable
assembly. The top lateral is drilled first followed by
successively deeper laterals. If laterals higher in the well are
desired, a retrievable casing whipstock is set at the desired
KOP and a window milled. The lateral is then drilled before
resetting the whipstock at the next KOP. Up to five laterals in
three formations have been drilled in South Texas.
Sperry-Sun Drilling Services
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COMPLETIONS
dozen wells are now completed to allow such selective re-entry via the
completion. Of these, more than half use PCE’s Multi-Lateral Re-Entry (‘MLR’)
system, the first of which was installed for NAM, in the Netherlands, in 1996. This
system employs an oriented MLR nipple, set across the window before running
the completion. A through-tubing whipstock may then be set in the MLR nipple,
on coiled tubing, to deflect subsequent coiled tubing runs into the lateral.
Offshore Qatar, where a number of these systems have been installed in the Idd
El Shargi field, laterals have been selectively re-entered for acidising and
production logging, for example.
Most multilateral completions do not allow more than one tubing string to be
installed, making it necessary to commingle production from the different laterals.
Though this does not usually give rise to problems, it could lead to a well being
killed by high water production from one lateral only, and might not permit
production from intervals with different reservoir pressures. However, service
companies are now offering multi-string completion systems, which permit
segregated production from two laterals, with dual tubing strings to surface. The
first completion of this type was installed by Baker Hughes in the Bokor field,
offshore Malaysia in 1996, in a well with three laterals, each of which was
completed with a sand control screen. Dual tubing strings to surface permit the
segregated production of two laterals, with the option of adding production from
the third to one of the others, by manipulation of a sliding sleeve. This
completion also provides full hydraulic seals across the junctions where the
laterals meet the main well bore, as all junctions are straddled with packers.
Though workover options have been very limited in the past, MLR, and
competing technology from other suppliers, makes possible a wide variety of
through-tubing intervention options. When a rig workover is required, the MLR
nipple can be retrieved on drill-pipe and a whipstock run in the locator/orienting
collar, to allow access with drill-string into a lateral, thus providing a full range of
workover options.
Coiled tubing drilling, together with a number of other recently developed
technologies, including under-balanced drilling, Logging While Drilling (‘LWD’)
and geosteering are being combined to widen the range of options available for
drilling multilateral wells. For example, the first under-balanced, multilateral
horizontal well was drilled on coiled tubing onshore UK in 1995, with two
uncased small bore laterals. In Oman, PDO are drilling a large number of
innovative multilateral wells on coiled tubing, including some that will be drilled
from old wells, via the 3” completion tubing, with a 2 3/8” hole size through the
reservoir.
Now that the challenges of drilling and completing multilateral wells have been
largely solved by the service companies, oil company engineers are only just
starting to identify novel applications, some of which may become commonplace
in the future.
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WELL PRODUCTIVITY AWARENESS SCHOOL
Geosteering
Horizontal wells are becoming almost commonplace. The recent
advances in drilling such wells is now focussed upon the
accuracy to which they are being drilled. If a horizontal well
cuts through the most permeable layers, or through the most
fractured zones then well productivity can be significantly
enhanced.
Geological steering, or geosteering, is a development in this
field. This technique uses real-time geologic data to guide the
drilling of a well, and is aided by the use of today’s integrated
computing displays. The engineer is able to display logs of
previous wells on the screen, alongside the readings coming
from the MWD-GR/Resistivity tools and is able to steer the bit
exactly to the level of the formation he wishes. This technique
could be used, for instance, to steer through a narrow known
permeable band in a sandstone.
Geosteering is also used to ensure that the bit does not drill
completely out of the reservoir. The primary geosteering log is
the resistivity log because of its deep depth of investigation. As
the tool approaches a bed boundary with a significant resistivity
contrast, a characteristic ‘horn’ will appear. At a 1° angle of
attack the resistivity tool will detect a bed boundary 44 m
before the tool crosses the bed boundary. Even with the
MWD above the mud motor, the bed boundary can be detected
before the bit drills the new formation. None of the other
sensors are as effective for geosteering. Obtaining the logging
information as close to the bit as possible will improve
trajectory control.
Geosteering can be enhanced by preparing ‘model logs’ for the
well profile
prior to
drilling the
well. The
expected log
response is
modelled for
the planned
well profile
using offset
logging
information.
The actual is
compared
with the
model during
drilling to aid
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COMPLETIONS
interpretation. The preparation of the model logs can be time consuming, so it is
important to plan ahead if these logs are to be used.
Anadrill Schlumberger have refined their MWD/LWD tools to produce the
Integrated Drilling Evaluation and Logging (IDEAL) system. Previously,
directional drilling manipulation has been based on measurements some 50 ft to
100 ft behind the bit, depending on the BHA. Now, data measured near the bit
are transmitted by wireless electromagnetic telemetry to an MWD tool, which
pulses information through the mud column to the surface. This allows accurate
near bit readings, yet gives the directional driller some flexibility with his BHA.
50
45
Trajectory
40
Apparent
formation dip
35
30
25
20
15
10
5
0
10000
10500
11000
11500
Horizontal displacement
Petroleum Engineer International
UNION PACIFIC RESOURCES CORP. USED MWD GAMMA RAY DATA TO
GEOSTEER THIS HORIZONTAL WELL. AN IMPORTANT CORRECTION CAN BE
SEEN AT 10,930 FT.
A different geosteering technique was used in BP’s extended reach wells (ERD) in
Wytch Farm. A Reservoir Quality Prediction team was set up, including a
geologist and a petrophysicist. They developed a model which quantified the
permeability of the rock as drilling proceeded. The model was set up on an
Excel spreadsheet. To work the system the drill cuttings were analysed to a
greater degree than normal; including sieve analysis. Naturally, the model
included a large amount of information gleaned from core data from surrounding
wells. The well was steered through the most permeable part of the formation.
The team believe that geosteering contributed greatly to the productivity success
of the first Extended Reach Drilling (ERD) well at Wytch Farm. The model is now
being further refined as the ERD campaign continues.
Completion Design
There are many types of basic completion available; this choice must be made
before the details of tubing accessories, artificial lift etc. are contemplated. Each
completion satisfies different needs. The engineer should investigate all the
options before making his or her choice. Think of the life of the well; not just the
immediate future. The completion types listed below may or may not need sand
control (see Section entitled “Sand Control”).
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WELL PRODUCTIVITY AWARENESS SCHOOL
a) Open Hole (Barefoot) Completion
The well is produced from an open hole completion. The tubing is set in the
casing and the well put on production. In most cases the casing would be set
just above the reservoir.
Advantages:
• Cheap and simple (especially for long intervals)
• Radial flow into well through 360°
• Good access to fractures
Disadvantages: • Mud filter cake will reduce productivity unless it cleans up
• Production has to pass through any damaged zone
• No protection against wellbore collapse
• No zonal isolation
1 Casing is set at top reservoir or there is a
danger that formations above will impair the
well through collapse or production of
unwanted fluids.
2 Zonal isolation is not possible. If a particular
zone needs to be shut off (due to gas
breakthrough in oil reservoir?) or stimulated,
then separation is not possible.
1
2
3
4
3 Hydrocarbons are produced directly into the
wellbore, which must be sufficiently strong to
withstand collapse.
4 Oil/gas must pass through the near-wellbore
damage zone to reach the wellbore. Mud
filter cake will impair production unless it is
fully cleaned up.
BAREFOOT COMPLETION
Zonal isolation is important if there is a water contact in the well; or possibly a
gas zone above the reservoir. It may also be important later if production pulls in
gas or water (to an oil well) and remedial squeezes (or other water shut-off
methods) are needed. The lack of zonal isolation makes selective stimulation
difficult. Zonal separation may also be needed if different reservoirs, or zones
within reservoirs, have different reservoir pressures or depletion rates.
b) Uncemented Liner
The next most simple completion is to run a slotted or pre-perforated liner. The
top of the liner is hung off in the previous casing. In most cases the previous string
of casing would be set just above the reservoir. The liner is left uncemented.
Advantages:
78
• Relatively cheap - dependent on type of liner (especially for
long intervals)
• Slots/holes need only be opposite reservoir
• Radial flow into well through 360°
• Good access to fractures
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COMPLETIONS
• Slot sizes may afford some degree of sand control
• Tubing shoe can be placed closer to reservoir
• Protection against hole collapse
Disadvantages: • Mud filter cake will reduce productivity unless it fully cleans up
• Production has to pass through any damaged zone
• No zonal isolation
ADVANTAGES
• Relatively cheap
• Radial flow through 360o
• Slot sizes afford degree of sand control
• Liner prevents hole collapse
DISADVANTAGES
• Mud filter cake must be removed
• Production must pass through any
damaged zone
• Minimal zonal isolation
PAY
ZONE
Open Hole
Damaged Zone
Schlumberger Oilfield
Review
UNCEMENTED LINER COMPLETION IN DEVIATED WELL
In some uncemented liner completions a degree of zonal isolation can be
achieved by setting external casing packers (ECP).
c) Cased and Perforated
The majority of wells around the world are completed in this fashion.
Advantages:
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• No need to clean up filter cake
• Perforations by-pass the damaged zone
(if engineered correctly)
• Good zonal isolation
• Casing programme not compromised
• Multiple/selective completions possible
• Good well integrity - if properly cemented
• Protection against hole collapse
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WELL PRODUCTIVITY AWARENESS SCHOOL
Disadvantages: • Possible skin due to lack of 360° coverage
• Permeability impairment due to crushed zone and perforation
debris
• Expensive, especially over long intervals*
*This is particularly important with long horizontal wells. The cost of perforating,
say, a 5000 ft horizontal well with a 7” liner could be approximately £600,000:
ADVANTAGES
• Perforations pass
through filter cake and
any damaged zone
• Zonal isolation possible
Production casing
• Multiple selective
completions possible
• Good well integrity
Cement
Cemented liner
Damaged
Zone
DISADVANTAGES
• Perforations may not
bypass all of damage - or
may cause own damage
due to crushed
zone/imperfect clean-up
• Expensive, especially
over long intervals
Selective
perforations
CASED AND PERFORATED COMPLETION
All the above completions may or may not fully penetrate the entire reservoir.
Remember that the ideal radial flow equation was for a fully completed, vertical,
open hole well drilled entirely through the reservoir; thus if a completion is only
across half the reservoir (partial penetration or partial completion
) then there
will be a positive skin.
Completion Practices
In the previous section we have already discussed types of completions, and why
such completions are chosen. In this section we will discuss how to put those
completions into the ground, and the important issues with reference to formation
damage and well productivity.
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COMPLETIONS
Casing and Cement
The most common completion is the cased and perforated variety, yet cementing
of casing remains one of the least successful facets of the drilling/completion
operation. There have been countless papers on primary cementing and all that
can be done to improve it, yet cement jobs still fail and cement bonds are
frequently poor. One of the advantages of the cased and perforated completion
is the ease of zonal isolation; yet if the cement bond is poor, the effective zonal
isolation will also be poor.
Cement
Casing
Oil
Perforation
Good zonal seperation
thanks to solid cement
bond
Mud
(Channel in
cement job)
Poor cement
job lends to
lack of zonal
isolation
Oil
Good cement job
Hole size
Perforations reach past
the damaged zone
Damaged zone
Perforations fail to penetrate
through the cement sheath
and/or the drilling damage.
HIGH SKIN
Hole size
Damaged zone
Productive Well
Poor cement job can decrease productivity
CEMENTING
Running and cementing casing usually takes a small amount of time, compared
with the drilling operation. Consequently, although cement filtrate may be
damaging to many reservoirs, there is little time for invasion to occur and hence
the damage is shallow. The overall effect on productivity is small – perforations
should easily go beyond any cement filtrate damage. It is however recommended
that fluid loss of the cement be controlled, especially if the hole is overgauge.
Squeeze cementing has a much greater potential to reduce well productivity
compared to a casing or liner cementation. This is due to the perforations increasing
the radius of the zone that is damaged. There is also a danger of cement filling up
any cavities (due to sand production) behind the casing. Often, re-perforation (with
smaller guns, and no drawdown) will not reach past such damage.
Naturally fractured reservoirs are most likely to be adversely affected by cementing:
if the most conductive fractures are filled with cement then the well may not flow.
Stimulation treatments (with diversion) are usually required to regain
communication with the fracture network, but sandstone is only slightly soluble in
mud acid, so cemented fractures are very difficult to clean up or by-pass.
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WELL PRODUCTIVITY AWARENESS SCHOOL
A POOR CEMENT JOB CAN DAMAGE WELL PRODUCTIVITY
WE NEED TO ACHIEVE THE SITUATION ILLUSTRATED IN ‘D’ BELOW
SCHLUMBERGER ULTRA-SONIC IMAGER (USI) TOOL
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COMPLETIONS
If casing has already
been perforated (as
would be the case in a
workover) then there is
a danger of cement
filling the perfs (and
any cavities) and
cement filtrate invading
the formation to a
greater depth than
could be reached by
any reperforation
Beware of squeeze
cementing forcing
cement into natural
fractures & thereby
sealing them =
Formation Damage
Oil
Oil
Mud
OWC
Oil Water Contact
Cement
SQUEEZE CEMENTING
Care should be taken not to fracture a reservoir by surging when running in hole
with the casing. Not only will lost circulation compromise well safety, but the
invading fluid (mud/mud filtrate) could cause formation damage. Use swab-surge
computer programmes to prevent this.
Completion Fluids
A well completion will either attempt to perforate through any damaged zone, or
a clean-up will attempt to remove the filter cake and some of the formation
damage. In each case it is imperative that the fluid used for the completion is
itself non-damaging.
In the previous section it was stated that perforations should by-pass the bulk of
the formation damage to reach virgin formation; however if the fluid in the hole
at the time of perforating is itself damaging, then the exercise is merely creating
another damage zone. The perforating issue will be dealt with in the next
section: suffice to say here that the completion fluid must be filtered and nondamaging. (In some instances it is not necessary to filter completion fluids, but a
safe practice is to filter any fluid during the completion phase that will contact the
reservoir at any time.)
The danger of surging the formation was mentioned above for running the
casing; the same thing can happen when running the completion packer. In
addition, poor design of the tensional and compressional forces during packer
setting could induce fractures and losses.
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WELL PRODUCTIVITY AWARENESS SCHOOL
a) Types
Completion brines are filtered salt solutions – the salt that is used depends upon
the density required and should also consider the potential for incompatibility
with the reservoir.
SG
PPG
(Fresh water = 1.00) (Fresh water = 8.3)
Potassium Chloride (KCl)
Sodium Chloride (NaCl)
Sodium Bromide (NaBr)
Calcium Chloride (CaCl2)
Calcium Chloride/Bromide (CaCl2/CaBr2)
Caesium Formate (CsCOOH)
Zinc Bromide (ZnBr2)
up to 1.16
up to 1.20
up to 1.50
1.20 - 1.35
1.25 - 1.70
1.70 - 2.36
1.70 - 2.30
up to 9.7
up to 10.0
up to 12.5
10.0 - 11.2
11.2 - 14.2
14.2 - 19.7
14.2 - 19.2
In most cases do not use seawater to mix completion brines – it is not suitable.
For example, many formation waters precipitate inorganic sulphate scales when
mixed with seawater. This scale can form in the pore spaces causing high skins,
and may be impossible to remove.
Note that brine density is sensitive to temperature. Thus when measuring the
density, the temperature should also be considered. This is especially important
when mixing some brines due to dramatic changes in temperature when
dissolving some salts. For example the dissolution of calcium chloride is an
exothermic reaction (the brine temperature can increase to 50°C) and with
potassium chloride the reaction is endothermic (the brine temperature can often
fall to below 5°C). With hot, deep wells the density of the brine at depth will be
considerably different from the density at surface. Salts may crystallise out as
temperature falls.
Typical viscosifiers used in completion and workover fluids are organic polymers.
They can sometimes be difficult to disperse, especially into high salinity brines.
The pH of the fluid can also affect the ease of polymer dispersion. High shear
mixing is required otherwise small lumps of undispersed polymer gel (‘fisheyes’)
will remain. These ‘fisheyes’ may not degrade with time nor be destroyed by
future acid treatments. To mix high salinity viscosified brine it can be beneficial
to pre-hydrate the polymer in a lower salinity fluid first.
b) Importance of Cleanliness/Filtering
Filtered brines are used as completion fluids to:
•
•
Ensure that minimal solids are present to settle on top of packers or in
sliding sleeves and other downhole tools.
Ensure that no solid particles block the perforation tunnels or the formation
pores within the perforation tunnels
Brines are often described as ‘solids free’; but this is a misleading statement, since
the salts that are used to mix brine always contain some impurities (the best NaCl
is PVD – pure vacuum dried), and they may get contaminated during transport or
handling. QA/QC of the salt supplied could be critical.
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COMPLETIONS
Why Filter?
Ensure no solids present to settle onto packers, and in
accessories (e.g. sliding side doors)
Ensure no solid particles present that may block
pore spaces/throats in the perforations and/or
the reservoir
– Note that even fresh water and the best quality PVD NaCI
MUST be filtered
Solids invasion was discussed in Chapter 3. Drilling muds have a high solids
content in the region of 10 - 20% v/v, whereas completion brines tend to contain
less than 0.05% v/v. Consequently brines have no ability to form a filter cake,
and significant quantities can be lost into the formation. In addition, the low
solids concentration can allow what solids there are to invade further into the
formation as bridging across pore throats is reduced. It is therefore important to
control the size of solids in the brine by filtration; the smaller the solids, the less
likely they are to plug pore throats.
If completion fluid during
or after perforation contains
large solids they will plug
the hitherto undamaged formation
= Loss of Productivity
Wellbore
Contains
Completion
fluid
Virgin reservoir
No invasion
from mud filtrate
Casing
Cement
Damaged zone
invaded by
Mud filtrate
PERFORATION DAMAGE
But when we say a ‘clean brine’, what exactly do we mean? How much rig time
are we going to spend circulating and filtering to achieve the clean brine?
Limits must be set for any completion brine. Decisions must be made beforehand
on whether a brine will be filtered to 10 micron, 5 micron or 2 micron (1 micron
= one millionth of a metre). Note that particles smaller than 40 micron are invisible
to the naked eye. This will depend upon the formation and the practicality of the
particular situation. Decisions must be made in advance as to how ‘cleanliness’
will be measured: turbidity meters, Coulter Counters, Malvern metres, etc.
‘Eyeballing’ a visually clean brine is no longer good enough. This operation can
take a long, long time (24-48 hours). The time is usually well spent and worthwhile.
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WELL PRODUCTIVITY AWARENESS SCHOOL
Filtering
Cartridge
Nominal
Diatomaceous
Earth (DE)
Absolute
Nominal
If losses into a formation render a well unsafe or filters cannot keep up with the
loss rate, the well must be stabilised with a kill pill. The formulation of kill pills
in the completion phase is significantly different from those used in the drilling
phase. This subject is covered in the section on workovers in Section 7.
Two main types of filtration are used:
Cartridge :
Nominal Rating – refers to the typical size of the particle that
is removed, but some larger particles get through the filter.
Absolute Rating – actual size of the holes in the filter
itself.
A 10µ absolute may equate to a 2-3µ nominal filter.
Diatomaceous Earth:
diatomaceous earth builds up a permeable filter cake that
traps any unwanted solids. DE filters are nominal filters
and usually have an absolute ('polishing') cartridge filter
downstream. DE filters can handle much dirtier brine than
cartridge filters. They are not good at handling oily water.
All tanks and pipework must be cleaned beforehand
All contaminants MUST be removed: rust,
scale, coconut figures from nuts, pipe dope,
tubing dope, old mud etc. must be
eliminated.
NEW BRINE MIXED
WITH FRESH WATER
AND CLEAN
CONSTITUENTS
(SALT)
If dirty fluid
is dumped
(where/when
regulations allow)
BAG FILTER (OPTIONAL)
DIATOMACEOUS
EARTH FILTER
If reasonably clean
then returning fluid
is re-filtered
Check differential
pressure across
cartridge to ensure
optimum operation
Measure
cleanliness
Inspect D.E. bed frequently
Do not allow loose diatomaceous
earth to go into the completion
fluid. It will plug formations!
CARTRIDGE FILTER(S)
(sometimes called 'polishing' filters)
Measure
cleanliness
Downhole tubulars
must be
scrupulously clean
DOWNHOLE
RETURNS FROM
THE WELL
TYPICAL FILTER SET-UP
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COMPLETIONS
Whatever the type of filter, filtration is not a ‘start-it-up-and-let-it-run’ operation;
the system must be constantly monitored and maintained.
c) Displacement
There is no point in placing ‘absolutely’ clean brine into a dirty well and ending
up with it mixed with dirty mud. Displacing solids-laden mud with clean brine is
not straight forward. In order to minimise contamination of the brine, the method
of displacement is important.
Depending upon the criteria set (for example, in gravel packed completions the
cleanliness criteria are even more severe than in normal cased and perforated
completions) there will be a series of circulations necessary to clean up the
system prior to displacing the well to completion brine. Note that the word
‘system’ is used, since the tanks, pumps, lines, drill pipe/tubing, and the casing
walls will all have to be free of solids prior to the brine going into the hole. If
surfactants are used to clean up the tubulars, it is imperative that they be
circulated out as they may cause formation damage themselves by the methods
already mentioned earlier.
If a well is not going to be perforated, it is essential that the mud filter cake be
removed from the wellbore when the well being completed. This problem –
especially in horizontal wells – is the subject of ongoing research. In such a case
the mud solids are usually chosen to be soluble (calcium carbonate in acid, sized
salt in dilute brine, oil-soluble resin in oil etc).
Perforating
Charlie Cosad of Schlumberger wrote “The fate of a well hinges on years of
exploration, months of well planning, and weeks of drilling But ultimately it
depends on performing the optimal completion, which begins with the millisecond
of perforation. Profitability is strongly influenced by this critical link between the
reservoir and the wellbore”.
There are three basic types of perforated completion, each with its own specific
requirements.
Completion Type Perforation
Natural:
Stimulated:
Gravel Packed:
If perforation is to be immediately followed by production,
then many deep shots would be most effective.
In stimulated completions – hydraulic fracturing and matrix
acidisation – a small angle between shots helps to effectively
create hydraulic fractures and link perforations with the new
pathways in the reservoir.
Many large diameter perforations filled with gravel are used
to keep unconsolidated formation from producing sand.
Perforating is extremely important.
All perforations must be
meticulously planned – any old holes will just not do. The purpose of
the perforation is to by-pass the damage zone and reach virgin reservoir.
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WELL PRODUCTIVITY AWARENESS SCHOOL
a) History of Perforating
With the advent of cased completions came the need to perforate wells. Early
wells were merely connected to the formation via a slot made by a mechanical
perforator where a blade was forced through the casing. These were not very
effective. The first wireline-conveyed bullet perforators were used in 1932 and
gave much better results.
Shaped charge perforators, which came from the development of armour-piercing
weaponry in World War II, were introduced shortly after that conflict, and gave
even better results. This form of perforating, run on electric line, dominated the
market until the introduction of Tubing Conveyed Perforating (TCP) guns by Vann
Systems in the early 70’s.
b) Perforating Charges
A shaped charge is a precisely engineered cone of pressed metal powder, or
drawn solid metal, surrounded by a secondary explosive and case, and initiated
by detonating cord. Detonation collapses the cone into a jet which generates
millions of psi pressure at huge velocities and penetrates the casing and the
formation.
Explosive
Primer
Well casing
Cement
Detonating
cord
0 µ sec
Damaged zone
Case
Liner
Formation
4 µ sec
9.4 µ sec
Progression of shaped-charge
detonation. The schematic at 0 µsec
shows the charge components. The
volume of explosive is greatest at the
apex of the liner and least near its open
end. This means that as the detonation
front advances, it activates less
explosive, resulting in a lower collapse
speed near the liner base. The
subsequent drawings show the case
deforming as the detonation front
advances, thrusting the liner into a jet
along the shaped-charge axis. The fully
formed jet, at 16.6 µsec, is moving at
about 21,300 feet/sec (6500 m/sec).
Crushed rock
16.6 µ sec
Perforation
tunnel
6-16"
The perforation
can contain
crushed rock
and liner debris
The metal case creates debris
that can cause mechanical
problems within the wellbore
PERFORATING CHARGES
THE SHAPED CHARGE
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The detonating cord or 'primacord'
is a continuous connection down the
length of the gun. Boosters are sometimes employed to pass the detonation
along to another gun (below/above). The detonating cord is activated by the
detonator , which is set off by electrical impulse, mechanical impact or pressure.
The detonating cord in turn sets off the p r i m e r , which is a small amount of
higher sensitivity secondary explosive at the base of each shaped charge. This
ensures correct initiation of the explosion.
Various grades of e x p l o s i v e a re used; dependent upon the downhole
temperature, and the time that the guns will be in the hole before they are fired.
For instance, a TCP gun will be exposed to wellbore temperatures for a greater
time than wireline conveyed guns, so RDX may be suitable for the wireline gun
where HMX (higher temperature rating – more expensive) will have to be used
for the TCP guns. The amount of explosive per shaped charge varies from 3 to
66 grams: the greater the charge, the greater the penetration. However, the larger
the charge, the less charges per foot that can be run.
The casing and the shaped charge is disintegrated into fingernail-sized flakes of
debris, and this debris can be a problem. It may plug the perforations. The
various suppliers have developed low debris charges. ‘Low debris’ actually
means different debris: fine powder rather than metallic flakes. Low debris
charges can be useful in horizontal wells where it can be produced out of the
well; whilst it may be difficult to move the larger flakes from the conventional
charges.
‘Big Hole’ charges have been developed for gravel-packing applications. They
have a liner made from a solid copper sheet to help create a big diameter hole
(1.0” vs. 0.4”). Unfortunately, the sheet liner forms a slow moving ‘carrot’ behind
the jet, which can block the perforation tunnel.
‘Deep penetrating’ charges are used for consolidated sandstones, to get
the best production rates.
Powdered
metal liner
0.4"
Depth of
damage
(~12")
‘Soft’ or poorly consolidated sandstones which need to be gravel packed
are perforated with ‘big hole’ charges.
Solid
liner
This perforation is
packed with gravel to
prevent sand
production.
1"
Casing
Cement
PERFORATING HARD OR ‘SOFT’ SANDSTONES
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WELL PRODUCTIVITY AWARENESS SCHOOL
c) Delivery Systems
There are essentially two ways of getting a gun down the well: on wireline (with
through-tubing and casing guns) and on tubing (Tubing-Conveyed Perforating – TCP).
Through-casing perforation
(Generally overbalanced)
Through-tubing perforation
(Generally underbalanced)
Tubing-conveyed perforation
(Generally underbalanced)
Workstring
Casing
Tubing
Packer
Packer
Firing
head
Casing
gun
Through
-tubing
gun
Safety
spacer
Flow
entry
ports
Guns
Three conveyance methods for perforating guns: through-casing and through-tubing,
and tubing-conveyed systems. The through-tubing gun shown is held against the
casing magnetically. The others hang free.
GUN DELIVERY SYSTEMS
Schlumberger Oilfield Review
Wireline conveyed casing guns are not usually fired underbalanced; whereas the
through-tubing and TCP guns can use this method of enhanced perforation cleanup (more of which later).
There are two broad categories of gun type: exposed and hollow carrier.
Exposed guns are run on wireline and have individual shaped charges sealed
in capsules and mounted on a metal strip or bar. The detonator and detonating
cord are exposed to borehole fluids. These guns are used exclusively throughtubing and leave debris after firing. They include two designs: ‘expendable’
(charges and mounting assembly become debris) and ‘semi-expendable’
(mounting only is recovered). For a given diameter, exposed guns carry a
larger, deeper penetrating charge than a hollow carrier gun. These guns
usually come with zero-degree phasing; therefore a bow-spring or magnet
should be used to press the charges against the casing. The length of gun that
can be run depends upon the length of lubricator that can be rigged up. These
guns are frequently run through-tubing for reperforating where pulling the
tubing would not be economic.
Hollow Carrier guns become preferable to exposed guns above about 21/8”,
because above this size, the casing, or hollow carrier design, becomes more
practical, allowing the use of larger charges, optimal angle between shots –
called ‘phasing’ (at 0, 45, 60, 90, 120 degrees) – and increased number of shots
per foot (4, 6, 8, or 12 spf) – called shot density.
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COMPLETIONS
Gun
System
Exposed
gun
Application
Wireline
through-tubing
Strip
X
Pivot
X
Scallop
X
Wireline
through-casing
X
Port plug
Hollow
carrier gun
Tubing
conveyed
High
efficiency
X
X
High shot
density
X
X
X
Schlumberger
Schlumberger
nomenclature
Nomenclature
Types of perforating guns and their application
Hollow carrier guns have shaped charges positioned inside a pressure tight steel
tube. The design is available for most tubing and casing sizes. It is used through
tubing when debris is unacceptable or in hostile conditions that preclude exposed
guns. The main types of hollow carrier guns are:
• Scallop guns: so-called because charges shoot through dished out areas in the
carrier (to reduce burr protrusion).
• Port Plug guns, in which charges shoot through replaceable plugs in a
reusable carrier. These are wireline conveyed, mainly for deep penetration,
and where 4 shots per foot is acceptable.
The wireline conveyed guns can be pulled out of the hole immediately after the
guns have fired. The TCP guns have to remain in the hole until the tubing string
has been pulled. Alternatively the TCP guns can be released (usually by slickline
manipulation) and dropped down the hole. If this is done, an additional sump
has to be drilled to make space for the guns. If the sump can not be provided,
the well will have to be ‘killed’ after the underbalanced perforating, and the guns
withdrawn from the well before the completion is run. This opens up the
potential for damage to the formation from the completion fluid leaking off into
the new perforations. To prevent this happening an oil-soluble resin, calcium
carbonate or sized salt LCM can be put across the perforations to stop the fluid
loss whilst the guns are retrieved.
TCP guns are usually more expensive to run because of all the rig time
consumed. However, for very long intervals they may take less rig time than
wireline conveyed guns – since a large number of perforating runs (dictated by
the length of lubricator) will have to be made. Note that even with the well
flowing during perforating it may not be possible to achieve the same drawdown
as the first perforating run. Also, care has to be taken not to blow a wirelineconveyed gun up the hole causing a 'birdsnest' and a subsequent fishing job.
d) Perforation Skin
The near wellbore region plays a vital part in the productivity of every well.
All the fluid produced from the reservoir has to pass through this region.
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91
WELL PRODUCTIVITY AWARENESS SCHOOL
Damaged zone
Perforation
diameter
Perforation
varies with
shot
density
Phase
angle
Crushed
zone
Perforation
penetration
Schlumberger Oilfield Review
Major geometrical parameters that determine
flow efficiency in a perforated completion. Four
key factors are shot density, phase angle,
perforation penetration into the formation and
perforation diameter. Productivity of a well also
depends on the size of the crushed zone,
whether the perforation extends beyond the
damaged zone and how effectively the crushed
zone and charge debris are removed from the
tunnel.
Phasing from top
6
3
8
0
45°
1
5
135°
4
7
2
0° phased
Enerjet
45 90 135 180 225 270 315 360
8
1
2
4
3
7
1
1
Gun in
casing
Schlumberger Oilfield Review
3
6
5
7
2
60° phased
scallop gun
A family of through-tubing, wireline-conveyed guns. From left, the 0° phased
Enerjet (a semiexpendable strip gun), the phased Enerjet, with two rows of
charges at 90° (an expendable strip gun) and the 60° phased scallop gun (a
retrievable gun). Unlike the Enerjet, the scallop gun has negligible debris and
can be run in hosite environments.
8
2
4
6
6
5
6
±45° phased
Enerjet
8
Casing unrolled (7 in.)
Three views of perforating with a 135°/45°
phased gun: the gun fired in casing, phasing
viewed from the top, and with the perforated
casing unrolled and laid flat. The 135°/45°
designation means the angle between
successive shots is 135°, resulting in an overall
phasing of 45°. There is 1 vertical inch [2.5 cm]
between shots, making 12 shots per foot. In the
natural completion, this phasing provides
hydrocarbons with the most direct path to the
wellbore.
GEOMETRIC FACTORS THAT DETERMINE FLOW EFFICIENCY
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COMPLETIONS
Even in the absence of a damaged zone it is possible to create a mechanical skin
by imprudent choice of perforating gun. A zero skin is where there is the same
pressure drop as ideal undamaged radial flow into the open hole, uncased well.
A mechanical skin will exist where there are any features around the well that
increase the radial flow pressure drop. For example, zero phased perforations
with 3” tunnel length, fired at 4spf, causes a skin of +5, even if there is no
damaged zone. When formation damage is present, the skin will be many
times larger.
Hydrocarbons have
a more tortuous
path to reach the
wellbore. This is
contrary to the idea
of 360° radial flow thus there is a
‘mechanical skin’
Zero phased
perforations
MECHANICAL SKIN CAUSED BY ZERO DEGREE PHASING
The science of
predicting the near
wellbore skin has
passed from
empirical models to
computer simulation.
The work of Karakas
and Tariq (SPE18247)
is widely accepted as
the best guideline,
giving equations to
predict mechanical
skin using a specified
amount of drilling
damage, perforation
details (phasing, spf,
penetration, crushed
zone damage), and
formation anisotropy.
If a small diameter gun is run in a larger casing there is a danger of
the situation below developing. Where possible the largest OD
casing gun or TCP should be run - but remember that you must be
able to fish the gun should it get stuck.
Debris if
insufficient
underbalance
Ineffective
to clean it out
perforation
If guns are not
centralised some
perforations will be
well below
specification
To make this field
Gun willviable
lie on low
economically
this rate
must
side
ofbethe hole
achieved until the
end of year seven.
Perforation
casing
diameter
about 0.4"
Crushed
zone
Tunnel length
up to 20"
GUN IN CONVENTIONAL (~20° DEVIATED WELL)
Revision 2: 2001
93
WELL PRODUCTIVITY AWARENESS SCHOOL
e) Perforating Through Drilling Damage
It is vitally important to perforate through any drilling damage.
Shot density is important, since more holes means more places for hydrocarbons
to enter the wellbore and the greater likelihood that perforations will intersect
productive intervals in a variable (anisotropic) reservoir. Under typical flow
conditions, perforation tunnel diameter does not adversely affect flow, provided it
exceeds 0.25” (6mm); which today is provided by almost all guns.
1.4
1.2
1.0
0.8
In this well, if the
perforation length
exceeds 12" then
the virgin reservoir
is tapped and the
productivity of the
well is restored. The
greater the shot
density the better
the productivity,
0.6
0.4
0.2
Damage Depth - 12"
Kd/K - 0.1
0.0
0.0
4.0
8.0
12.0
16.0
20.0
Perforation Length (in)
PERFORATING THROUGH DRILLING DAMAGE
f) Perforation Tunnel Length
The actual perforation tunnel length has a significant impact on well performance.
The data to estimate perforation tunnel length is given by the manufacturers in
accordance with the API Recommended Practice 43. Edition 5 of RP43 was
published in Jan.1991.
Section 1: A multi-shot test into a block of concrete at ambient conditions
Section 2: Single shaped charge fired into a 39/16” cylinder of Berea Sandstone at
3000 psi confining stress.
Note: Many companies will publish the results of the less stringent
Edition 4 tests.
Beware: The API RP43 results at best gives a relative measure of downhole
perforation lengths. In 1984 Exxon performed a ‘shoot-out’ between all the
manufacturers, under controlled conditions, and found that none of the results
met or exceeded those stated by the manufacturers.
The penetration results of Section 1 tests (in concrete) real perforations, as ‘target
activity’ will always reduce the concrete figures. As a rule-of-thumb, Section 1
results should be reduced by 33% to be equivalent Section 2 (in Berea Sst) test.
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COMPLETIONS
Percentage of reported API penetration
0
50
100
Dresser Atlas
Gearhart
Schlumberger*
Harrison
SCS
SIE Geoscience
GOEX
Owen
JRC
*Schlumberger acheived the longest perforations in each class
EXXON SHOOT-OUT, 1984
New Deep Penetrating Charges
Schlumberger have recently introduced new perforating charges which by virtue
of their improved charge liner and denser explosive packing technology offer a
significant improvement (38%-54%) in target penetration.
The table below compares the new 51J HMX and 37J HMX charges with existing
options. Both the 51J and 37J charge types have been field tested by several
operators worldwide. The HMX temperature rating allows the guns to be
considered in most BP reservoir environments.
Charge Name
Charge
API
Carrier Density Phasing
API
Size
Section 1 Section 1
Size
(grammes) (ins) (shots/ft) (degrees) Penetration Entry Hole
(ins)
(ins)
51J Ultrajet HMX
51B Hyperjet II HMX
51B Hyperjet II RDX
38.5
37
37
41/2
41/2
41/2
5
5
5
72
60
60
43*
31.05
30.52
0.45*
0.45
0.48
37J Ultrajet HMX
41B Hyperjet II HMX
41B Hyperjet II RDX
34
22
22
31/2
33/8
33/8
4
6
6
60
60
60
34
23.5
22.12
0.46
0.4
0.36
*Unofficial API Data
The principal applications of these charges include:
• Zones with formation damage which extends beyond the penetration depth of
existing charges (e.g. Cusiana).
• Zones which have been remedial cement squeezed resulting in a large
annulus of cement around the wellbore due to previous formation production
(e.g. Forties).
Revision 2: 2001
95
WELL PRODUCTIVITY AWARENESS SCHOOL
Always check the conditions under which the results were obtained. There are
corrections that must be made to the API Section 2 results, when deciding upon
which charges to use to perforate an actual well. There are corrections for:
1. Unconfined Compressive Str ength – the rock you are actually perforating
may be harder or softer than Berea. North Sea rock is usually softer than Berea.
2. Confining Stress – the Edition 4 tests are done at 1000 psi confining stress.
The Edition 5 tests are done at 3000 psi confining stress, which can reduce the
performance of a charge by 10%. Above 3000 psi there is not much
difference. Check to see which Edition the perforating company is quoting.
3. Clearance – there is of course a difference between having the charge
pressed against the casing, versus an offset. Check what the perforating
company is quoting vs. how you are perforating.
Guns are tested according to API 43. Section 1 is a multi-shot test into
a concrete target. Section 2 is a single shot into a cylindrical Berea
sandstone core more representative of real formations.
Berea
TTP
Sealing material
Steel
Perforation
If no Berea tests were
done, use 66% of the
concrete test perf.
length to estimate
Berea perf. length.
Typical Perforation Lengths
Charge size
6.5g 22g
Section 2
Test
TCP
High permeability
beads or rods
Soft formation
Hard formation
10"
3"
17"
7"
To convert Berea perforation lengths to actual downhole penetration
the lengths must be corrected for formation compressive strength,
overburden stress and clearance. Perforations go further in weaker
rocks with less overburden stress.
These corrections are important: for instance the Total Target Penetration can be
halved if penetrating a much harder rock than Berea. If you have computer
programmes to help you (BP’s KTPerf and Inflo2), use these to assist you in your
decision; if not, press the perforating company for more and better information.
Quality control of perforators is important:
•
•
•
•
How old are the charges?
How have they been stored (temperature/stability)?
How have they been transported?
Who manufactured them and where?
g) Underbalanced Perforating
Crushed Zone
Immediately around each perforation tunnel is a ‘crushed zone’, where the
formation has been deformed. The thickness and permeablility of the crushed
zone depends upon charge size, rock type and underbalance. It is usually about
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COMPLETIONS
Thin Section of Undamaged Rock
Thin Section of Crushed Zone
(50% less permeability)
DAMAGE AROUND THE PERFORATION
Blue = Porosity/Permeability
1/2” thick, and has about 50% of the undamaged formation productivity. CAT
scans and thin sections have shown that porosity is maintained in the crushed
zone. The larger pores are destroyed, and the grains become micro-fractured.
If this crushed zone is not removed, the productivity from each perforation will
be impaired.
Overbalanced perforating before flowing
Damaged zone
Virgin formation
Change
debris
Cement
Casing
Without cleanup, the
perforation tunnel is
plugged by crushed
rock and charge
debris.
Crushed (low-permeability)
zone still exists
Overbalanced perforating after flowing
Part of low-permeability
zone still exists
Perforation partially plugged
with charge debris
Flow has removed
most charge debris,
but some of the
low-permeability
crushed zone
created by the jet
remains.
Ideal underbalanced perforating
Crushed zone and charge
debris expelled by surge
immediately after perforating
Sufficient
underbalance during
perforating removed
damage - both
charge debris and
crushed rock.
Schlumberger Oilfield Review
This one will have by far and away the best productivity.
Revision 2: 2001
97
WELL PRODUCTIVITY AWARENESS SCHOOL
Schlumberger Oilfield Review
98
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COMPLETIONS
Underbalance
One important parameter that the engineer has control over, and that can
influence near-wellbore skin, is the amount of underbalance. Underbalanced
means that the wellbore pressure is less than the formation pressure before
perforating; thus there is a flow into the wellbore immediately after perforating.
Underbalanced perforating gives better well productivities; the strong surge of
flow out of the perforations removes crushed rock and fine debris, giving clean,
open perforations. Once the debris is out of the perforations it must be produced
out of the well.
Wireline perforating can only be slightly underbalanced. The first run in the hole
might be a few hundred psi underbalance; perhaps more in low productivity
wells. If the underbalance is too great there is the real danger of the guns getting
‘blown up the hole’ with dire consequences. In contrast, tubing conveyed
perforating allows much larger, safe underbalances.
Clean perforations are thought to be obtained by a sufficient flowrate out of each
perforation. Hence a lower permeability reservoir will require a larger
underbalance. King (1986) produced a graph, of minimum underbalance vs.
permeability.
If weak formations are perforated with too
high an underbalance, there is a danger of the
perforation tunnel collapsing - leading to
impaired well productivity.
1000.0
100.0
These wells flowed
as per expectation.
10.0
1.0
0.1
100
Inadequate underbalance
Adequate underbalance
1000
Underbalance (psi)
These wells recorded
a positive skin.
10000
EFFECT OF PERMEABILITY ON REQUIRED UNDERBALANCE
In the Cusiana field for instance, an early well was perforated with an
underbalance of 2000-3000 psi and this resulted in much lower skins than seen in
a later well where the underbalance was only 500-1500 psi.
Revision 2: 2001
99
WELL PRODUCTIVITY AWARENESS SCHOOL
Too much underbalance can also cause problems; for example the collapse of
perforation tunnels leading to sand production in weak formations. This was
thought to be the problem in Cusiana which is why the underbalance was
reduced. (In fact the debris turned out to be crushed rock from the perforations
and they were able to revert to the higher underbalances.) It might also create a
fines migration problem in some formations. It might also unseat the TCP packer
or collapse the tubing. The level of underbalance is controlled by using a
cushion of nitrogen, diesel or brine.
‘Backsurging’ may be used to clean out perforation tunnels if underbalance is not
possible, or insufficient, at the time of perforation. Backsurging is done with
special tools run in completion or workover strings. BP Alaska use instantaneous
underbalance devices (IUD’s) following reperforating with wireline conveyed
guns. A similar underbalance device has been used on Ula and Gyda. These
tools are however limited by the length of formation they affect by each
application (approx. 50 ft).
The clean-up of perforations by backsurging after the well has been put on
production is thought to be less effective when compared with underbalanced
perforating. This is because the hydrocarbons by this time have found the paths
of least resistance through the damage and this route will never be as good as
through the entire fabric of the rock.
Perforation Plugging
A cased and perforated well relies on its perforation tunnels as the avenues of
production. These tunnels can very easily become plugged. This emphasises the
need to perforate in clean completion fluid, and to keep the wellbore free of
plugging materials such as pipe dope. Pipe dope will block perforations and
is difficult to remove.
Therefore be sparing with the application of dope to
tubing, and apply with a small paintbrush to pin ends only. This is a example
where anyone and everyone can influence the productivity of the well.
It is possible for just one slug of dirty fluid going downhole to completely plug all
the perforations – PERMANENTLY. A perforation that is 16” long and 0.4” in
diameter only has a volume of 2 cubic inches or 32 cubic centimeters. Imagine
how easy it would be to plug off the perforation entirely; or even just plug off the
perforation entrance with a globule of tubing dope!
Paint from completion equipment can also come off downhole, and enter the
perforation tunnels. This is why brightly painted packers – be they yellow, blue
or red – are stripped of their coats of many colours before being run in the hole!
Always be careful when tripping into the hole with open perforations – especially
with a packer in the string. A strong surge could cause formation breakdown,
losses and damage.
h) Overbalanced Perforating
In the section above the necessity and benefit of underbalanced perforating was
explained. Nowadays the vast majority of wells are perforated underbalanced.
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COMPLETIONS
However, Oryx Energy (U.S.A.) became worried by some of the poor results that
they were getting from their perforated completions. They calculated that they
were only achieving an average of 25% completion efficiency: only one
perforation in four was effectively contributing to production.
Oryx therefore investigated ways to improve this; both within the techniques
already employed and by experimenting with new techniques.
Some observers (including BP Sunbury) had noted that there were a series of
radial fractures around perforation tunnels. Oryx reasoned that if a well was
perforated in severe overbalance , that these fractures might be extended and
actually enhance the productivity of the perforation. Thus overbalanced
perforating was born. Oryx have achieved some measure of success over more
than 50 wells, and are now licensing the technique via the relevant service
companies. Halliburton have such a license and are actively marketing the new
technique.
Closure of Fractured Perforation
Overburden causes
perforation tunnel to
close up?
A simplified look at a
perforation
The smaller than
expected perforation
tunnel will lead to lower
productivity
Outer bounds of
perforation tunnel
Fractures created by
perforation jet
Fractures initiating from applied
overbalanced pressure
σ max (maximum horizontal stress)
σ max
Revision 2: 2001
Perforations here are
extending past the explosive
tip of the perforation. This
leads to enhanced productivity
101
WELL PRODUCTIVITY AWARENESS SCHOOL
The table below illustrates the negative skins that can be achieved.
Build-up results for overbalanced well treatments
Well/state
location
O.B.
Type
Formation fluid
name/type system
Midperf BHP
O.B.
(perf/ depth. Perf. Resv.
surge) ft
ft
psi
grad.
psi/ft K
Skin
1.
2.
3.
4.
5.
6.
7.
8.
9.
10.
11.
12.
13.
14.
15.
16.
Strawn SS
Strawn SS
Strawn SS
Strawn SS
Strawn SS
Atoka SS
1st Spiro
Morrow SS
Atoka SS
Strawn SS
Morrow SS
Svn Rvrs SS
PDC SS
Red Fork SS
Strawn SS
Skinner SS
Perf
Perf
Perf
Perf
Perf
Perf
Perf
Perf
Perf
Perf
Perf
Surge
Perf
Surge
Surge
Surge
1.39
1.39
1.39
1.39
1.40
0.87
1.25
1.21
1.10
1.27
1.11
1.69
1.33
1.18
1.06
1.24
-0.6
-2.2
-2.3
-2.3
-2.0
-2.3
-1.4
85
-3.3
-3.6
-5.0
10.0
-0.4
-1.5
-1.1
-1.5
Texas
Texas
Texas
Texas
Texas
New Mexico
Oklahoma
New Mexico
New Mexico
Texas
New Mexico
New Mexico
Michigan
Oklahoma
Texas
Oklahoma
N2
N2 & sand
N2 & sand
N2 & sand
N2 & sand
N2 & HCl
N2 & HCl
N2 & sand
N2 & ISP
N2 & sand
N2 & ISP
HCl
N2 & HCl
N2 & wtr
N2 & sand
N2 & wtr
5769
5763
5763
5768
5697
14305
10823
9490
13021
5899
10784
3022
10231
12630
5921
11321
17
45
5
28
32
68
70
13
10
135
44
20
38
40
128
30
1980
1450
1650
1891
2058
11014
8000
2816
4771
2200
4336
640
4650
5827
1770
4653
0.424
0.756
0.120
0.003
0.003
0.018
0.006
10.8
0.24
0.109
7.955
0.500
0.039
0.006
0.081
0.051
Oryx Energy has so far had its greatest success in moderate to low permeability
sandstones (25mD or less), high permeability-low BHP formations, and naturally
fractured carbonates.
How is it done? Conventional perforating guns are used, but a large overbalance
is applied by pressurised nitrogen. If the pressure was applied using a liquid
(brine or oil) it would dissipate too quickly after the gun was fired and the
fractures at the tips of the perforations would not propagate. This is because
brine and oil are essentially incompressible. However, if only nitrogen were used
there would be no ‘mass’ to do work in the perforation. So the two methods are
Typical land based overbalanced
perforating operation
Applied surface pressure
= 7000 psi
Illustration just prior
to perforating
Pressurized
nitrogen
Applied wellbore pressure
8000 psi
(∆P = 5500 psi into perfs)
Overbalanced
Perforating
102
Sand. reservoir
pressure = 2500psi
Oil or fracture fluid
Frac fluid will enter the
perforations at 5500psi
greaterpressure than the
formation and will cause
fractures to propogate
from the tip of the
perforations
Revision 2: 2001
COMPLETIONS
combined: the expanding gas provides the energy whilst a small column of
incompressible fluid across the formation does the work. In normal applications,
nitrogen is pumped at high rates instantaneously after perforation to extend the
fractures. It is analogous to a bullet in which the slug provides the mass to
penetrate the target when the powder behind is detonated.
The technique is not widespread, and it is unlikely to take over entirely from
underbalanced perforating. However it does have some application where:
• permeability of the formation is so low that the perforation tunnels will not be
cleaned out regardless of the underbalance used
• low pressure reservoirs which may not have enough energy to backsurge the
perforations
• large intervals that must be perforated on wireline (several runs), where the
later perforation runs can only be achieved with the well flowing, versus the
desired full waterbalance
Relative importance
of four main
geometrical factors
in the three
completion types,
where 1 is the
greatest importance
and 4 is the least.
The optimum
perforation design
establishes the
proper trade-off of
these factors, the
lower part of the
figure shows
common
considerations for
perforating natural
completions. When
natural fractures are
present, phasing
becomes more
important than
density to improve
communication
between fractures
and perforations.
Schlumberger
Oilfield Review
Revision 2: 2001
103
WELL PRODUCTIVITY AWARENESS SCHOOL
The present ‘Rule of Thumb’ for overbalanced perforating is:
Minimum BHP Applied = (Fracture Gradient in psi/ft + 0.4) x Depth
The sequence of a typical Oryx job might be:
1. Run TCP guns. Set on depth.
2. Using coiled tubing or circulating sub to place between 300ft and 1000ft of
frac fluid across the interval and above the guns.
3. Pressurise up the nitrogen above the frac fluid to 7000 psi at surface.
4. Detonate guns.
5. Pressure drops instantly to approx 4400 psi.
6. Kick in nitrogen pumps at 8000-10,000 scf/min and pump 140,000 scf.
7. Produce well back.
There are some problems with overbalanced perforating; primarily concerning
equipment specification
• can the wellhead, tubing, casing take the pressures?
• have the well components been weakened over time by corrosion
(if re-perforating at old well)?
• are the tubulars CLEAN?
• is the frac fluid non-damaging?
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COMPLETIONS
Sand Control
Sand Control is implemented by one of the following methods
•
•
•
•
•
External gravel-pack
Internal gravel-pack
Pre-packed screen
Chemical consolidation
Frac pack
In many wells, especially shallow ones,
hydrocarbon production causes sand
production. Unconsolidated
sandstones with permeability over 0.5
Darcies are most susceptible to sand
production, which may start during first
flow, or later when reservoir pressure
has fallen, or when water breaks
through. Sand production strikes with
varying degrees of severity, not all of
which requires action. The rate of sand
production may decline with time at
constant production conditions and is
frequently associated with clean-up
after stimulation.
Sand production may be tolerated
depending upon operational
constraints like resistance to erosion,
separator capacity, ease of sand
disposal, and the capability of any
artificial lift equipment to remove
sand-laden fluid from the well.
Fluid inflow
Cement
Fluid inflow
Perforation tunnel
Formation sand
Fluid inflow
Doorway to the wellbore. A stable arch is
believed to form around the entrance to a
perforation cavity. This arch remains stable as
long as flow rate and drawdown are constant.
If these are altered, the arch collapses and a
new one forms once flow stabilises again.
Gravel
a) Internal/External Gravel Packs
and Pre-Packed Screens
Gravel packs can be internal or
external : using special tools, sized
gravel is placed between the
unconsolidated reservoir and the
screen to prevent sand production.
A pre-packed screen is a form of
gravel-pack completion. The prepacked screen features a bonded
resin-coated gravel held between an
inner perforated base pipe and an
outer wire-wrapped screen. Such
completions are finding favour in
unconsolidated horizontal wells, such
as those of the Chevron Alba Field,
Kerr-McGre’s Gryphon Field and BP’s
Foinaven Field.
Revision 2: 2001
Cementing port
and/or external
casing packer
Slotted or
pre-drilled liner, or
wire-wrapped screen
Gravel - must be
placed in clean
fluid to maintain
the pack
permeability
(not often used nowadays)
Underreamed hole must be drilled with
non-damaging fluid
EXTERNAL GRAVEL PACK - EGP
105
WELL PRODUCTIVITY AWARENESS SCHOOL
Underreamed
External
Gravel Pack
Frac
Pack
Resin Coated
Sand Pack
Plastic
Consolidation
Internal
Gravel
Pack
DOWNHOLE SAND CONTROL METHODS
106
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COMPLETIONS
Dual-Screen Prepack Screen
Perforated Base Pipe
Gravel
Inner wire-wrapped screen.
This can be a mesh, rather
than a stainless steel screen.
Great care must be taken when
handling all types of gravel-pack
screens. They must be cleaned
or kept clean at surface and
handled very carefully. One
point of weakness can lead to
failure of the whole completion.
They must be run in hole as
carefully as possible to minimise
damage and/or dirt pollution
whilst scraping the wall of the
wellbore.
For long term productivity, the
gravel must be clean, tightly
packed and placed with the
minimum damage to the
formation. These requirements
These screens are most commonly run
in very high angle holes and horizontal
should be used in the correct
wells with sand control problems
selection of gravel size, carrier
fluid and placement technique. They also rely on scrupulous cleanliness during
placement operations to prevent the contamination of the gravel pack by small
particles that significantly reduce pack permeability. It has been proved that
0.5% fines in the gravel can plug the completion!
Outer wire-wrapped screen
The carrier fluids must be sufficiently viscous to carry the gravel to the completion
downhole, yet they must ‘break’ completely after placement and flow back
leaving no damaging residue. A carrier fluid is pumped with a time-delay (and
temperature) breaker to facilitate this.
Gravel is not just loosely sized sand. Gravel for gravel packing is a precisely
graded, high quality product with strict limits of manufacture/production to
minimise fines and impurities.
Commonly Available Gravel Sizes
Approximate
Median Diameter
Gravel Size
(in.)
0.006
0.008
0.010
0.017
0.023
0.033
0.039
0.033
0.047
0.066
0.079
Revision 2: 2001
x
x
x
x
x
x
x
x
x
x
x
0.017
0.017
0.017
0.033
0.047
0.066
0.066
0.079
0.079
0.094
0.132
US Mesh
Size
In.
µm
40/100
40/70
40/60
20/40
16/30
12/20
12/18
10/20
10/16
8/12
6/10
0.012
0.013
0.014
0.025
0.035
0.050
0.053
0.056
0.063
0.080
0.106
300
330
350
630
880
1260
1340
1410
1590
2020
2670
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WELL PRODUCTIVITY AWARENESS SCHOOL
Permeability and Porosity
of Graded Sands
US Mesh
Permeability, Darcies
(approximately)
Porosity, %
(approximately)
8/12
10/20 10/20 10/30
Angular Angular Round Round
20/40 40/60
Round Round
1,745
881
325
191
121
45
36
36
32
33
35
32
The pressure drop along the perforation tunnels in cased hole gravel packs gives
high skins. Larger gravel gives a lower pressure drop and skin. However, since
the pack must act as an effective filter, the gravel also has to be small enough to
prevent the ingress of formation particles. The work of Saucier gives the most
widely accepted criteria for gravel size selection, where gravel-size is six times
the median diameter of the formation sand. In all cases the gap between each
wire-wrap of the screen is exactly sized to compliment the gravel size used.
Saucier also identified that wide entry holes, and large gravel-filled cavities behind
the casing reduced the pressure losses in the perforations. This placement
technique is now known as a 'pre-pack' where the perforations are purged by
underbalanced perforating, followed by placement of gravel in a very clean
filtered fluid. The perforations can then be protected by a degradable LCM which
can be removed prior to placement of gravel between the screen and the
perforations.
Casing
Cement
Gravel pack
Screen
Perforation
Formation sand
Anatomy of a casedhole gravel pack.
The gravel is placed
in the perforations
prior to the gravel
being placed in the
annulus.
INTERNAL GRAVEL PACK - IGP
108
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COMPLETIONS
b) Sand Control Using Chemical Methods
These techniques can be broadly divided into two categories; plastic (or in-situ)
consolidation and use of resin coated sand. Historically, these techniques have
been used as a low cost method of stopping sand production in short completed
intervals.
i)
Plastic Consolidation
The objective of the consolidation technique is to treat the formation in the
immediate vicinity of the wellbore with a material that will bond the sand grains
together at their points of contact. This is accomplished by injecting liquid
chemicals through the perforations and into the formation. These chemicals
subsequently harden and bond the sand grains together. For the treatment to be
successful, three requirements must be met;
a. the formation must be treated through all the perforations
b. the consolidated sand mass remains permeable to well fluids
c. the degree of consolidation should not decrease over time
There are two main types of plastic consolidation treatment:
Epoxy Resin: this is pumped in three stages. First a pre-flush containing
isopropyl alcohol is pumped to reduce water saturation (otherwise consolidation
is poor); then the epoxy is pumped; followed by a viscous oil to displace the
resin from the pore spaces (to restore permeability).
Shell use this treatment extensively in West Africa. It has some limitations:
a)
b)
c)
d)
only 10 ft at a time can be treated
reservoir temperature (40°C - 100°C)
clay content (max=20%)
formation water salinity.
Furan and Phenolic Resins:
these chemicals have a much higher temperature
range than Epoxy but the consolidation is often 'brittle' and may fail prematurely.
ii )
Resin Coated Sand
Like a gravel pack, a resin coated sand pack is sized to hold back the formation
sand; however, a resin coating, rather than a screen, holds the pack sand in
position. Working through tubing, gravel pack sand is pumped via coiled tubing
into the perforation tunnels and void spaces outside the casing. After the resin
coating hardens and bonds the gravel together, this consolidated sand pack will
prevent formation sand from entering the wellbore. Excess resin-coated sand is
removed from inside the casing, usually by drilling it out.
Some products mix the resin into the gravel slurry prior to pumping on location
(e.g. Sandlock V process – externally catalysed) or the proppant is delivered to
location already coated and formation temperature alone cures the resin, causing
it to stick together (Bakerbond).
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109
WELL PRODUCTIVITY AWARENESS SCHOOL
Sand Control Method
Cased Hole GP (IGP)
Open Hole GP (EGP)
Milled Window, Underreamed GP
Sand Consolidation
No. of
Wells
6
17
10
20
Productivity Impairment
Skin
Flow Eff.
25
6
11
2
22%
53%
38%
75%
Brunei Shell assume an average skin of +40 (15%
flow efficiency) for their IGPs. Although this is very
low flow efficiency, a gravel pack installation allows
higher sand free production rates than without a gravel
pack, and hence the additional completion expense
can usually be justified.
SHELL SAND CONTROL EXPERIENCE; WEST AFRICA (GABON)
All Types of Sand Control
c) Frac-Pack
Gravel packing is necessary for sand control (where sand consolidation treatments
are inappropriate). Unfortunately (internal) gravel packing can cause skins of +10
to +50, even if strict cleanliness guidelines are followed. Some of the reasons for
this, apart from dirty carrier fluids, might be:
•
•
•
•
•
•
difficult to get all perforations effectively packed with gravel
mixing of gravel and formation sand in perforation tunnels
migrating fines due to high near well bore fluid velocities
poor vertical communication in laminated reservoirs
poor communication of the perforations to good reservoir quality rock
trapped fines in the formation which might otherwise clean up
To overcome these difficulties with high skins on IGP’s a technique that
combines fracturing technology (see Section 5) with sand control was invented:
the frac- pack..
The first evidence of frac-packs can be found in Venezuela in the sixties. The
procedure did not appear to be adopted worldwide. In 1985 BP Alaska
experimented with the ‘new’ technique called ‘Frac-Pack’ in the heavy oil
deposits. The treatment which combines frac-stimulation technology with gravelpacking, was successful; but the heavy oil development was halted due to global
oil economics. However, the technique has now reached fruition in the Gulf of
Mexico, where the technology has become increasingly refined, resulting in an
average 2-3 fold increase in productivity compared with IGP’s, and skins of zero,
or even negative values.
110
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COMPLETIONS
Note: Frac-packs do not
have to be selectively
perforated.
Screen
Casing
Cement
Damaged
Zone
Frac-pac with
proppant
Weak layer of
reservoir not
perforated
Consolidated
formation
STRONG
Layer requiring
sand control
WEAK
Consolidated
formation
STRONG
Stronger levels (not prone
to sand production) of
reservoir perforated. Oil
from weaker layers flows
through the frac to the
perforations without
producing sand
SPECIAL APPLICATION OF FRAC-PACK
The frac-pack procedure creates a relatively short, highly conductive fracture
which will breach the near-wellbore damage, reduce the drawdown and nearwellbore velocity and stresses, and increase the effective wellbore radius. The
treatment has three key stages:
i) formation breakdown - fracture initiation
ii) fracture created - terminated by tip screen-out.
iii) fracture inflation and packing.
The most important criteria for a good frac-pack is fracture conductivity . The
proppant - or gravel - in the frac needs therefore to be as coarse as possible; but
this conflicts with the requirement that proppant size should be kept small for
effective sand control. Initially the gravel in frac-packs was sized according to
Sauciers criteria (d5o of the proppant should equal five to six times the d5o of the
formation sand). However the situation in a frac-pack well is different from a
gravel-packed well, since the fluid velocities are lower in a frac-pack and the
same production can be achieved with a lower drawdown. Operators have found
that they are able to put a larger proppant in a frac-pack than Saucier’s criteria
suggests. In the Amberjack Field, for instance, BP have stepped up from a 40/60
gravel to 20/40 ceramic beads (larger particles = larger pore-throats; more even
round grains = enhanced permeability) without loss of sand control. Skins have
gone from +3 to -0.5.
A frac-pack does not get away from the need for a screen in the well, unless
resin-coated gravel is pumped. At present most frac-pack wells are completed
with screens, but there is an increasing pace in the development of resins and
resin-coated gravel.
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111
WELL PRODUCTIVITY AWARENESS SCHOOL
A special application of this type of treatment has been successfully pioneered by
Oryx Energy in the USA, where resin-coated gravel slurries are used in
overbalanced perforating. The very high perforating pressures fracture the
perforation tips, and the instantaneous pumping (of nitrogen) behind the slurry
packs the new mini-fractures.
d) Cleanliness
A gravel packed well will nearly always have a positive skin.This is a necessary
evil to prevent sand production. However, all efforts must be made to minimise
this skin. This is very much an area where everyone on the rig can influence the
success of a well. All equipment, tanks, lines and tubulars must be very very
clean. All fluids must be filtered. Completions must use minimal tubing dope.
Remember that the gravel pack will effectively stabilise any formation damage
existing in the formation. It is therefore imperative that as much damage
(e.g. filter cake, filtrate, perforation debris) be removed as possible prior to the
gravel-pack being placed.
112
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COMPLETIONS
Intersected Natural Fracture
Hydraulically-Induced Fracture
Deviated Hole
BETTER THAN BASE CASE PERFORMANCE
Partial Penetration
Fractured Reservoir
Poor Perforation
Formation Damage
Low K
POORER THAN BASE CASE PERFORMANCE
Revision 2: 2001
113
WELL PRODUCTIVITY AWARENESS SCHOOL
The wells are now cased and perforated:
Cased and perforated well. No formation damage.
Poorly perforated. No formation damage
Production Rate 10040 bopd Skin = -0.9
Production Rate 7200 bopd Skin = +1.9
Cased and Perforated
16" Perforations, 6 spf, 80 degree
No Damage
Fully Completed
Vertical
Cased and Perforated
8" Perforations, 2 spf, 180 degree
No Damage
Fully Completed
Vertical
The equivalent undamaged open hole completion
with a skin of zero produced 8910 bopd.
WASP-3: Same reservoir as Wasp-1
Well is now cased and perforated
Same reservoir as but with formation damage.
Production Rate 6480 bopd Skin = +3
Cased and Perforated
16" Perforations, 6 spf, 80 degree
80% Permeability Reduction
2 Feet of Invasion
Fully Completed
Vertical
114
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COMPLETIONS
Completion Skin: Good Perforations
Drilled with Poor Mud Giving Damaged Zone.
Well Engineered Perforations
Production Rate 9380 bopd Skin = -0.4
Cased and Perforated
16" Perforations, 6 spf, 80 degree
80% Permeability Reduction
1 Foot of Invasion
Fully Completed
Vertical
The equivalent open hole
completion had a Skin of
+5.4 and produced
5320 bopd.
Deeper Invasion Perforations Cannot Reach
Past the Damaged Zone.
Production Rate 6480 bopd Skin = +3
Cased and Perforated
16" Perforations, 6 spf, 80 degree
80% Permeability Reduction
2 Feet of Invasion
Fully Completed
Vertical
The equivalent open hole
completion had a Skin of
+7.6 and produced
4570 bopd.
Completion Skin: Poor Perforations
One Foot of Invasion
Very Poorly Perforated
Production Rate 3100 bopd Skin = +15
Cased and Perforated
8" Perforations, 2 spf, 180 degree
80% Permeability Reduction
1 Foot of Invasion
Fully Completed
Vertical
Two Foot of Invasion
Very Poorly Perforated
Production Rate 2830 bopd Skin = +17.2
Cased and Perforated
8" Perforations, 2 spf, 180 degree
80% Permeability Reduction
2Feet of Invasion
Fully Completed
Vertical
The equivalent open hole
completion had a Skin of
+5.
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115
WELL PRODUCTIVITY AWARENESS SCHOOL
Completion Skin: Partial Penetration (of Reservoir)
Same reservoir as Wasp-1 but only partially completed.
Same reservoir as Wasp-5 but with Formation Damage.
Production Rate 6250 bopd Skin = +3.4
Production Rate 4980 bopd Skin = +6.3
Open Hole
No Damage
Top 100 ft Completed
Vertical
Open Hole
50% Permeability Reduction
2 Feet of Invasion
Filter Cake Removed
Top 100 ft Completed
Vertical
WASP-5
Completion Skin: Deviated Well
Same reservoir as Wasp-1 but drilled at high angle.
Same well as Wasp-6 but with formation damage.
Production Rate 11500 bopd Skin = -1.8
Production Rate 6360 bopd Skin = +3.2
Open Hole
No Damage
Filter Cake Removed
Fully Completed
55 Degrees
Open Hole
80% Permeability Reduction
2 Feet of Invasion
Filter Cake Removed
Fully Completed
55 Degrees
WASP-6
116
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COMPLETIONS
Same reservoir as Wasp-6 and same inclination, but
cased and perforated.
Same well as Wasp-7 but with formation damage.
Production Rate 12980 bopd Skin = -2.5
Production Rate 9140 bopd Skin = -0.2
Cased and Perforated
16" Perforations, 6 spf, 60 degree
No Mud Damage
Fully Completed
55 Degrees
Cased and Perforated
16" Perforations, 6 spf, 60 degree
80% Permeability Reduction
2 Feet of Invasion
Fully Completed
Vertical
WASP-7
Completion Skin: Gravel Packs
Same Reservoir as before. External Gravel Pack
necessary.
Production Rate 6310 bopd Skin = +3.3
Open Hole (Under-reamed to 12.25")
10D Gravel
No Mud Filtrate Damage
Fully Completed
Vertical
WASP-8
Revision 2: 2001
Same well as Wasp-8 but with Internal Gravel Pack
Production Rate 5940 bopd Skin = +4
8" Perforations, 0.6" Diameter
6 spf, 90 degree Phasing
10D Gravel
No Mud Damage
Fully Completed
Vertical
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WELL PRODUCTIVITY AWARENESS SCHOOL
Completion and Mechanical Skin in Gravel Packs
Same well as before, IGP but in Damaged Formation
Same well as before but Formation Severely Damaged
Production Rate 4570 bopd Skin = +7.6
Production Rate 2120 bopd Skin = +25.6
8" Perforations, 0.6" Diameter
6 spf, 90 degree Phasing
10D Gravel
40% Permeability Reduction
2 Feet of Invasion
Fully Completed
Vertical
8" Perforations, 0.6" Diameter
6 spf, 90 degree Phasing
10D Gravel
80% Permeability Reduction
2 Feet of Invasion
Fully Completed
Vertical
Example of Frac-Pac to overcome high gravel-pack skin
Production Rate 8910 bopd Skin = 0
8" Perforations, 0.6" Diameter
6 spf, 90 degree Phasing
10D Gravel
Mud Damage Bypassed By Fracture
Fully Completed
Vertical
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COMPLETIONS
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119
WELL PRODUCTIVITY AWARENESS SCHOOL
120
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S T I M U L AT I O N
Stimulation
122
Acidisation
Candidates for Acidisation
Acid Systems
a. Hydrochloric Acid
b. Mud Acid
c. Organic Acids
d. Additives
123
124
124
125
127
127
Treatment Types
a. Bullheading vs. Coiled Tubing
b. Acid Washes
c. Matrix Acidisation
d. Acid Fracs
128
128
130
130
134
Formation Damage During Acidisation
a. Corrosion
b. Iron Reprecipitation
c. Fluid Incompatibilities
d. Fines Mobilisation
e. Liquid Block in Gas Wells
f. Cement Bond Destruction
g. Prevention
135
135
135
135
136
136
137
137
Microbes as an aid to Well Production
139
Hydraulic Fracturing
141
Basics of Fracturing
Treatment Types
a. Acid Fracs
b. Propped Fracs
141
145
145
145
Identifying Candidates
a. Gas Wells
b. Oil Wells
c. Conventional & Tip Screen Out Treatments
d. Deviated & Horizontal Wells
e. Water Injectors
148
149
150
150
151
153
Formation Damage During Fracturing
153
MODULE SUMMARY
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123
156
121
WELL PRODUCTIVITY AWARENESS SCHOOL
Stimulation
At the end of this module you should be aware of:
• The types of well which may benefit from stimulation
• When to consider acid stimulation
• When to consider hydraulic fracturing
• How damage can occur during stimulation treatments
• Techniques to improve stimulation performance
• Potential improvements in productivity after stimulation
• Typical skin factors expected after stimulation
Why Stimulate
Native
permeability
very low.
?
To by-pass
near-wellbore
damage
Low K
Why would we stimulate a well in the first place? There are two main reasons:
either the native permeability of the reservoir is so poor in the first place that the
well/field is not economically viable, and would not be produced without
stimulation, such as some southern N. Sea gas wells/fields; or the near-wellbore
region has been damaged and a stimulation treatment is necessary to by-pass the
damage and restore the well productivity. The first reason is unavoidable; the
second is best avoided by not damaging the well in the first place.
Generally, acid stimulation is most suited to carbonate formations and for the
clean-up of acid soluble damage, carbonate muds and kill pills; hydraulic fracturing
to low permeability sandstones and formations with non-soluble formation damage..
STIMULATION
- as a general rule ...
!
Hydraulic
Frac
Acid
122
Most suited to
CARBONATE
Formations
Most suited to Low
Permeability
Sandstones
Removing
acid soluble
damage
Fracturing past
formation damage
Revision 2: 2001
S T I M U L AT I O N
Prevention is better than Cure
Formation Damage cannot always be removed by acid.
Consider your choice of mud and completion fluid carefully
Acidisation
Candidates for Acidisation
Acid will not solve all well productivity problems. Acidisation is fraught with
problems and can damage a formation rather than stimulate it, if the job is not
planned properly.
Not all wells can be improved with acid. Before contemplating an acid job, the
well/wells must be studied carefully to see whether or not they will truly benefit.
There may be reasons other than formation damage that are restricting productivity.
Causes of Poor Productivity Other Than Acid Soluble Damage
High liquid/gas ratio in a gas well >100 bbl/MMscf
High gas/oil ratio in an oil well >1000 scf/bbl
Three phase production: water, oil and gas
High pressure drawdown >1000 psi
High Flow Rate >20 bbl/day/ft
> 5 bbl/day/shot
Sub-optimal perforating
Inefficient lift in the tubing
= Non-Dary effects in gas wells
= turbulent flow = pressure losses
Completion skins
Gas breakout if producing below bubble point
In general, an acid job falls into one of three categories:
i) Hydrochloric acid (HCl) in carbonate reservoirs to etch new channels
of communication
ii) Hydrochloric acid in a damaged carbonate-cemented sandstone to
create channels to by-pass the damage
iii) Mud acid (HF) in low-carbonate sandstones, to remove mud damage
or soluble fines.
Organic acids (formic and acetic) do the same job as HCl but they are weaker and
act at slower rates.
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WELL PRODUCTIVITY AWARENESS SCHOOL
ACID TYPES
FORMATION
HCI
HF
Acetic
Carbonates
Sandstones
(>15%
carbonates)
Sandstones
(<15%
carbonates)
Think carefully about what you want the acid to do, before you start designing
the acid job and ordering the chemicals and equipment.
Acid Systems
a) Hydrochloric Acid
Hydrochloric (HCl ) is the most widely used acid. A concentration of 15% is most
common, but 7.5% and 28% can also be found. It dissolves carbonate materials
such as calcite, dolomite and siderite. Iron oxide (rust) is also dissolved, or just
dislodged from the tubing..
2HCl + CaCO 3 ⇔ CaCl 2 + H2 O + CO2
Matrix acidising of carbonates started as long ago as 1896 in the USA.
Hydrocarbon production was found to increase by three to four fold, but the
treatments severely corroded the casing. Thus the popularity of this stimulation
declined until 1931 when Dr. John Grebe of the Dow Chemical Company
discovered that arsenic inhibited the action of HCl on metal. The volume of work
that this generated led to the founding of Dowell.
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S T I M U L AT I O N
DENDRITIC PATTERN OR ‘WORMHOLES’ FORMED BY HYDROCHLORIC ACID
IN A CARBONATE
It is important that the acid reaction only produces soluble products. Some
impurities in limestone and dolomite are insoluble in acid, and if appreciable
percentages of such components are present, special additives must be included
in the acid solution to ensure their removal.
b) Mud Acid
Mud Acid is a mixture of hydrofluoric acid (HF) and hydrochloric acid, usually 12%
HCl and 3% HF, but low strength mud acid (6% HCl and 1.5% HF) is also used.
Mud acid is used primarily to remove clay-particle damage in sandstone formations,
to improve near-wellbore permeability of clay-containing formations and to
increase solubility of dolomitic formations. Its utility is based on the fact that some
clays, silica, and other materials, normally insoluble in HCl, have some degree of
solubility in HF.
HF+'clay' → Si,Al in solution
quickly
HF+'quartz' 
→ Si in solution
slowly
( H 2 SiF 6 )
H2SiF 6 +'clay' → Al + Si( OH) 4
amorphous silica precipitate
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125
WELL PRODUCTIVITY AWARENESS SCHOOL
0.4
0.4
MUD ACID
0.3
0.3
0.2
0.2
0.1
MUD ACID
0.1
REGULAR ACID (HCl)
HCl
0
0
6
12
18
Time of Contact in Hours
0
24
0
Solubility of Bentonite in Acid
6
12
18
Time of Contact in Hours
24
Solubility of Silica Sand in Acid
HF reacts with sodium, potassium and calcium to form insoluble
precipitates. HF may also produce insoluble by-products such as colloidal silica
as a result of actions with the rock. Consequently a pre-flush of HCl must always
be used to:
a.
b.
c.
Displace formation water containing potassium, sodium or calcium ions.
If this is not done a range of fluosilicates {e.g. K2SiF6} or fluoaluminates of
varying solubility can form due to the HF reaction.
Maintain a low pH in the near wellbore region throughout the treatment to
avoid various precipitation reactions.
Dissolve carbonates which could produce insoluble fluorides (e.g. CaF2).
Never use HF with Carbonates
Mud Acid
HF + CaCO3 =
CaF2
+ CO2 + H2O
Always pre-flush the
formation with HCI to
remove carbonates
Also remove sodium,
potassium and calcium
ions to prevent the
formation of insoluble
fluosilicates and fluoaluminates
Precipitate = Formation Damage
The fluid used to displace HF should not contain sodium, potassium or calcium
ions. Ammonium chloride, HCl or diesel is often used to flush the near wellbore
area immediately following the mud acid; thus if any precipitates are formed they
are as remote as possible from the near-wellbore region.
+
H 2SiF 6 + 2K → K 2SiF 6 precipitate
CaCO 3 + 2HF → CaF 2 precipitate + CO2 + H 20
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S T I M U L AT I O N
c) Organic Acids
These acids are used less frequently, although there is an increasing tendency to
use them to remove carbonate LCM in gravel-packed completions. Organic acids
(acetic and formic ) dissolve carbonate materials in the same manner as HCl but
at a much slower rate. These are used in high temperature wells (greater than
250°F), or those with high alloy tubing (e.g. 316 stainless steel in wire-wrapped
screens), where unacceptably high corrosion rates would otherwise be obtained
with HCl (even with corrosion inhibitor). The slower reaction rate also allows
use of these acids to achieve deeper penetration in carbonates, where HCl would
spend quickly in the vicinity of the wellbore.
The maximum concentration for Formic Acid used in the field is 15%; otherwise
insoluble calcium formate will precipitate. Likewise acetic acid is never used in
concentrations greater than 10% or calcium acetate is precipated.
d) Additives
i)
Corrosion Inhibitors
These are generally dissolved in the acid to eliminate 95% to 98% of the metal
loss that would otherwise occur. Most inhibitors have practically no effect on the
reaction rate of the acid with the formation. The length of time an inhibitor is
effective depends on the acid temperature, type of acid, acid concentration, type
of steel, and inhibitor concentration. Be aware that these inhibitors are often
highly damaging since they can change the wettability of the formation.
ii)
Surfactants
Surfactants are chemicals that are used to lower the surface tension or interfacial
tension of fresh acid or spent acid solutions. This allows the acid to penetrate
deeper into a formation, and allows easier passage of spent acid when the well is
produced back. Surfactants also act as demulsifiers to inhibit the occurrence of
emulsions (acid/oil) or destroying those already formed. A mutual solvent is a
form of surfactant that helps prevent the formation of sludges or emulsions, and
may assist in particle migration/clean-up by preventing the stabilisation of
emulsions by fine particles. A mutual solvent can also remove a damaging oilwetting phase from a rock (for instance where oil-based mud has rendered a
previously water-wet rock oil-wet, thus forcing the water into the pores causing a
blockage) and surfactants can re-establish the water-wet conditions allowing the
oil to flow.
iii)
Clay Inhibitors
These prevent various clays and silts from swelling and blocking pores and pore
throats.
iv)
Iron Control Agents
A sequestering agent prevents the precipitation of iron salts when the acid spends.
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WELL PRODUCTIVITY AWARENESS SCHOOL
A reducing agent will convert ferric ions to ferrous irons, and these will not
precipitate until the pH is above 7 (which will not happen in the spent acid). In
a sour well, where H2S is present, complexing agents are needed to prevent the
precipitation of ferrous sulphide.
v)
Gelling or Fluid Loss Agents
Natural gums and synthetic polymers are sometimes added to the acid to increase
the viscosity of the acid solution to slow down its leak-off into large pores or
fractures.
vi)
Nitrogen
Nitrogen can be added to the acid to energise it; to assist flowback and clean-up.
vii) Retardants
To slow down the reaction of the stimulation, either slower-acting acids such as
formic and acetic acids may be used, or retardants are mixed with HCl or HCl/HF.
Treatment Types
Two things need to be considered here
• how are we going to get the acid to the reservoir?
• what sort of acid job are we going to perform?
a) Bullheading vs. Circulating
Acid Treatments
Methods of getting acid
to the formation
Bullheading down production
tubing
OR
Circulating via
Coiled Tubing
OR
Circulating via Dedicated
Work String
Beware of potential
damage from rust, scale,
dope or dirt being forced
into the formation.
Coiled tubing may restrict rates
Dedicated work string must be
scrupulously clean
ACID WASH
= Small volume
Cleans perforation only
MATRIX ACIDISATION = Large volume
Full acid job reaching the rock matrix
well into the near wellbore region
Pumped at below frac pressure
ACID FRACS
= Fracturing of rock with acid medium to
etch the surface of frac
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S T I M U L AT I O N
In 1990 Paccaloni of AGIP studied 650 matrix acidising jobs world-wide. He
estimated that 12% were outright failures; and that 73% of these failures were due
to poor field practice. Just 27% of the failures were caused by incorrect choice of
fluids and additives. Reasons for poor field operation centred on the technique of
bullheading ; when acid is pumped into the well down the tubing, pushing dirt,
scale, rust and dope from the tubing, and whatever fluids are below the packer –
often mud – directly into the formation. Therefore, wherever possible, coiled
tubing or a dedicated workstring should be used to circulate the acid into place
and then pump it away. Check that these are clean and not recently used for a
cement job (the acid will dissolve residual cement, and carry it into the formation
where it will plug).
Coiled
tubing reel
Matrix fluid tank
Pump unit
Injector head
BOPs
Coiled tubing
Circulating valve
Matrix acidizing with the
Formation Selective
Treatment (FSTS) system
on coiled tubing. The FSTS
tool comprises an injection
port between two inflatable
packers. A circulating valve
just above the tool obviates
the need to push large
volumes of well fluid into the
formation before the acid.
For less efficient spotting of
acid, coiled tubing can be
pushed to the end of the
hole and slowly withdrawn
while acid and diverting
agents are pumped.
Liner
Schlumberger Oilfield Review
MATRIX ACIDISING THROUGH COILED TUBING AND
STRADDLE PACKER
If the choice of treatment precludes the use of coiled tubing (e.g. the ball sealers
will jam in the CT or CT does not permit the desired rates and/or pressures) then
take all the precautions possible to ensure that the tubing is clean, even to the
extent of ‘flexing’ (pressure the string to cause ballooning of pipe to break off any
flakes of rust) and ‘pickling’ it with acid before the main job is pumped. The ‘dirty’
sump fluids might be circulated out in a similar manner, and replaced with a
clean non-damaging fluid. Everything must be done to avoid ‘solids’ getting into
the perforations and the formation, where they will cause permanent damage.
If a dedicated work string has to be run then the well might have to be killed –
which might itself cause damage!
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WELL PRODUCTIVITY AWARENESS SCHOOL
b) Treatment Type
i)
Acid Washes
Acid is circulated past the perforations, often with coiled tubing; pumping is then
stopped and the acid allowed to feed into the formation under hydrostatic
pressure (sometimes a small pressure is applied). The treatment is rarely longer
than one hour, and the well is immediately produced back to remove the acid
and its by-products.
ii)
Matrix Acidisation
The simple aim of matrix acidising is to dissolve away formation damage or
create new pathways within several inches to a foot or two around the wellbore.
The treatment is pumped at a pressure below formation fracture pressure. The
volume of acid pumped (per foot of perforation) can be calculated in the same
manner as the depth of invasion. To penetrate 3 ft into a formation in an 8 1/2”
wellbore will require approximately 42 gallons of acid per foot of reservoir.
Often volumes are much higher: at 50-100 gallons/ft.
Formation damage mineralogy
Diagnostics
Well completion data
Damage type
Damage removal
mechanism
Fluid selection
adviser
3% HF, 12% HCl
Fluid description
Fluid sequence
Risk analysis
Pumping schedule
advisor
Volumes
Number of diverter stages
Injection rates
Preflush 15% HCl, Surf, Cor. Inh.
Main flush 3% HF, 12% HCl, Surf.
Overflush 5% HCl, Surf, Cor. Inh.
Simulator
Flow profile evolution
Skin evolution
Rate/pressure plots
Production
prediction
Production rates
Payout time
PLANNING A MATRIX STIMULATION
130
Product mapping
Preflush 15% HCl, F78, A260
Main flush RMA, F78, A260
Overflush 5% HCl, F78, A260
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S T I M U L AT I O N
It is important to understand the ‘reaction rate’ of an acid you plan to use. This,
correlated with reservoir and formation characteristics, form a guide for the
selection of acid type and the volume for a given treatment. Next, a study of
these factors can furnish an understanding of what parameters govern spending
time, which will determine how far a given formulation can penetrate into a
formation before spending. Many factors govern the spending rate of an acid,
such as pressure, temperature, flow velocity, acid concentration, reaction
products, viscosity, acid type, area/volume ratio, and formation composition
(physical and chemical).
What is going to affect the acid reaction rate and therefore how
deeply the stimulation is effected?
• ACID TYPE
• PRESSURE
• TEMPERATURE
–
Choose the acid that will dissolve more rock/damage
–
Above 500 psi pressure does not have much effect in acid reaction rates
–
Higher temperatures lead to faster reaction rates. Remember that the
injected acid will cool the formation
• FLOW VELOCITY
–
Increased flow velocities can increase reaction rates
• ACID CONCENTRATION
• AREA/VOLUME RATIO
–
With HCl, higher concentration leads to faster reaction, up to 25%
–
The area in contact with the acid over a given time; inversely proportional to
the pore radius or fracture width - more area leads to quicker reaction. For
example, a 10mD, 20% porosity limestone may have an A/V ratio of 28,000
to 1. In such a formation it would be difficult to obtain significant penetration
before spending
If pumping an acid treatment to remove formation damage, HCl acid in a carbonate
will tend to etch new paths around any formation damage; whereas mud acid in
sandstones will try and dissolve away the actual damage itself.
A pre-flush is pumped to flush out any undesirable minerals/fluids in the rock.
This is followed by the acid itself; followed by a postflush to push the spent acid
back into the formation and away from the near-wellbore region (to push any
potential damage as far away from the well as is practical).
Apart from the insoluble precipitates that may form in a sandstone acidisation,
there is always the risk of mobile fines being generated; thus it is sometimes
recommended that injection rates be decreased and/or that retarded systems be
used to slow down the acid reaction to try and prevent fines being dislodged.
Dowell have recently introduced a retarded system utilising fluoboric acid (HBF4)
that reacts with (formation) water to generate HF in situ (sometimes known as
Self-Generating Mud Acid). The slow rate of this conversion allows deep
penetration of the HBF4 and thus of HF. As a bonus, the fluoboric acid itself
reacts with the clays and silt, forming borosilicates that appear to help bind the
fines to large sand grains.
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131
WELL PRODUCTIVITY AWARENESS SCHOOL
4000
3000
Mud acid treatment
2000
1000
0
Fluoboric acid
treatment
0
1
Production improvement in a
Nigerian oil well after fluoboric acid
treatment. The well was initially
acidized with mud acid and
produced 850 barrels of liquid per
day (BLPD) with a 34% water cut.
Production then declined almost to
zero, most likely due to fines
movement. After fluoboric acid
treatment, production rose to 2500
BLPD, obviating the need for
further acid treatments. Oil
production a year after the
treatment was 220 BOPD.
2
Time, yr
Schlumberger Oilfield Review
USE OF CLAY STABILISER TO PREVENT FINES MOVEMENT
An important part of matrix acidising is the ‘art’ of diversion . Diversion of acid is
necessary, because in the treatment of a large interval (more than 10 ft), the first acid
to hit the formation will generally enter the zone that already has the least damage
or the best permeability, and it will increase the permeability of that immediate area
even further (if the design is correct!). Subsequent acid preferentially enters this
zone and the remainder of the interval will receive little or no stimulation, unless the
acid is diverted. Various methods of diversion can be used:
Why Diversion?
Without diversion all the acid would
go into the most permeable zone or
the least damaged and the majority of
rock would remain unstimulated. A
properly planned diversion should
ensure that all the reservoir is
stimulated.
Straddle packer: a positive means of diversion, where twin packers are used
to isolate intervals one at a time. The method is effective but costly because of
the time taken.
Ball sealers: these are nylon balls with hard cores that are designed to seal
across any perforation taking acid. Ideally the balls have a density close to, or
slightly less than, the acid. The treatment is pumped in stages: preflush; acid;
ball sealers; acid; ballsealers, acid etc. (A postflush might be pumped after each
acid stage). Buoyant balls are caught in ‘ball-catchers' at surface; if the balls
are heavier than the fluids they sink to the bottom of the rathole.
Particle materials:
benzoic acid flakes which dissolve in hydrocarbons, oilsoluble resin and materials that melt at a certain temperature are used as diverting
agents. They are added continuously or intermittently to build up a filter cake
across any interval taking acid. Clean up of these agents after a treatment can be a
problem, i.e. not all the oil-soluble resin may dissolve in the produced oil.
Particulate diverting agents are generally not effective in fractured formations.
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S T I M U L AT I O N
DIVERSION
Particulate Diverters
- Benzoic Acid
- Oil Soluble Resin
- Temp sensitive
chemicals
Ball Sealers
Balls are pumped
down the well
and seal
against
the zone taking
fluid at that time
Straddle Packer
- Expensive
- Accurate
Foam
Acid will now flow
into the untreated
portion of the
reservoir
- Nitrogen & soap
- Blocks by surface tension
- Efficiency improved by surfactant
F o a m : foamed acid is becoming popular, but relative permeability effects make
it difficult to pump large amounts of acid into any given interval. Foamed acid
is useful in diverting a long horizontal section in an open-hole completion.
Openhole completion?
Chemical
Gravel packed?
Yes No
Chemical
Coiled tubing
available?
Yes No
Mechanical
Yes No
Chemical
Staged treatment
required?
Yes No
Chemical
Flowback of
balls a problem,
or high shot density?
Yes No
Mechanical ball sealers
CHOOSING A DIVERSION METHOD FOR MATRIX ACIDISING
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WELL PRODUCTIVITY AWARENESS SCHOOL
Generally a matrix acidisation is far cheaper method of stimulation than a ‘frac
treatment’ (with or without acid), but unfortunately acidisation is not always the
best way to increase productivity.
Stage 1
Stage 2
1
2
3
4
5
6
7
8
Step
Fluid
Volume
bbl
Flow rate
bbl/min
Time
min
Preflush
Main fluid
Overflush
Diverter slug
Preflush
Main fluid
Overflush
Tubing displ.
HCl 15%
RMA 13/31
HCl 4%
J237A2
HCl 15%
RMA 13/31
RMA 13/31 4% HCl
NH4Cl brine 3%
17.3
68.2
33.0
3.1
17.3
55.6
53.7
33.0
2.2
2.2
2.4
4.8
4.8
1.1
1.1
1.2
7.9
31.0
13.8
0.6
3.6
50.5
48.8
27.5
1. Regular Mud Acid, 13% HCl, 3% HF.
2. Four-micron particulate oil-soluble resin, usable up to 200 °F.
TYPICAL STAGED MATRIX ACID JOB
Time for pumping = 3 hrs
iii)
Acid Fracs for Carbonates
In acid fracs, HCl is used in carbonates to create a conductive fracture which can
bypass damage and/or stimulate low permeability formations. The faces of the
fracture are etched by the acid, so that after the fracture closes, some flow
channels remain open. It is not effective where:
a.
b.
c.
The rock has an acid solubility of less than 80%
The rock is too soft to support an etched fracture – a Brinnell
hardness of at least 100MPa is recommended; and if porosity is
greater than 40% problems can also be expected.
Core testing is necessary to ensure a successful treatment.
The conductivity of acid fractures can reduce with time, so in some instances
propped fracturing should be considered in carbonates (e.g. in chalk). Acid
fracturing in sandstones is not a common practice.
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S T I M U L AT I O N
Formation Damage During Acidisation
This section is critical: too many people plunge ahead with acid jobs thinking that it
will solve all their problems, without first considering the downside.
FORMATION DAMAGE DURING ACIDISATION
‘Pickle’ the tubing before pumping
any acid to minimise damaging
ferric irons in the spent acid
Use corrosion inhibitors – but
beware that excess inhibitor could
itself cause damage
Corrosion
Fluid Incompatibilities
Iron Precipitation
ACID
Liquid Block in Gas Wells
Fines Mobilisation
Beware of acid and oil forming an
emulsion or sludge – possibly
encouraged by iron in the acid.
Beware of acid mixing with
remains of oil-based mud. Beware
surfactants.
caused by
spent acid (esp.
in low pressure
wells.)
HCI may cause silica
fines to be released
from clays. HF may
precipitate silica fines.
a) Corrosion
Acid dissolves the tubing. This is minimised by adding corrosion inhibitor. Most
corrosion inhibitors are not soluble in acid and, if used in excessive quantities,
will damage the formation by changing the wettability. Particular care is needed
in chrome tubulars where special inhibitors are required.
b) Iron Reprecipitation
The pH of spent acid will rise, which can reprecipitate any iron that has been
dissolved. The damaging ferric ions are dissolved from the wall of the tubing as
the acid is pumped downhole. To avoid this it is good practice to ‘pickle’ the
tubing before the treatment by pumping acid to the end of the tubing and then
reverse circulating it out with the dissolved iron. This will also remove any other
debris that might be removed from the walls of the tubing during acidisation.
c) Fluid Incompatibilities
Acid may form emulsions or sludges on contact with formation oil. Drilling
muds, especially oil-based muds, which may still be in the near wellbore region,
can also create emulsion problems. Sludge precipitation can be encouraged by
iron in the acid. Various surfactants can be pumped to alleviate these problems,
but remember that surfactants themselves can cause problems.
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WELL PRODUCTIVITY AWARENESS SCHOOL
d) Fines Mobilisation
Although HCl does not dissolve clays it does react with them, leaching aluminium
out of the structure. This process produces silica fines which can reduce
permeability. A ‘pH shock’ can also disperse clays, or they can be dispersed by
the dissolution of carbonate cements.. Consequently, HCl acidisation of clay-rich
sandstones can cause a permeability reduction if this is not offset by the removal
of acid soluble material.
Minerals
Surface Area
Solubility HCl
Solubility
HCL-HF
Quartz
Chert
Feldspars
Micas
Low
Low to Moderate
Low to Moderate
Low
No
No
No
No
Very Low
Low to Moderate
Low to Moderate
Low to Moderate
Kaolinite
Illite
Smectite
Chlorite
High
High
High
High
Very Low*
Very Low*
Very Low*
Very Low**
High
High
High
High**
Calcite
Dolomite
Ankerite
Siderite
Low to Moderate
Low to Moderate
Low to Moderate
Low to Moderate
High
High
High
High
High, but CaF2 Precipitation
High, but CaF2 Precipitation
High, but CaF2 Precipitation
High
*
Aluminium and other elements can be leached out of clay minerals leaving
insoluble silica
** Iron removed from chlorite causes potential iron reprecipitation problems
Mineral-Acid Solubility
Mud acid can also cause fines dispersion, in addition, as HF spends itself on clay
minerals it can also precipitate silica. This can cause a permeability reduction if
an excessive amount of acid is used.
The problem of fines migration and permeability loss is most pronounced in low
permeability sandstones, as their smaller pore sizes are more prone to plugging.
In high permeability sandstones the movement of the fines might weaken the
rock, causing sand production problems.
Due to the sensitivity of low permeability clay-bearing sandstones, low strength
mud acid is often used in an effort to minimise these adverse effects (acetic acid
and acid-methanol mixtures have been other alternatives). Clay stabilising
treatments have also been used on such rocks after the acid treatment, to try and
minimise the movement of fines after the job.
e) Liquid Block in Gas Wells
In gas wells, especially low pressure gas wells, spent acid may create a ‘water
block’ around the well. This can take some months to clean up or may
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S T I M U L AT I O N
permanently block production (in West Sole after workover and acidisation,
production takes about six months to return to normal). The effect can be
reduced by the use of surfactants and/or mutual solvents. Alternatively, by
adding nitrogen to the acid a speedy recovery can be encouraged.
f) Cement Bond Destruction
Hot HCl/HF acid can break down cement bonds. This is especially a problem
where poor primary cementing leaves channels in the cement, or where a
previous squeeze cement job has been used to block off water. Arco Alaska have
developed a latex-blended cement that is more resistant to acid.
g) Prevention
Pre-job Planning
PREVENTION OF ACID DAMAGE
• Check acid compatibility with:
–
–
–
–
formation
oil
formation water
tubing
• Do tests with simulated spent acid iron content. Use fresh
oil where possible - oil ages with time
a. Acid compatibility with the oil, brine, old oil-based mud, tubing, and formation
must be checked when planning the job. Check for formation of emulsion and
sludges. Make sure that all acid additives are also checked with the acid. Carry
out return permeability measurements. When checking acid compatibility with
formation water, do so with a simulated iron content of the spent acid and at
reservoir temperature. Where possible use fresh oil, as oil ages with time.
On Site
PREVENTION OF ACID DAMAGE
• Check specifications of all chemicals delivered to site
• Batch mix treatment
• Check that everything is ‘as per design’
• Check that all pipework and equipment is clean
(hardware previously used for a cement job is unsuitable)
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WELL PRODUCTIVITY AWARENESS SCHOOL
Stimulated Completion
Perforation Technique Selection
It is undetermined whether the well needs stimulation. Could underbalance perforating eliminate
the need for stimulation?
or
Stimulation is required. Is any added operational complexity of underbalance perforating justified
by the likely improvement in well cleanup and stimulation?
No
Yes
P erforate overbalance
Perforate underbalance (see
underbalance perforating in
Natural Completion flowchart)
Will perforation be performed through workstring?
Yes
No
Through-tubing guns
Will stimulation benefit from high shot density or reduced phase angle?
(wireline conveyed)
Yes
• Will gun or charge debris be
a problem for downhole
equipment?
or
• Are more than two zones to
be perforated selectively?
Yes
Select correct
diameter of
scallop or high
shot density
gun
compatible
with downhole
restrictions;
select phasing
and shot
density.
Boxes in red
outline denote
final decision
points.
Select correct diameter high
shot density gun compatible
with downhole restrictions;
select phasing and shot
density
Casing guns
(wireline conveyed)
No
Exposed guns
Is well deviation ≥ 60° or is the
interval long enough to justify
running on tubing?
Yes
No
Tubing
conveyed
Wireline
conveyed
Are uniform and circular
entrace holes a high priority?
and
Is 12-in. API section 3
Yes
Selectric
system
THIS APPLIES FOR ACID AND FRAC STIMULATION
138
No
No
Is limited entry perforating
required?
Yes
No
Is the well ≤ 4000 psi, <210°F
[99°C]?
Yes
No
High Energy
Guns
Port plug
guns
Port plug
guns
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S T I M U L AT I O N
b. Check the acid and additives supplied on-site are as specified. Batch mix the
treatment; do not allow it to stand unagitated as chemicals may separate.
Check everything is mixed as per design specifications.
c. Check that all pipework is clean. Pipework previously used for a cement job
is not suitable (acid + cement reduces acid strength and potentially damaging
products may form). If coiled tubing is to be used, check its age, its previous
history and its present day cleanliness.
d. Check maximum wellhead pressure for the job: be it the formation fracture
pressure or the wellhead rating that dictates
e. Collect return acid samples; look for emulsions, sludge; measure iron
concentration to check that sufficient sequestering agent was used.
f.
Throughout the acid job, monitor and record all the parameters accurately.
The results of the job (pre-job vs post-job rates, and a subsequent well test)
should be carefully matched with the expectations of the treatment to
evaluate its effectiveness.
All the above precautions must be borne in mind when contemplating, planning
or executing an acid job.
•
•
•
•
•
Think carefully about how acid is going to improve the permeability/reduce the skin
Experiment with cores where possible
Consider possible damage from acidisation. Take precautions to minimise
Supervise/quality control job carefully
Evaluate job as critically as possible to improve future acidisations
One great advantage that acid stimulations have over fracture stimulations is cost.
Typically in the North Sea:
•
•
An average figure for an acid job might be $100,000
A frac will cost nearer $600,000.
(counting service company costs only)
On land in the USA for instance, the frac will probably be much cheaper than
$600,000, but will still be more expensive than the acid job.
Microbes as an Aid to Well Production
As oilfield hydrocarbons were originally formed by microbial action millions of
years ago, it should be possible to use microbes again to change the properties of
reservoir fluids in such a way as to improve oil production and recovery.
The most common approach considered is to pump down, into the reservoir,
microbes, which will then feed on the crude oil and multiply, in the process
breaking down long-chain hydrocarbons into shorter chains. Thereby, lowering
the viscosity of the crude oil, increasing its mobility and reducing any tendency to
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WELL PRODUCTIVITY AWARENESS SCHOOL
paraffin wax precipitation. In some processes, this same reduction of viscosity is
achieved, or aided, by formation of organic solvents by microbial action.
Common by-products of this process are surfactants, which reduce the interfacial
tension between oil and water, thus improving the oil recovery from water flood
projects. Another common by-product is carbon dioxide, which provides a
limited amount of energy, gas pressure, to help force the reservoir fluids towards
the wellbore.
In some projects, Microbial Enhanced Oil Recovery (‘MEOR’), is applied reservoirwide, by pumping the microbes down with injection water on a continuous, or
near-continuous, basis. In others, the microbes are squeezed in batches into the
reservoir in oil producing wells, typically 3-5 feet into the formation, which, after
being left up to two weeks for the microbes to multiply and act on the oil in situ,
are flowed back. The resulting modification of the reservoir fluid properties near
to the wellbore, gives lower near well-bore pressure losses, lower skin and an
improvement in well productivity.
After a large initial increase in production, this declines, so treatments are usually
repeated every three to six months. A recently reported series of such treatments
in four wells in Venezuela, for example, gave a more than doubling in average oil
production over approximately half a year of post-treatment production. In
addition to Venezuela, field MEOR projects have also been implemented in
Australia, China, Rumania, Russia and the USA, with approximately ten thousand
wells benefiting from MEOR Worldwide.
Indegenous Thermophillic Coccoid
Bacteria growing in reservoir core
material at 90°
In addition to reduction in near well-bore
pressure losses, microbial treatments are used
for other purposes. For example, some
microbes compete with Sulphate reducing
bacteria (‘SRB’) for food, and, when introduced
into the reservoir, will literally eat the SRBs
lunch, resulting in a reduction of the SRB
population and hence in the H2S content of the
produced oil. This increases the value of the
crude oil and reduces corrosion. Sometimes the
reduction in wax content is primarily aimed at
reducing plugging of flow-lines and well
tubing, so as to reduce well maintenance costs.
Another application being researched is the
creation of biomass in situ, to block-off water
producing sands adjacent to the wellbore.
Obviously, different microbes are used for
different purposes, and it is very important that
laboratory tests with the actual crude oil are
made before any field trials are conducted.
Though the use of microbes to improve oil production was first proposed as long
ago as 1926, field applications remain limited outside the USA, many projects
being little more than field trials. MEOR is however, the subject of numerous joint
oil industries, governmental and academic research programmes, particularly in
the USA, Norway, Australia and the UK. Use of microbes to improve oil
production holds much promise for the future.
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S T I M U L AT I O N
Hydraulic Fracturing
Basics of Fracturing
width
Propped hydraulic fracturing is of major
importance to BPX and many other oil
companies world-wide. Successful fracture
treatments may increase the productivity of
a well up to 400% relative to a zero skin
well. This may result in substantial capex
length
savings (less wells per field necessary), or
it may extend the economic life of a field.
height
A frac may be necessary to break through
s e v e re formation damage (that has not
One wing of a fracture in a vertical well. The
wellbore is lined with casing and the frac
been penetrated by the perforations), or it
initiated through perforations.
may be desirable to increase the
productivity of a well in a very low permeability reservoir. In some cases –
Ravenspurn, for instance – a field would not be developed but for the success of
frac treatments. However fracs are generally expensive operations and therefore
their economic benefit must be evaluated carefully.
The first deliberate hydraulic fracture treatment was carried out in the USA in the
1920’s. However, it was not until 1949 that Halliburton carried out the first
successful, commercial frac treatments. By 1955 more than 3000 wells a month
were being treated; and by 1968 more than half a million jobs had been performed.
Advances in Hydraulic Fracturing Applications
1946
- Marginal well stimulation technique
1955
- More than 3000 wells/month treated
Hugoton, Kansas
Late 60's - Radio-active liquid waste disposal
Oak Ridge, Tennesee
Mid 70's
- Tight gas massive hydraulic fracturing
Rocky Mountains, Colorado
Late 70's - Carbonate reservoir fracturing
North Sea, Netherlands
1980
- Blow-out kill from a well nearby
1982
- Medium and high permeability reservoirs
Kuparuk, Alaska
1982
- Coal seam methane drainage
San Juan Basin, Colorado
1984
- Offshore high rate gas wells
Ravenspurn, UK North Sea
1985
- Frac pack for sand control
West Sak, Alaska
1987
- Horizontal well stimulation
Sprayberry, Texas
1989-91
- Drilling cuttings disposal
1991
- Frac pack for sand control
Alaska, Gulf of Mexico, North Sea
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WELL PRODUCTIVITY AWARENESS SCHOOL
To Frac or Not to Frac?
Determine if the well is providing the maximum benefit, indicated by return
on investment and net present value.
Evaluate permeability and skin (near well damage) from well test.
Determine benefit using NODAL
analysis for various combinations of:
• Recompletions
(tubing size, perforations, surface
equipment, artificial lift)
and
• Matrix treatments
(different materials and sizes)
or
• Fracture treatments
(different material and sizes)
Maximum benefit achieved for
recompletions only?
Yes
Perform recompletion.
No
Yes
Perform matrix treatment.
Maximum benefit achieved
after matrix treatment only?
No
Is maximum benefit achieved
after matrix treatment with
recompletion?
Yes
Perform recompletion.
No
Yes
Perform fracture treatment.
Is maximum benefit achieved
after fracturing only?
No
Is maximum benefit achieved
after fracturing with
recompletion?
Yes
Perform recompletion
No
Fracturing not
needed.
The science of fracturing is a huge subject. Only the basics of the process can be
dealt with here.
Hydraulic fracturing is the pumping of fluids at rates and pressures sufficient to
break the rock, ideally forming a fracture with two wings of equal length on
opposite sides of the borehole. If pumping were stopped after the fracture was
created, the fluids would gradually leak off into the formation; pressure inside the
fracture would fall and the fracture would close, generating no additional
conductivity. To preserve a fracture once it has been opened, either acid is used
to etch the faces of the fracture (an acid-frac in carbonate) to prevent them from
fitting closely together, or in a sandstone the fracture is packed with proppant to
hold it open.
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S T I M U L AT I O N
To Create a Propped Frac
•
•
Perforate well - efficiently
•
•
Pump proppant to hold the frac open
Pump crosslinked gel under pressure to
initiate and propagate a fracture. Gel
used to minimise leak-off
The gel must have a 'breaker' to allow
the fluid to revert to a water-like
consistency for ease of flow-back once
the frac is in place
Conventional hydraulically induced fractures are almost planar, with widths
typically of 1/10th to 1/4 inch, even though lengths and heights may grow to
several hundred feet. A fracture will always tend to open against the line of least
resistance; so the plane of the fracture will be perpendicular to the minimum
principal stress, irrespective of the deviation of the well.
Sv
St
Sr
Vertical
Stress Min
horiz.
Max
stress
horiz.
stress
Stresses in the earth act in three principal
directions, one vertical, and two horizontal,
a maximum and a minimum. At the
borehole well, these are vertical, Sv, radial,
Sr, and tangential, S t. Vertical stress
induced by overburden usually exceeds the
two horizontal components. This means a
fracture will have the least resistance to
opening along a plane normal to the
smallest principal stress. Because this
stress is horizontal, the fracture will orient
vertically. In areas of active thrusting, and
in some shallow wells, a horizontal stress
may exceed overburden and the fracture
will form horizontally. Regional tectonic
forces determine the azimuthal orientation
of the least principal stresses and thus of
the fracture wings.
Schlumberger Oilfield Review
In principle a frac treatment, usually a combination of stages of viscous
crosslinked polymer gels, is initiated at pressures exceeding the formation
breakdown pressure . Once the frac has been initiated, it is propagated at a
slightly lower pressure.
If the fracture initiates in the middle of a thick uniformly stressed body of rock, it
will normally grow uniformly in all directions within the plane, resulting in a
coin-shaped shaped fracture. However, if a fracture initiates in a lower stressed
formation, bounded above and below by higher stressed rocks, as is normally the
case of a sandstone surrounded by shales, then the vertical growth of the fracture
will be restricted by the shales.
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WELL PRODUCTIVITY AWARENESS SCHOOL
Frac being pumped
Shale layer
restricting vertical
growth of fracture
Fracture Perforations
Frac continues
to grow
downwards
Wing of Fracture
BOUNDARY AFFECTING FRAC GROWTH
As a fracture opens, the fluid begins to leak-off into the formation along the frac,
driven by the difference of the fluid pressure in the fracture and the pore pressure
in the reservoir. As the fracture area increases, the rate of leak-off from the
fracture increases, and so the rate of fracture propagation falls. Ultimately a point
of diminishing returns is reached, when the rate of creation of additional fracture
area by continued pumping is very low.
Often a ‘Minifrac ’ or ‘Datafrac ’ is pumped - without proppant - (and the
pressure decline monitored) prior to the main job, to check the design parameters
used in job planning. The on-site measurements may modify the predictions
made by various computer simulations; which use historical data and rock
properties taken from cores and mechanical properties logs to compute estimates
of fracture lengths, pressures etc.
The frac fluid is formulated such that it will lose its viscosity (at reservoir
conditions) a few hours after the frac is in place. Frequently a 'breaker ' is
included in a frac fluid, so that it loses its viscosity with time. Thus the frac fluid
will flow back through the fracture and not remain in the formation or the frac. If
fluid loss agents are included in the fluid formulation, to assist in the building of a
filter cake to reduce leak-off, then these too must be removed during the clean
up, by temperature or dissolution in the produced fluid.
The aim of the propped frac is to open a channel between the reservoir and the
wellbore; effectively increasing the drainage radius of the well. The frac will
deliver the hydrocarbons to the wellbore, but the matrix of the rock must still
deliver the hydrocarbons to the frac face. The pressure drop within the frac must
be low to encourage the passage of hydrocarbons: in other words there must be
good fracture conductivity.
144
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S T I M U L AT I O N
Treatment Types
a) Acid Fracs
This method of stimulation has already been mentioned in the “Treatment Types”
Section above, as it crosses the boundary between an acid treatment and a
fracture treatment.
PROPPED FRACS
To prevent closure, hydraulic fracture is propped open by pumping a
slurry of sand. At greater depths high strength proppant is used.
• Substantially increases production from low permeability formations
(less than 10mD).
• Bypasses skin damage over a wide range of permeabilities.
• Fractures can grow out of zone resulting in water and unwanted gas
production.
Fracture has
grown into
water zone.
ACID FRACS
Proppant
• Only used in carbonates.
• Conductive path along fracture created by acid "etching" fracture walls.
• Etched formation must be strong enough to withstand closure forces.
HYDRAULIC FRACTURE TREATMENTS
Created by pumping above the pressure needed to fracture the rock
b) Propped Fracs
In sandstones, the faces of the frac cannot be etched with acid, and therefore the
frac must be held open with proppant. The amount of proppant pumped is
important since it may become partially embedded in the frac face upon closure,
and therefore sufficient proppant must be pumped to keep the fracture open and
conductive. Proppant can become crushed; therefore care must be taken when
estimating the fracture conductivity. The permeabilities of some proppants, as set
out in the manufacturers literature, are often optimistic.
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WELL PRODUCTIVITY AWARENESS SCHOOL
Sandstone
Embedment
Gross
Aperture
Net
Aperture
Filter
Cake
Sandstone
FRACTURE CONDUCTIVITY
is all important.
• Proppant must be strong enough to
withstand closure stresses
• Proppant must be well rounded and
perfectly sized, with no fines/debris that
will limit permeability
• Proppant must be as large as is
practicable
• The crosslinked gel used to carry the
proppant must be non-damaging and
must lose its viscosity (due to a
'breaker') once the proppant is placed
• Any additives in the gel must not leave
solids in the proppant
• All fluids must be scrupulously clean
LENGTH OF FRACTURE
There is an increasing trend
away from an emphasis on very
long fractures, to an emphasis
on fracture conductivity.
LARGE SCALE IDEALISED CROSS-SECTION OF PROPPED FRAC
(Viewed from above)
Proppant is placed in fractures in slurry form. A stage of clear frac fluid, the
‘pad’, is pumped ahead of the slurry stage to create the correct fracture
dimensions. A slurry stage is then pumped to fill that volume. As the slurry
moves towards the tip of the fracture it becomes progressively more concentrated
as fluid leaks off. The early part of the slurry, which is expected to reach the tip,
is usually pumped at low concentration: usually 1 lb of proppant per gallon of
frac fluid. If too high a slurry concentration was pumped early on, it could
dehydrate and bridge off before reaching the end of the fracture. The slurry
concentration is gradually increased as the treatment progresses.
CONTROLS ON FRACTURE
PERFORMANCE
FRACTURE PERFORMANCE DEPENDS ON:
ABILITY OF FORMATION TO SUPPLY FLUID TO THE
FRACTURE
∝ FRACTURE LENGTH ∗ ROCK PERMEABILITY
ABILITY OF THE FRACTURE TO TRANSMIT FLUID TO THE
WELL
∝ FRACTURE WIDTH X FRACTURE PERMEABILITY
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S T I M U L AT I O N
Design of an Ideal Fracture Treatment
Improved or expanded
stress and modulus data.
Test for different fracture
model or less length.
Obtain stress magnitude and
Young's Modulus1 versus depth
from logs, cores. Also collect
other well and formation
information: lithology, nature
fracture locations, porosity.
Check offset well data.
If appropriate fracture geometry
model not known, do microfrac
(1/3 to 1/ 2 length of actual job, no
proppant) to select fracture
geometry model (2D, P3D, MLF).
Fracture skin or lower
fracture conductivity?
Select fluids and additives that
minimize formation and proppant
damage and environmental
impact.
Different reservoir model
permeability? Is reservoir
anisotropic? Layered?
Stress sensitive?
Obtain permeability and reservoir
pressure from well test; porosity
from logs.
If not done earlier, perform
microfrac to determine correct
model, fluid loss coefficient and
treatment efficiency (volume of
fluid pumped versus volume of
fracture, determined mainly by
leakoff).
Different fracture geometry
model or length?
Iteration for revisions
Use net present value (NPV)
calculation to select proppant,
optimize pump schedule and
fracture length, and predict
production.
Finalize pump schedule with
PLACEMENT program. The
program gives pressure required
during job, frac length at end of
job and distribution of proppant.
Execute job.
Do well test and use
ZODIAC program to
evaluate fracture treatment
and reservoir
characterisation.
No
Is well producing as expected?
Yes
Analyse bottomhole
pressure during execution
with various fracture
models.
No
Was bottomhole pressure during
execution as expected?
Yes
Fracture treatment
design is optimal.
1. Young's Modulus is the ratio of stress (force per unit area) to strain (displacement per unit length).
Schlumberger Oilfield Review
Revision 2: 2001
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WELL PRODUCTIVITY AWARENESS SCHOOL
Job Description Information
Stage
Name
Pump Fluid
Rate
Name
bbl/min
Stage Fluid
Proppant
Volume
Concentration
gal
lbm/gal
Proppant type
+ Mash
Estimated Surface
Pressure
psi
Pad
35
YF140
5,000
0
Slurry
35
YF140
9,000
2
INTERPROP + 20/40
4610
Slurry
35
YF140
14,000
4
INTERPROP + 20/40
3760
Slurry
35
YF140
23,000
6
INTERPROP + 20/40
3080
Slurry
35
YF140
15,000
8
INTERPROP + 20/40
2460
Displ.
35
YF140
13,200
0
A typical pumping schedule for a hydrofrac in a
gas well in east Oklahoma, USA. Each unit of
fluid that represents a change in proppant
concentration or flow rate or both is called a
stage; a specific sequences of stages is called
a pumping schedule. This is a pumping
schedule to produce a 909-foot [277 m]
fracture. The pad fractures the rock and helps
transport the proppant which holds the fracture
open after pressure is released. A major
component of fracture design is establishing the
volume and chemistry of pad and slurry.
Generally, the pad is the largest stage,
accounting for 30 to 50% of fluid, and, rarely, up
to 70%. Ideally, to optimise the propped
fracture length, the pad is completely leaked off
at the moment the fracture reaches its intended
-
5630
-
length. If the pad leaks off too soon, the
fracture will be too short; if too late, the fracture
is not effectively propped. In this well, five
slurry stages with different proppant
concentrations and volumes are used, but as
many as 17 or 20 slurry stages may be used in
large frac jobs. The later slurry stages have
higher proppant concentrations than earlier
stages because the slurry fluid leaks off as it
travels along the fracture. Therefore, a slurry
concentration that starts at the wellbore as 2lb
of proppant per gallon of fluid [240 kg/m ], may
end up as 8 lbm/gal [960 kg/m ] at the end of
pumping, and 44 lbm/gal [5270 kg/m ] when the
fracture closes. In this job, one proppant size
is used (20/40 refers to a standard sieve mesh
size that permits passage of a particle with an
6170
average diameter of 0.63 mm [0.025 in.]).
A larger proppant is sometimes used near
the wellbore to minimise turbulent flow,
which would decrease hydrocarbon flow
rate.
Time for job = 54 mins.
Identifying Candidates
The productivity increase that may be achieved by fracturing is a function of
fracture length, fracture conductivity and fracture/wellbore communication. It is
difficult to lay down firm guidelines for the selection of wells, as each field or
well should be considered on its individual merits.
When planning any frac-job careful consideration must be made of the risk of a
frac extending out-of-zone, i.e. below the oil-water contact, or up into a gas cap.
There are numerous computer programs to predict the size and shape of a frac;
like all programs, if poor data is input, the predictions are not worth much.
Ensure that valid data is used to predict the frac.
Data for input to the frac program includes:
•
•
•
•
geological data
formation boundaries/layers from logs
mechanical properties (from logs, sonic + density)
core data – Young’s Modulus
– Poisson’s Ratio
This data is fed into one of a variety of programs:
148
•
2D
–
•
P3D –
Two dimensional
• Fracture height input
Pseudo three dimensional
Fracture height, length and width can all vary somewhat
independently
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S T I M U L AT I O N
•
3D
–
Three dimensional
Fracture height, length and width can all vary independently
• Lengthy computation time
• More data input required
To complicate matters further, the mathematics of the above programs may be
based on one of three common models:
• Perkins-Kern-Nordgren (PKN)
• Khristianovic-Geertsma-de Klerk (KGD)
• Radial model
The details of the various programs and models are outwith the scope of this
book, but suffice to say that if a frac prediction is wrong it can lead to placement
problems, where too much proppant is pumped for the size of the fracture; or to
production problems when the well doesn’t flow as predicted.
The competence of the cement job surrounding the perforations should also be
evaluated for the same reason. The perforations themselves need be only 4 spf
to 6 spf, and phased at 45 to 60 degrees. The perforation diameter should be at
least six times the mean proppant diameter.
Wellbore
Hydraulic fracture
normal to least
stress
Casing
60° phasing
never >30° from
fracture
Orientation of least
horizontal stress
Channel to
fracture wings
Area of
flow restriction
0° phasing
perforation
The importance of shot phase angle to maximizing
communication between perforations and stimulated fractures.
Studies of fracture and perforation orientations show that for
optimum well productivity, the two lie within 30°, preferably 10°.
This minimizes fracture initiation pressure and the length of the
channel between the perforation and fracture wings, and
increases the likelihood the fracture will initiate along a
perforation. Perforating guns with small phase angle and high
shot density achieve this optimum angle most effectively. The
figure shows that a 0° phasing could place the perforation far
from the fracture, which initiates along the plane normal to the
least stress. But in reality, wells to be fractured are often
perforated with guns at 60° phasing or less (dashed lines). This
means the perforation is never more than 30° from the fracture.
a) Gas Wells
All low permeability gas wells should be considered for fracturing; either at the
completion stage or later in the life of the field. If the frac is to be carried out at
a later date, this should be borne in mind when designing the completion
(including the casing design).
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WELL PRODUCTIVITY AWARENESS SCHOOL
For the North Sea, any well with a permeability of less than 200 mD is a definite
candidate, although better wells should not be dismissed. The actual distribution
of the permeability within the sand body should also be considered
b) Oil Wells
In general, oil wells require higher permeabilities to produce at commercial rates
than do gas wells. It is therefore symptomatic that the benefit of a frac in an oil
well is apparently less than in a gas well. The benefits of fracturing are
potentially greater if a positive skin is present but fracturing is expensive and
other ways of removing near-wellbore damage should be investigated first.
c) Conventional and Tip Screen Out Treatments
A conventional frac is designed to be long and thin; whereas a tip screen-out
(TSO) frac is designed to be short and fat!
Proppant
Width Length Concentration
(inches) (feet)
(lb/ft2)
Conventional Frac
Up to
0.25
750 to
1500
0.5-2.0
0.25 to
1.50
50 to
500
4.0-12.0
Candidates for Conventional Fracs
• Low permeability reservoirs
Tip
Screen-Out
Candidates for Tip Screen-Out
• Frac past near-wellbore damage
• Reservoirs with fines migration
problem
• Multiple pay zones
• Sand Control (frac packs)
• Higher permeability reservoirs
CONVENTIONAL VS TIP SCREEN-OUT FRACTURES
In a low permeability reservoir, the greatest benefit from a frac may be gained by
fraccing as deep as is reasonably possible into the formation to increase the
drainage area. In a higher permeability reservoir, especially one with significant
invasion/formation damage, or one that is ‘soft’ (i.e. the fracture closes around
any proppant, which then becomes fully embedded, thus severely diminishing
fracture conductivity), it is more beneficial to have a shorter, wider frac: say 1” x
100ft as opposed to 1/4” x 1000ft.
Candidates for shorter, wider Tip Screen-Out fracs are:
•
150
Reservoirs with significant wellbore damage. Previous matrix treatments have
failed, and short, wide fractures are designed to bypass the damage and
connect the undamaged reservoir with the wellbore.
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S T I M U L AT I O N
•
Reservoirs with fines migration. A short, wide fracture can alleviate this by
reducing pressure losses and the velocities near the wellbore.
•
Multiple pay zones in laminated sandstone/shale sequences. The thin sand
laminae may not communicate sufficiently with the wellbore until a fracture
provides a continuous connection to the perforations. Computer modelling
should indicate if the sand/shale barriers will hinder the vertical growth of
the frac.
The opposite wing of
the frac has not been
drawn, to illustrate the
laminated geology
Statoil in Gullfaks use this type of
fracturing to produce a weak
sand-prone reservoir sandwiched
between two more competent
reservoirs. The competent reservoirs
are perforated (the weak sand is not)
and a Tip Screen-Out frac is placed to
connect up the weak reservoir to the
wellbore. The lower velocities through
the frac radically diminish the likelihood
of sand production.
Casing and perforations
not illustrated
Proppant
Laminated pay zone with sand-shale sequences.
The sand laminae may be connected to the wellbore
by short, wide fractures.
Schlumberger Oilfield Review
The difference between the two types of propped frac are:
•
In a conventional frac – ideally – the pad has completely leaked off the
moment the fracture has reached its intended length. The slurry stages, with
their increasing concentration of proppant, gradually pack off the fracture,
and pumping ceases when the pumping pressure begins to increase as the
frac becomes full of proppant and ‘screens-out’ at the wellbore. A typical
quantity of proppant placed would be less than 2 lb of proppant per square
foot of fracture (lbm/ft2).
•
In a tip screen-out frac, the frac length is much shorter, and the pumping
schedule is designed to carry proppant to the tip of the fracture at an early
stage, where it packs off and prevents further propagation of the fracture.
The slurry continues to be pumped into the frac, and as the pressures rises
the frac is forced open and a greater width is packed. The frac may have a
proppant concentration greater than 4 lbm/ft2.
Most propped fracs will back-produce some of their proppant. Slow bean-up
of wells when putting them on production is important. Special proppant
knock-out pots will be required between the well and the process facilities.
d) Deviated and Horizontal Wells
It is recommended that wells (especially ones that are expected to produce at
high rates) that are to be fractured be drilled at low deviation angles through the
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WELL PRODUCTIVITY AWARENESS SCHOOL
reservoir. This may mean drilling a S-bend well. However that is not to say that
deviated wells must never be fractured. If the orientation of the field of least
principle stress is known – from measurements or from the fault pattern – then
fracture stimulation my be very advantageous.
Frac propagating
perpendicular to the plane
of the page
Jh
Minimal
Horizontal
Stress
Good connections between the
frac and the wellbore
Vertical Well
Poor connection between the
frac and the wellbore
Jh
• inefficient frac placement
due to pump/pressure
losses
• inefficient production greater pressure drop in the
near-wellbore region
Deviated Well
SOLUTION:
Drill an S-bend well if you need to deviate
away from a platform
Two scenarios for directing a
horizontal wellbore for induced
fracturing. If the wellbore is
drilled perpendicular to the
minimum stress, indicated by the
arrow, the fracture will develop
parallel to the well (above). If the
wellbore is drilled parallel to the
minimum stress, the fracture will
develop transverse to the well
(below).
Schlumberger Oilfield Review
The reason for preferring fracture candidates to be low deviation is to get the
maximum communication between the frac and the wellbore, which may not
happen in highly deviated wells where the frac and the wellbore may only cross
at one point. Fracture initiation and propagation pressures will be higher due to
higher perforation friction losses.
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S T I M U L AT I O N
The following field example demonstrates these phenomena:
100
This figure shows that the
most productive fracs are
achieved on vertical or
near-vertical wells; and
that if a deviated well is to
be fractured the best
productivity results (in
Alaska) will be achieved if
the well is in an azimuth of
0-30° from North.
90
80
70
60
50
40
30
20
10
0
0- 20
0-30
20-40
30-60
60-90
40-60
Well deviation
Well Azimuth
SURVEY OF FRACS ON ALASKAN WELLS
e) Water Injectors
It is believed that most high rate water injection wells are fractured due to cooling
of the rock and lowering of the formation fracture pressure below the injection
pressure (termed thermal fractures). Consequently there is rarely much to be
gained by propped fracturing injectors - if possible, it would be better and
simpler to increase the injection pressure.
Formation Damage During Fracturing
PREVENT DAMAGE DURING FRAC
• All fluids pumped must be compatible
– all compatibility notes mentioned under acid apply here
• Good quality control of frac fluids
•
•
•
– any crosslinked gel MUST break
– check breaker in heat bath on site
Check proppant for quality and cleanliness
Mixwater must be unpolluted and filtered, and inhibited with
NaCI or KCI
All pipework must be thoroughly cleaned
Whether the purpose of a frac be to breach the formation damage around a well
or to increase the drainage area of an undamaged well, it is important that the
frac fluids do not damage the formation. The choice of fluids for the frac and the
subsequent clean up after the frac are critical for the success of the treatment in
this area. Some items to be considered are:
a.
All fluids to be pumped into a well must be compatible with the reservoir
fluids and the reservoir rock. If acid is to be pumped, all the precautions set
out in the Section entitled ‘Formation Damage During Acidisation’ apply.
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WELL PRODUCTIVITY AWARENESS SCHOOL
b.
Good quality control of treating fluids is essential. The failure of the
crosslinked fluid to break can result in virtually zero post-frac productivity.
3700
NOTE: The first fracture
fluid that the Service
Company suggested
was tested at Clair
reservoir conditions and
found to be entirely
unsuitable, being very
slow to cross-link and
showing no
“break-back” of viscosity
over time whatsoever.
By lowering the base gel
pH, omitting all gel
stabilisers and including
a chemical breaker, a
fluid was obtained which
cross-linked more
quickly, gave acceptable
working time (fluid able
to carry proppant) and
broke very cleanly.
21.7 psi/min
3600
Screen out fully
developed
3500
Fracture
initiated
Fracture propagation
Addition of
proppant
Screen out
initiated
3400
3300
3.7 psi/min
BP Sunbury
3200
0
20
40
Time (mins)
60
80
100
FRAC IN CLAIR FIELD
c.
The breaker should be checked on-site in a water bath.
d.
Take frequent samples throughout the job.
e.
Check proppant for quality and cleanliness.
f.
Water for mixing gel should be unpolluted and coarsely filtered, and
inhibited with KCl.
g.
All pipework must be clean.
The above list is not comprehensive; basically everything must be checked and
rechecked to ensure the success of the job. There will not be a second chance.
After a propped frac has been placed, precautions must be taken to ensure proper
clean out of any proppant left in the wellbore. When a frac string is pulled out, a
suitable filtered fluid must be left in the hole, preferably with a degradable LCM
component to stop excessive losses into the frac just formed (the same applies
during the workover of a fractured well).
When a propped-frac well is brought on stream, it should be beaned up slowly to
minimise the shock to the pack and thus minimise flow-back of proppant.
Likewise, during the life of the well, rate changes should always be made gradually.
In a naturally fractured rock it is worth bearing in mind that fluids will be forced
into rocks at very high pressures, yet produced back at much lower drawdowns.
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S T I M U L AT I O N
Thus it may take quite some time to produce back all the fluid. Foam fracs may
minimise losses into natural fractures.
In a naturally fractured rock the stresses resulting from the main frac treatment
may cause movement of the fractures, possibly closing them or creating fines.
This mechanical damage will not be easily removed.
Frac Evaluation
Generally, great care has been taken in the planning of a frac: to get the right size
and shape of frac, after evaluating all the available log and core data; and after
running numerous computer simulations. However, more often than not very little
post-frac evaluation is done.
In Ravenspurn South, the BP
engineers were able to convince
management that an extensive
programme of pre- and post-frac
production tests and an extensive
logging
programme
were
necessary to properly evaluate
the planned fracs – and shut-ins
for pressure build-ups can be as
long as 14 days on these wells.
The programme was conducted
as planned (over the first six
wells) with evaluation of the
early fracs leading to changes in
the design of later fracs. The
refinement of the frac technique
allowed the field to be produced
through only 21 wells instead of
the planned 38; although laterly
the recovery is not quite as
expected and some new wells
may have to be drilled in the
future.
Acidisation of Undamaged Well
Acid
Production Rate 10800 bopd Skin = -1.4
Cased and Perforated
16" Perforations, 6 spf, 60 degree
No mud damage
Acidisation - 2 Feet, 2 x Permeability
No Acidisation Damage
Fully Completed
Vertical
Frac of Damaged Well. Tip Screen-Out Frac
How fracs are evaluated:
• Comparison of pre-frac
and post-frac test data,
including pressure build-up
• Multiple-isotope radioactive
logging (isotopes placed in
proppant)
• Temperature logging
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Production Rate 17820 bopd Skin = -4
Cased and Perforated
16" Perforations, 6 spf, 60 degree
24" filtrate invasion
80% permeability reduction non acid-soluble
Fully completed
Vertical
Proppant permeability 872 Darcies
Frac gel fully broken
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For further reading on the subject of Stimulation the reader is referred to the Schlumberger Oilfield
Review, October 1992 and to the SPE Petroleum Engineering Handbook, Chapters 54 and 55.
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PRODUCTION RELATED DAMAGE
P roduction Related Damage 1 5 8
Precipitation
159
Scale Precipitation During Production
a. Calcium Carbonate
b. Sulphates
c. Scale Prevention
159
160
162
164
Wax Precipitation
Asphaltene Precipitation
Hydrates
Corrosion
Hydrogen Sulphide
166
166
166
167
167
Fines Migration
167
Phase-Related Permeability Reduction 168
Condensate Banking
Water Coning
Gas Breakout
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168
169
170
Stress Induced Permeability Change
170
Injection Wells
171
MODULE SUMMARY
172
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WELL PRODUCTIVITY AWARENESS SCHOOL
Production Related Damage
Remember: ‘Prevention is Better than Cure’
At the end of this module you should be aware of:
•
•
•
•
•
•
•
The main causes of damage during well production
Why water production reduces productivity
How and where different types of scale are formed
How to avoid, or overcome scale problems
When wax and asphaltenes can cause production difficulties
Why fines migration occurs and how to identify it
Loss in oil rate that can occur due to production related damage
Water production reduces the wellhead flowing
pressure - if the water cut is high, the well may not
flow naturally.
"Wet" Well
Production Wells
Injection Well
A well which does not produce
water is less likely to suffer from
production related damage.
"Dry" Well
Production Well
Calcium
carbonate can
form in the near
wellbore region
due to the
pressure drop
when the well is
producing.
If two incompatible
waters mix in the
wellbore, precipitates
like sulphate scale
can form. When
scale is deposited in
the tubing, it will
restrict flow.
Damage in the near wellbore
region, such as scale or
drilling damage, gives a
higher pressure drop when
the well is flowed - this
causes more scale
deposition and/or water
coning.
Tubing
Scale deposits
The main culprit of production related damage is WATER.
–
–
–
–
–
–
it is heavier than
oil and therefore
robs the
production systems
of energy
it is difficult and
expensive to
dispose of at
surface
it causes corrosion
it causes scale
formation
it causes hydrates
it causes emulsions
How to recognise production related damage
Production Rate,
stb/day
6000
Natural decline due to drop in
reservoir pressure - no production
related damage.
4000
2000
0
0
1
2
3
Years of Production
4
Production Rate,
stb/day
6000
Rapid decline due to production
related damage - productivity might
be restored by regular stimulation
treatments (not always successful,
dependent on interval length and
cause of damage).
4000
2000
0
0
1
2
3
Years of Production
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4
PRODUCTION RELATED DAMAGE
Precipitation
PRECIPITATION
During production, inorganic
products (scale) or organic
products such as wax and
asphaltene may be
deposited
– in the tubing
– in surface facilities
– IN THE FORMATION
Greatest impairment
will be nearest the well
– in the perforations
Precipitation occurs either :
a.
b.
c.
In the formation surrounding the wellbore and in the perforations, reducing
the productivity by increasing the pressure losses in the near-wellbore
region;
In the tubing, affecting the tubing performance by reducing the tubing ID.
However, the skin is not affected
In surface flowlines and facilities – problematical, but not of such great
concern since surface facilities can be more easily cleared/replaced.
Scale Precipitation During Production
WHAT IS SCALE?
‘Scale’ is any inorganic, solid material that precipitates in
the reservoir, wellbore or topsides equipment during oil/gas
production or related operations.
Calcium Carbonate (Calcite – CaCO 3)
Barium Sulphate
(Barite – BaSO4 )
Calcium Sulphate (Gypsum – CaSO4 2H2 O)
(Anhydrite – CaSO4)
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WELL PRODUCTIVITY AWARENESS SCHOOL
Calcium Sulphate generally tends to form Gypsum below 100°C and Anhydrite
above 100°C although these temperatures are not exact, depending also on
pressure and water chemistry.
Barium and Strontium Sulphate often appear together in scale (e.g. Forties),
forming a single mineral with a composition intermediate between BaSO4 and
SrSO4. Radioactive elements (primarily Radium226) are also co-precipitated in the
crystal lattice making this type of scale slightly radioactive (LSA – Low Specific
Activity Scale) and requiring special disposal/handling procedures. Calcium
carbonate scales do not exhibit this radioactivity.
Scale usually contains impurities, such as iron minerals, wax, asphaltenes etc.
How does it form?
Scale can precipitate due to:
a. A pressure decline which causes a release of CO2
b. A change in pressure or temperature which causes a drop in solubility
c. Mixing of two incompatible fluids
Once scale has precipitated in the reservoir it reduces the porosity and
permeability. Scale in the reservoir occurs close to the well and the permeability
reduction caused by scale is manifested in an increasing skin.
It is no use producing a well and hoping that scale will not form. A detailed
chemical and thermodynamic study is required at the outset to predict scale
formation, and thus plans can be made to minimise the cause and the effect. It is
better to prevent scale formation than to rely on stimulation. There are now
several computer programs available to assist in scale precipitation studies.
a) Calcium Carbonate
The most common inorganic scale to precipitate in production wells is calcium
carbonate, CaCO3. Many rocks contain calcite, consequently the formation brine
is saturated with CaCO3 (i.e. the brine cannot dissolve any more calcite). On
production, the pressure is reduced around the wellbore and, in many fields (e.g.
Prudhoe), gas is allowed to break out from the oil. CO2 dissolved in the
formation water then enters the gas phase, this results in precipitation of CaCO3
as indicated by the following equation:
Ca++ + 2HCO3 = CaCO3 solid + CO2 gas + H2O
Even without a release of CO2, pressure alone causes some loss in solubility. The
brine becomes supersaturated which may lead to CaCO3 precipitation. This
typically occurs in regions of sudden pressure drop, such as the downstream end
of a subsurface safety valve. Such a valve may periodically have to be flushed
with HCl acid.
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PRODUCTION RELATED DAMAGE
CALCIUM CARBONATE SCALE
Pressure drops
close to the
wellbore
Problem is
selfaggravating.
Scale
produces an
even greater
pressure
drop, leading
to yet more
precipitation
Formation water is saturated
with CaCO3
Ca+++2HCO 3- = CaC03
solid
+ CO2 gas + H 2O
With the reduction in pressure, CO2 breaks out of
solution in the formation water and calcium is
deposited
Limestone/Sandstone with calcite cement
In the formation, the pressure reduction during production is greatest immediately
adjacent to the production well. Consequently, this is where most of the scale
forms. CaCO3 scale in the formation is aggravated by any damage near the
wellbore as this reduces the productivity index and increases the pressure drops
(for the same production rate). The problem is self-aggravating because the scale
deposition causes an additional skin; the well has to be beaned up to maintain
production; the drawdown is greater still and more scale is deposited. The loss
of production is gradual at first but then accelerates rapidly.
The man on the rig has the opportunity to minimise the tendency for a
reservoir to form scale: he can drill an undamaged well to minimise that
pressure drop and therefore delay the onset of scale precipitation.
Fortunately, CaCO3 scale can be removed by hydrochloric (HCl) or acetic acid, or
even the benign EDTA chelating chemicals (assuming that all of the scale can be
contacted by acid and that both the tubulars and the reservoir are suitable for
such treatment).
In Prudhoe Bay, BP have found that problems with near-wellbore CaCO3 scale
appears to have diminished or stabilised, but scale precipitation some one to two
foot from the wellbore may now be the problem, necessitating larger overflushes
and/or more retarded acid. If the acid is unable to remove this scale, a small frac
treatment (tip screen-out method) may be necessary. Arco Alaska believe that the
scale is deposited as much as hundreds of feet from the wellbore.
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WELL PRODUCTIVITY AWARENESS SCHOOL
b) Sulphates
a. Barium Sulphate
Barytes is barium sulphate. The solubility of BaSO4 is very low. Changes
in the pressure or temperature do not result in significant changes to the
risk of scale formation. Mixing of incompatible formation and injected
waters is the major cause of BaSO4 scale. Seawater and many surface
waters contain sulphates which are typically absent in oilfield brines. The
formation brines are frequently high in barium and strontium.
BARIUM SULPHATE
Very low solubility so changes in temperature and pressure do not result in
material amounts of precipitation.
SULPHATE
+
BARIUM
BEWARE
Formation waters
are frequently hign in
Barium and Strontium
Seawater and many
surface waters contain
sulphates
Very insoluble even to aggressive
acids.
BARIUM
SULPHATE
Normally has to be
drilled out of
tubing. If in
formation – frac
may be necessary
b. Calcium Sulphate
CaSO4 scale occurs due to mixing of incompatible waters, but the situation
is complicated by pressure, temperature and water chemistry. There are
several crystal forms of CaSO4, which have different solubilities at given
conditions. For instance, low temperatures and pressures promote gypsum
(CaCO4.2H2O) formation, while at higher temperature and pressures
anhydrite (CaSO4) is more likely to form. Thus, a change in pressure can
alter the form most likely to deposit and give an apparent change to
calcium sulphate solubility. As with CaCO3 scale, the largest pressure
reduction occurs close to the production well (in one report, side wall
cores from an open hole production well showed that scale only formed in
the last 3/8” of rock).
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PRODUCTION RELATED DAMAGE
CALCIUM SULPHATE SCALE
Production
Calcium Sulphate scale occurs by mixing
incompatible waters, although pressure
and temperature changes can alter the risk
of calcium sulphate scale by making a
different crystallographic form more likely.
Extra
pressure
drop due to
skin?
Evaporation of water and mixing of brines
can also precipitate CaSO4
DIFFICULT
TO REMOVE
Cannot be removed by HCI
directy. Chemical converters‘ (e.g.
caustic) must first be used to
change scale to acid soluble form.
This is not always effective.
Chelating agents such as EDTA
can also be used but they are
expensive and are slow to react.
In all cases, PREVENTION IS BETTER THAN CURE
Mixing of formation and injection waters in the liner and tubing invariably causes
sulphate scale. This may or may not happen within the formation, but is only of
consequence around the near wellbore region where permeability reductions
have the greatest affect on fluid flow. Additionally, the scale may form in the
perforations.
FLUID COMPATIBILITIES
Seawater
North
Sea
Miller
Formation
Water
Ula
Formation
Water
Bruce
Formation
Water
Sodium
10890
28100
52582
24570
Calcium
428
615
34676
1410
1366
113
2248
200
462
1630
3509
345
Strontium
8
65
1157
610
Barium
0
770
91
400
Chloride
19699
46050
153030
41660
Sulphate
2962
4
44
13
Bicarbonate
123
1655
134
525
pH
6.5
7.0
6.6
6.3
Concentration
in mg/L
Magnesium
Potassium
Note: relative permeabilities of sulphate and barium between seawater and
formation water.
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WELL PRODUCTIVITY AWARENESS SCHOOL
Barium sulphate is very insoluble, and is a much more serious problem than
calcium carbonate because it is insoluble even in highly aggressive HF/HCl mud
acid. It generally has to be drilled out of the tubing/liner (coiled tubing has been
used for this purpose in Forties and Magnus). Chelating agents similar to EDTA
are available but they are slow and expensive and are ineffective if scale is oil
coated. If barium sulphate scale is in the formation, a frac may be necessary.
After drilling barium sulphate out of a well, reperforation may well be necessary,
either because the existing perforations are scaled up or the drilling process has
resulted in formation damage. If the scale can be drilled out on coiled tubing,
with the well flowing, there is less likelihood of milled scale entering the
perforations.
c) Scale Prevention
Prevention of scale is better than cure:
a.
b.
c.
d.
Identify the chemistry of the produced water
Attempt to reduce the pressure drops where scale may be a problem.
Do not mix incompatible waters.
If scale is going to form, inhibit it - especially troublesome barium sulphate.
BEWARE: anything you pump into a well is potentially damaging.
All injection water must be carefully monitored.
Beware of:
Injection
Water
Formation
Water
Sulphate
Seawater/sulphate
Barium
Barium ions
- plugs injection well
- in situ plugging away from
the wellbore, or in the
producing well, when the
water breaks through.
Dissolved oxygen
H2S
- forms iron sulphide, very
damaging. Corrosion.
Toxic.
Dissolved oxygen
CO2
- carbonates
Beware of oxygen
scavengers; sulfite and
CO2 in scavengers may
mix with formation water
rich in barium.
Even the lubricant used in a gas compressor has been
known to damage an injection well.
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PRODUCTION RELATED DAMAGE
Scale formation can be prevented by the use of scale inhibitors . To protect the
near wellbore region, perforations and production tubing these treatments are
squeezed into the formation at regular intervals. Then they are produced back
with the oil and water. Only small quantities of inhibitor are necessary. They do
not change the solubility of the offending scale, but rather interfere with the
process of precipitation (i.e. the kinetics) such that scale formation is delayed, or
crystal growth is modified so that smaller crystals form which are produced out
with the oil rather than deposited in the formation or on the tubing.
Offshore the most obvious injection water is of course seawater, but seawater
mixes with barium to form insoluble barium sulphate. Some operators
desulphonate their injected seawater, but this is very expensive. The Miller Field
for instance injects two barrels of seawater for every barrel of oil produced. To
desulphonate the seawater would be prohibitively expensive. Thus Miller have
developed their own specific inhibitor. The Miller Field will produce 2 tonnes of
barium sulphate scale for every 10,000 bbls of oil produced when injection water
breakthrough occurs..
How to minimise Production Related Damage
Minimise damage whilst drilling the well
Complete the well to obtain the lowest possible
skin factor
Control the producing drawdown
Avoid rapid changes in the flowing conditions
Scale Inhibitor Squeeze Treatments: are used to minimise downhole
scale formation - the scale inhibitor is injected into the formation and
during production it is slowly 'returned' in the produced water.
Remove the cause. Although very expensive, sulphate can be
removed from all injection water to prevent barium sulphate scale.
Stage 1: Preflush
Stage 2: Pump Scale Inhibitor
Inhibitors are injected
down the production
tubing (beware damage
from scale, rust, wax
asphaltenes etc. being
forced into the formation)
or coiled tubing and back
into the formation by
several feet – at below frac
pressure. The inhibitor will
be adsorbed onto the sand
grains or will reside in the
pores of the rock to be
gradually depleted by
production. The produced
oil is evaluated and
measurements made to
ascertain when the next
inhibitor treatment is
required.
Stage 3: Pump Overflush
Stage 4: Shut in
Stage 5: Return the well to production - inhibitor is slowly
released into the well.
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WELL PRODUCTIVITY AWARENESS SCHOOL
Wax Precipitation
WAX PRECIPITATION
• Primarily produced in tubing, flowlines and surface facilities
due to drop in temperature
– but can precipitate in formation where gas breakout
causes drop in temperature
Wax removed periodically by aromatic
solvents and/or hot water washes. Also by
wireline cutter.
BEWARE of pumping dissolved wax into
the formation
Wax inhibitor can be pumped down an
injection line (if included in completion)
Wax deposition occurs primarily due to a drop in temperature, and is most
pronounced in tubing, flowlines and surface facilities. Precipitation of wax can
however occur in the formation close to production wells, where gas breakout
and expansion causes a drop in temperature. In production risers, for instance
through permafrost or deep water, wax deposition has also been observed. The
tendency for wax precipitation is crude specific. Evaluate live samples from early
tests in the laboratory.
Wax deposition in the formation is rare and prevention is not normally possible. It
could be removed at intervals by injecting aromatic solvents. Heating the solvent
can help clear wax out of the tubing, but by the time it reaches the bottom of the
well, the temperature has usually equilibrated with the surrounding formation.
BEWARE: although wax may not form in the formation, it can be carried into
perforations by treatments designed to remove wax from the tubing; or indeed
kill fluids, acid, and anything else bullheaded into the formation.
Asphaltene Precipitation
Asphaltenes are high molecular weight substances held in the oil by various polar
compounds. They tend to precipitate out of the crude oil at pressures close to
the bubble point. They are specific to oil-type. The problem does not exist in all
crudes. The deposition of asphaltene in the formation and the tubing can have a
serious effect on well productivity. They are insoluble in non-aromatic solvents
and their precipitation cannot easily be inhibited with chemicals. They can be
removed slowly with various aromatic solvents. Beware of asphaltene solvents
destroying elastomers in packers, seals, and other production equipment. Various
asphaltene inhibitors are being developed and should be commercially available
in the near future.
Hydrates
Hydrates are crystalline solid materials comprising water and low molecular
weight gases. They are formed at high pressures at low temperatures (but above
0°C). They can block gas lift values and surface chokes. Hydrates can be
inhibited by the injection of ethanol or methanol into the gas flow stream.
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PRODUCTION RELATED DAMAGE
Corrosion
Corrosion is known to all of us where water attacks iron resulting in the
degradation of the steel. Corrosion inhibitors are put in completion brine and
sometimes injected downhole via 1/4” lines. As far as well productivity is
concerned two things are important:
• no corrosion products should go near the formation
• corrosion inhibitors must be tested for formation damage within the reservoir
Hydrogen Sulphide
Produced water, sulphate reducing bacteria and other circumstances can lead to
the production of H2S. This will cause hydrogen-embrittlement of steel apart
from the obvious danger to life from poisonous gas. Always consider inhibiting
completion brines to minimise the chances of H2S generation.
Fines Migration
Tiny solid particles occur in the pore spaces of all sandstone formations. Fines
are usually identified as any solids that pass through a 400 mesh (37 micron)
screen, which is the smallest screen size available. Electron micrographs have
revealed the nature of typical fines; clays, quartz, minerals (such as feldspars,
muscovite, calcite, barite) and amorphous material. Clays are only a small
constituent; quartz and amorphous material make up most of the fines.
Fines are loose, not attached to the sandstone grains, and can move freely within
the porous matrix. Experiments have shown that fines movement is strongly
affected by liquid phases and boundaries. e.g. fines are only thought to move
readily when the phase that wets them is flowing. Mixed wettability fines are
confined to the oil/water interface.
FINES MIGRATION
’Fines‘ are usually
identified as any
solids that will pass
through a 400 mesh
(37 micron) screen
(the smallest there is).
’Backflushing‘ of the
formation may
increase production if
fines can be
dislodged.
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Fines are made up of
clays, quarts, minerals
(feldspars, muscovite,
calcite, barite) and
amorphous material.
Quartz and
amorphous make up
most of the fines.
Bring the well on
slowly to minimise the
chances of any fines
bridging in the pore
throats
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WELL PRODUCTIVITY AWARENESS SCHOOL
Why are fines of concern to well productivity? It has been suggested that
imposing a high initial drawdown (opening the chokes rapidly) causes formation
damage due to fines migration; wells which are completed and brought on-line
with minimal pressure surges to the formation should have lower skins. In some
cases, large underbalanced perforating may lead to reduced near-wellbore
permeability due to fines migration caused by the underbalance surge.
Furthermore, in some fields such as Prudhoe Bay, rapid productivity declines are
observed over periods of a few months; some of this is attributed to the
movement of formation fines during normal production from the well.
Fines cause productivity impairment when they bridge across pore throats.
Bridging is a result of two things;
a) Fines move only when the fluid velocity is sufficiently high to entrain the
particles. Thus fines migration only occurs in a cylindrical region of a few feet
around the wellbore.
b) Mobile fines accumulate, bridging pore throats and impairing productivity,
when they are of suitable size.
Laboratory tests indicate that changing the flow direction can increase
permeability, at least temporarily. This is as a result of fines bridges across pore
throats breaking up. Such observations have lead to the technique of backflushing a well, a useful technique for the identification of fines migration. Some
Prudhoe Bay wells respond simply to injecting a filtered fluid into the formation
for a few hours (below fracture pressure), which breaks up many of the fines
bridges. This results in higher flow rates after the treatment, but does not prevent
the onset of a further decline as the fines continue to migrate.
Phase-Related Permeability Reduction
Condensate Banking
In a gas well on production, the pressure drop in the near wellbore region may
take the reservoir pressure to below the dewpoint. Some of the liquids in the gas
then drop out and settle in the pore structure, thus affecting the relative
permeability to gas of the near wellbore region
The low permeability due to condensate drop-out will itself cause a bigger
pressure drop, and thus the problem is self-aggravating. The presence of a
condensate bank is difficult to detect. They can be avoided or delayed by
minimising the drawdown of the reservoir. Gas fields with high liquid yields and
high dewpoint pressures are most prone to this form of damage.
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PRODUCTION RELATED DAMAGE
Reservoir pressure
Gas dewpoint pressure
Zone of condensate
dropout
Distance
MECHANISM
As near wellbore pressure is reduced during production, dewpoint pressure of
gas is reached. Dropout of liquid hydrocardons in near wellbore zone reduces
relative permeability to gas. Once formed, condensate bank will itself cause
additional pressure drop, and be self aggravating.
OCCURRENCE
Only a problem in gas reservoirs with significant condensate yield, and relatively
high dew point pressure. Difficult mecahanism to diagnose due to fluid sampling
problems.
IMPACT
Possibly serious, but poorly understood
CONDENSATE BANKING
Hydraulic fracturing of a problem well/field would reduce the drawdown on the
reservoir, and this might alleviate the problem. In some cases a condensate bank
can be reduced by pumping ‘dry’ gas into the reservoir and producing it back
with the vapourised liquids.
Water Coning
If a reservoir is completed too close to the water contact there is a danger that
water will be pulled into the well ahead of the oil, thus forming a cone.
Reservoir pressure
Aquifer coning to produce
near-wellbore water
saturation increase
Distance
WATER CONING
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WELL PRODUCTIVITY AWARENESS SCHOOL
The cone of water will not only reduce the relative permeability to hydrocarbons
but it will adversely affect the tubing performance. The impact of this can be
very serious on well productivity, and completion strategy should do everything
possible to avoid this problem.
Gas Breakout
If an oil reservoir has a gas cap and it is ‘pulled’ too hard there is a danger of gas
coning. This will reduce the permeability of the rock to oil and thus decrease
production. Alternatively, if the reservoir pressure falls below bubblepoint, gas
will come out of solution and surround the wellbore. This will also reduce the
relative permeability to oil and affect the productivity of the well.
Reservoir pressure
Oil bubble point pressure
1
Increased near-wellbore
gas- saturation
2
Downward Coning of
pre-existing gas-cap
Distance
MECHANISM
Near wellbore increase in gas saturation may have two causes (see above)
OCCURRENCE
Easy to predict/diagnose, but difficult to quantify.
IMPACT
Potentially severe
PREVENTION/REMOVAL
Minimise production drawdown.
GAS BREAKOUT
A rising GOR in a well is easy to identify, but the extent of the damage downhole
is not. Once again, the preventative measure is to minimise the drawdown on
the reservoir. The bubble point of a reservoir is a field-wide pressure and
therefore this is more of a field problem than a well problem; however, once
again, if a well has to be drawn down by a greater pressure to achieve a certain
productivity (because it is damaged) the problem will be exacerbated.
Stress Induced Permeability Change
As a reservoir is produced and the pressure drops (given no pressure
maintenance) the overburden pressure can cause the pores to close up, thus
reducing permeability. This effect will be greatest in:
a. Overpressured reservoirs – high drawdown
b. Fractured reservoirs – fractures may close
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PRODUCTION RELATED DAMAGE
c. Unconsolidated, mechanically weak reservoirs
d. Low permeability (usually gas reservoirs)
An example of stress-induced permeability reduction can be found in the
Pedernales Field in Venezuela where a reduction in reservoir pressure of about
one third of the original pressure led to a permeability reduction of 20%. In some
of the Norwegian N. Sea fields the seabed is sinking due to evacuation of the
reservoir. The extent of the reservoir permeability reduction is unknown. What
is known is that some of the platforms have had to be raised to re-establish their
original height above the sea level.
Injection Wells
Laboratory tests involving the injection of seawater into cores invariably show a
loss in permeability with time, as solids in the brine create internal or external
filter cakes. Based on the radial flow equation this would result in a significant
loss in well injectivity with time. This led to the use of fine filtration equipment
for water injection in most BP fields.
However, two lines of investigation have shown that fine filtration is unnecessary
in the North Sea:
1)
Measurements on the quality of water prior to the filters and downhole
showed that filtration has no measurable effect on water quality. This is
because the quality of North Sea water is very good to start with; solids
enter the system after the filters (due to corrosion, system upsets etc.).
2)
Hydraulic impedance testing has shown that most of the injectors are
thermally fractured.
Thermal fracturing caused by cold injection water hitting the reservoir water
pressure results in the surface area of formation exposed being much
greater than in an unfractured well. This makes it less prone to damage
because:
a)
It takes longer to achieve the same permeability reduction due to a
larger area which must be damaged;
b) The same permeability reduction causes a smaller pressure loss
(because the velocity through the damage is lower).
Although thermally fractured wells are more tolerant of damage than
unfractured wells, they can be damaged, especially by the injection of lower
quality produced water. The damage is partly due to oil carry-over.
However in places such as Forties, small calcium carbonate ‘scale’ particles,
precipitated from the produced water due to loss of carbon dioxide, are
responsible.
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WORKOVERS
Wo r k o v e r s
Types
174
Workover Practices
176
Well Killing
177
Fluids
a Types
b Importance of Cleanliness Filtering
178
178
181
Best Practices
182
Water Shut-off Treatments
188
Coil Tubing
190
MODULE SUMMARY
200
a Drilling
b Completions
c Well Maintenance
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190
197
199
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Workovers
At the end of this module you should be aware of:
•
•
•
•
•
The main causes of damage during workovers
The different ways to kill a well
The reasons for using special filtered brines
Why kill pills are sometimes used
How to avoid workover damage
Types
• Workovers should not be the poor
relation of the oil industry
$$$ They can be very profitable £££
Too often, workovers are thought of the poor relative of oilfield operation. This
is a fallacy. The workover of a well is as important as when the well was drilled
in the first place. Formation damage and productivity impairment can still occur.
A very large proportion of BP’s annual budget is spent on workovers. BP Alaska
spends in excess of $200 million per annum in workovers.
A workover is an operation upon an existing well – be it an oil or gas well or an
injection well – that materially alters the physical condition of that well. Some
40% of the BP Aberdeen ‘drilling’ budget is spent on workovers, as opposed to
drilling. It is therefore a significant part of the operation, and a serious potential
avenue to cause damage rather than to improve well productivity.
There are countless types of workovers:
•
•
•
•
•
•
•
•
•
•
•
•
174
Scale treatment by injection
Wax cleanout
Recompletion – different configuration or repair of existing design
Plugback and sidetrack – Recompletion
Drainholes and multi-laterals
Reperforation – Change of perforations
Acid stimulation
Fracture stimulation
Deepening of well
Water shut-off
Gravel pack
A combination of the above
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WORKOVERS
Mechanical Reasons For Workovers
Replace Failed Equipment: During production, the well completion is subject to a corrosive and
erosive environment - tubing can develop leaks after only a few years. Artificial lift also needs
replacing regularly - electric submersible pumps (ESP's) have a typical life of 6 - 18 months, sucker
rods about 24 months.
Resize Tubing/Add Artificial Lift: As reservoir pressure drops, less energy is available to bring oil
and gas to the surface. The situation gets worse as water cut increases with time. In many older
wells, the tubing size must be reduced, and/or artificial lift (such as gaslift, ESP's, jet pumps or rod
pumps) must be added.
Reservoir Reasons For Workovers
Gas
Oil
Cone
Channel
in cement
Cement Channels: Poor liner cementing can leave mud-filled channels
around the liner. Water or gas from other intervals can then get into the
wellbore, reducing oil production and causing many other problems.
Sometimes, mud in channels holds back unwanted gas and water until
the well is stimulated with mud acid. 'Remedial' workover operations
are needed to cement the channels.
Recompleted
Well
Zonal Isolation: Unwanted water or gas production may need to be
shut off. This might be done with cement, a bridge plug or 'straddled'
with a piece of tubing and two packers.
Recomplete to Produce from Other Horizons: Many fields contain
several reservoirs. Older wells may be recompleted to begin production
from a new reservoir.
Sand Control: Wells which produce from weak sandstones may not
require initial sand control, but sanding problems may get worse with
time. 'Remedial' sand control may be needed to reduce sand
production.
Watered out
Formation
Cement Plug
There are countless ways of conducting a workover:
WITH RIG INTERVENTION
• Full-sized drilling rig
• Workover rig
• Workover hoist
NON RIG INTERVENTION
• Slickline
• Electric Line
• Snubbing unit
• Coiled tubing
• Pumping (acid and/or frac)
Types of Workovers
Rig Workovers - The well completion is pulled to perform work such as liner repair, tubing or ESP
replacement. A workover rig, drilling rig, or pulling unit is used. Because the tubing is pulled, the
well must be killed.
Snubbing Unit Workovers - It is possible to pull and run tubing under pressure without killing the
well, by using a 'snubbing unit'. This reduces the risk of formation damage, but is much more
expensive, and there are limits to the pressures and tubing sizes which can be handled.
Through Tubing Workovers - Coiled tubing units allow drilling, under-reaming, cement squeezing,
gravel packing and other operations to be done through the production tubing. Often, the work can
be done without killing the well, and sometimes it can be performed with the well flowing. Other
coiled tubing workovers include running concentric re-completions complete with spoolable gas-lift
valves.
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WELL PRODUCTIVITY AWARENESS SCHOOL
Workover Practices
The types of workover during the life of a field will change as the field matures.
Initially the workovers will tend to be repair jobs on things that went wrong
during the initial drilling and completion. Then, the trend will be towards
measures to extend the life of a well/field as production problems become more
prevalent and various methods of enhanced recovery are attempted. As the wells
get older, of course, they are more prone to equipment failure.
This section of the book, “Workovers”, may appear thin and perhaps not
important; on the contrary:
Everything that has been mentioned in previous sections applies to workovers.
Many of the techniques describes in the next section also apply to workovers.
WELL PRODUCTIVITY IS CRITICAL IN WORKOVERS
Plan a Workover Efficiently
Data
Gather all relevant data - mechanical, geological, reservoir and
production.
Communication
Speak to geoscientists, engineers, rig supervisors, crews,
service companies. Keep everyone informed before, during and
after the job.
Safety
Maintain all safety rules. Heighten safety awareness.
Equipment
Make sure that all equipment is fit for purpose, from the rig down
to the smallest piece of kit employed. Anticipate most extreme
situations that equipment may be subjected to.
Location
If offshore - can the platform handle your planned operation?
Simultaneous drilling and production?
If onshore - does the location need to be prepared to prevent
logistical problems?
Weather
Choose when least weather downtime is likely if possible.
Official Documentation
Obtain all the necessary consents and permits well in advance.
Know your Well Condition
Would a wireline survey before the rig arrives tell you something
that will change the course of the workover?
Timing
Make a realistic time estimate. Attempt to anticipate and be
prepared for predictable problems.
Fluids and Kill Pills
Take great care in the area - see notes later in this chapter.
WELL PRODUCTIVITY
Think Well Productivity throughout the planning and execution of
the workover. Do not get so sidetracked by mechanical
problems that the perforations and the reservoir get neglected.
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Well Killing
Ideally a well need not be killed to carry out a workover. If the original
completion string permitted the wellbore below the packer to be isolated with a
wireline plug (for instance), then the tubing above the packer could be replaced
without disturbing the formation (if tubing above is attached to packer via a seal
assembly). This is known as a 'top-hole' workover. Alternatively, coiled tubing
or a snubbing unit might be employed to work over a well under pressure. In
both these instances, the reservoir would not be open to potential damage by a
well killing operation.
Milling or scraping activity
close to the open perfs will
create damaging solids that
will enter the open perfs.
Avoid such activity close to the
perfs if possible – or make
sure that perfs are sealed with
LCM or a sand plug
If possible, circulate to kill the
well. Avoid bullheading.
If kill pill is pumped, make sure
that it is clean and non-damaging.
Can it be removed later?
Put plug in tailpipe if working
above the packer
Check the well records to see if
any fractures present.
What is likely loss rate?
What sort of kill pill is best suited
to the reservoir, without causing
formation damage?
However, often a well does have to be killed, and this is where the importance
of kill pills is paramount.
To kill a well requires that a fluid with a greater hydrostatic head than the
reservoir pressure be placed in the well. Since the well has previously been
designed to produce, the perforations or the open-hole completion should have
permeability, and thus the workover fluid will tend to leak off into the formation.
A good workover fluid is clean, filtered and devoid of any solids. It cannot
therefore form a filter cake and will leak off at a high rate into the formation. To
prevent the loss of fluid into the formation, a kill pill is employed. An ineffective
kill pill will not only cause a potential well control problem, but may also cause
damage to the perforations and formation by plugging with insoluble solids.
A kill pill or any chemical in the workover fluid must flow back after the
workover, when the well is put back on production; or it must be able to be
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destroyed by hydrocarbon flow or treatment with water or acid. Any foreign
solids within the workover fluid are in danger of becoming lodged in the
formation. Reservoirs with a wide range of permeability are particularly prone to
ineffective clean-up.
Where possible the well should not be killed by bullheading
the tubing
contents into the formation, as all the debris and scale within the tubing will be
forced into the formation, to the eternal detriment of the reservoir. If possible,
coiled tubing should be used to circulate the tubing contents to kill fluid, and/or
to pump the kill pill.
One technique in use is to dump sand across the perforations to reduce the loss
of fluids. But remember that whatever you use to minimise losses must be
removed successfully from the well after the job. Think ahead.
Sanding Back
Damage can be minimised by ‘sanding back’ above the perforated interval.
Sand can be 'dump-bailed', or pumped in gelled water using coiled tubing.
The sand-pack allows flow-through, and a kill pill will seal against the sand
pack instead of plugging perforation tunnels. This can be especially useful
when working over hydraulically fractured wells.
Kill pill can be
spotted on
top of sand to
control fluid
losses.
Frac sand
pumped in
gelled
filtered
water.
Fluids
a) Types
The workover fluid and the kill pill must be carefully designed.
In the past, too often, workovers have been carried out using a logistically
convenient fluid such as lease brine, lease oil, manufactured brines, mixtures of
local waters, refined oils or even drilling mud. Unfortunately the quality of such
fluids is extremely variable, and may critically affect the effectiveness of the
treatment.
An ideal kill pill must clean up from the well completely after the workover.
Tests must be done with various fluids to check which is suitable for each
well/field. The common solids that are used in kill pills, and their respective
washing systems are:
Workover Fluid Kill Pill Solids
Wash System
Brine
Under-saturated brine
Sodium hypochlorite
Calcium bromide
Hydrochloric acid
Diesel or xylene
Sodium hypochlorite
Hydrochloric acid
Brine
Brine
Brine
Brine
Sized Salt
+
+
+
+
Calcium carbonate
Oil soluble resin
Fine grained cellulose fibres
HEC or XC Polymer
Although these systems are readily dissolved if the solvent reaches the solid,
several problems occur in the field:
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• It is difficult to ensure that all of the perforations are washed – the washing
fluid may be lost only to those perforations that are open.
• The ‘solids’ in the perforations are actually a mixture of solids and polymers,
with the polymers generally coating the solids – this reduces their solubility
in the solvent. A mild acid – acetic – may be necessary to destroy the
polymer, before (for instance) dilute salt solution removes sized salt.
It is much better to use a kill pill that is easy to clean up by producing the well;
rather than having to rely on chemical removal.
A kill pill is nearly always formation specific; when, for instance, the grain size of
the formation has been taken into account, and the temperature of the reservoir.
The kill pill must be tested for its suitability and the formula not changed without
good reason. In Alaska, for example, they formulate pre-thaw and post-thaw kill
pills for use at different times of the year because of the changes in the make-up
water that is taken from the sea.
As a general rule seawater should not be used as a kill fluid or a workover fluid
as sulphates in the seawater can mix with possible barium/strontium in the
formation water to form insoluble (pore-blocking) barium/strontium sulphate.
Any liquid that is used as a workover fluid should not damage the formation, i.e.
if there are water sensitive clays present, a KCl brine will be used in preference to
an unsaturated NaCl brine.
KILL PILLS MUST BE TESTED
There are three things that must be tested for a kill pill:
•
Does the 'filtrate' damage the formation?
(this applies to the workover fluid and to whatever
the kill pill is mixed with)
•
•
Will the kill pill prevent losses?
What is more important in terms of well productivity,
will it come out again?
Workover fluids must be tested on representative cores for return permeability .
Remember that even a small amount of damage in the near-wellbore region can
cause high skins. In some cases it may not be possible to perforate past postworkover skins. The apparatus to determine return permeability is discussed
previously in this book, in the section covering drilling muds.
For kill pills it is necessary to examine the ‘lift-off’ capability of various pills.
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Differential pressure
measurement
Fluid in/out
Gas pressure
Fluid reservoir
Kill pill placed
Step
1
Pressure is applied from above
(to simulate hydrostatic) and the
solids in the kill pill will be
deposited here, and should
prevent any further passage of
fluid. Losses are stopped. The
hole can be kept full with kill
weight fluid.
Permeameter
Core plug
(11/ 2" diameter x 3" long)
Step
2
Steady pressure is applied
from below to simulate
drawdown, and production
from the well. The pressure
and time taken to 'lift-off' the
kill pill can be measured.
Differential pressure
measurement
Fluid in/out
DESIGN OF KILL PILLS Schematic Diagram of Filter Cake Lift Off Apparatus
The type of graph that illustrates the comparison between two kill pills is shown below.
100
Calcium
Carbonate
90
80
Sized Salt
70
60
50
In this case, the sized
salt kill pill is far more
suited to this reservoir.
In these conditions it is
far easier to remove; it
takes only 5 psi to 'lift-off'
versus the 90 psi
necessary to remove the
calcium carbonate pill.
40
30
20
10
0
Time
(seconds)
COMPARATIVE CLEAN UP OF KILL PILLS
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Note that this apparent success of the sized salt kill pill is specific to that
particular recipe of kill pill (e.g. various types and concentrations of polymer,
sizes and concentrations of salt, etc.) in the formation tested.
It is not sufficient to use a kill pill that worked well in a previous field even if the
two fields in question have apparently similar sandstones.
There is a possibility to carry out even further testing for kill pills, but with
increasing cost. It is possible to create perforations in a block of reservoir, to
measure production rates through the perforations, and then to kill them, and
finally measure production rates after ‘lifting off’ the kill pills (with or without
stimulation). These experiments are very interesting for measuring and observing
the dynamics of kill pills, but very few petroleum engineers have 1 metre x 1m
x1m blocks of their reservoir to play with!
b) Importance of Cleanliness/Filtering
All the comments made in Section 4, under Completion Fluids apply to workovers
– perhaps even more so. NOT ENOUGH ATTENTION IS PAID TO CLEAN
FLUIDS DURING A WORKOVER. The financial success or failure of the workover
is dictated by the formation: however mechanically slick the replacement of the
old completion for a new one is (for instance) matters not if the permeability has
been halved in the meanwhile.
• Always check the mixing and delivery methods of any workover fluid.
Was the equipment (tanks + lines + pumps) clean?
• Beware of finely divided asphalt resins or wax in old lease crud.
• Beware of additives in refined diesel.
• Beware additives in salt (for free flowing properties, for instance).
• Filter the workover fluid
Proper filtration
minimises damage
Formation Damage caused by
Solids in Workover Fluids
A good filter cake
minimises damage
This graph shows
laboratory testing of
different fluids
pumped through a
core plug.
Solids content
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Note that in many workovers you are dealing with perforations. If you recall
from Section 4, perforations are long and thin, and are easily damaged. If
precautions were taken to select the correct guns and the optimum perforating
technique back at the time of completion, how foolish it would be to fill up those
precious perforations with debris during the workover phase. Such debris might
never come out again. If you plug the original perforations, you may have to
stimulate or re-perforate; both which could render the workover uneconomic.
Whatever debris goes in may not come
out. It is far easier to enter than exit.
Volume of one
perforation, assuming it
is a cylinder rather than
a cone, is 1.28 cubic
inches. or 20.6 cubic
centimeters
0.4"
10"
If there are 20 ft of
perforations at 6 shots/ft
the total volume of the
perforations is 2472
c.c., about 2.5 litres.
NOT a huge volume.
This is the total volume of the
perforations; but of course the flow
will be plugged off if either the
mouth is blocked or just the
surface area of the perforation is
plastered with pipe dope, wax,
asphaltene etc. BEWARE.
Drawn to half scale
It is not only fluids that must be clean. All the previous comments about clean
pumps, lines, and tubulars apply here, perhaps more so.
Rig drill pipe is generally not very clean, even after surfactants, solvents and other
clean-up fluids have been circulated through it. One story tells of an apparently
clean 12,000 ft string of 5” drillpipe from an active North Sea rig being cleaned,
by hammering it repeatedly to remove internal debris. The rubbish and debris
filled seven full sized skips. Imagine some of that entering your well and
perforations!
Even brand new tubing cannot be trusted: recent tests have shown that as much
as 81 lbs/1000 ft of mill scale/corrosion can be removed from new pipe (internal
and external). The removal of such debris must be conducted ashore, before the
tubulars are sent to the rig.
Best Practices
In Prudhoe Bay BP studied approximately 300 workovers, carried out over four
years. They eliminated wells in which cement squeezes, acid jobs, and additional
perforating was performed and came up with 51 suitable candidates to study preworkover and post-workover PI’s. (Reference: ‘Prudhoe Bay Rig Workovers:
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Best Practices for Minimising Productivity Impairment and Formation Damage’,
C.G. Dyke and D.A. Crockett. SPE 26042.) They came up with a list of best
practices, from which the following list is extracted:
(a)
Well records should be checked in advance for the presence of whole mud
losses during drilling. These losses indicate natural fracture permeability
which requires a coarser grade of kill pill during killing.
The expected losses in a workover may follow a field-wide pattern.
In Prudhoe Bay the losses were estimated using the equation,
Loss Rate = (100 + 100 PI) bbls/day.
(b)
Wells should be killed by circulating to minimise productivity impairment.
Prudhoe Bay uses filtered seawater as a workover fluid. This has been
checked as non-damaging to the Ivishak formation. Cleanliness of
workover fluids is particularly critical when treating perforated completions,
as only a relatively small amount of particulate solid is needed to block the
perforation tunnels. Bullheading will introduce solids into the perforation
tunnels/formation.
Low permeability wells are more likely to be damaged by bullheading than
are high permeability wells because of the smaller pore throats within these
formations. To study the effects of bullheading, BP looked at the damaged
caused when bullheading corrosion inhibitor treatments down the tubing
(where the inhibitor did not enter the formation).
HIGH PI WELLS
1
LOW PI WELLS
(10-25 mD
permeability)
0
-1
-2
-3
-4
-5
Based on single
well test pre and
post bullhead
Based on two
month interval
pre and post
bullhead
-6
-7
-8
DAMAGE INDUCED BY CORROSION BULLHEAD
TREATMENTS FOR LOW AND HIGH PI WELLS
(c)
Downhole operations such as milling and scraping must be conducted as
far away as possible from open perforations. Whatever the position of the
downhole operation, the losses must be cured before the milling or
scraping commences.
Workover of a well called Z-18 led to an 88% loss of PI, and the need for
additional perforating to restore production. Investigation followed to track
down the source of the damage.
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Losses at around
200 bbls/day.
No kill pills pumped.
Packer
milled 700 ft above
perforations.
Loss rate continued at
200 bbls/day.
MILL ON PACKER 13147 ft
88% LOSS IN PI DURING WORKOVER
PERFS 13845-13928 ft
350
300
MILL ON FISH 13888 ft
250
Milling of fish within
the perforated section
causes losses to drop
to less than 10
bbls/day: the solids
are plugging the
perforations.
200
150
100
50
0
1 2
3 4 5 6
7 8 9 10 11 12 13 14 15 16 1718 19 20 2122 2324 25
DAYS FROM START OF WORKOVER
EFFECT OF MILLING AT PERFS ON DAILY FLUID LOSS RATE, Z-18
Scraping the casing across or near perforations will have the same effect.
CASING
SCRAPER
If the casing has to
be scraped to
place a packer
FINES IN SUSPENSION
a) place the
packer well
clear of the
perforation
b) only scrape a
minimal area
where the
packer will sit
c) do NOT run the
scraper lower
PERFORATIONS
FINES CAN ENTER
PERFORATIONS
In any workover
operation, beware of
circulating debris from
the bottom of the well
past the perforations especially on
fractured wells.
JUNK
FALLS
TO TD
NO OBSERVABLE DAMAGE
TO PERFORATIONS
DAMAGE TO PERFORATIONS
IF NOT PREVIOUSLY KILLED
BY LCM
WORKOVER OPERATIONS CARRIED OUT WITHIN PERFORATIONS CAN CAUSE
SUBSTANTIAL DAMAGE
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WORKOVERS
250
Drill out cement
200
Workover ends
here
150
100
Losses cease
indicating that
cement has
plugged the
perforations.
Scrape casing at perforations
50
Perforations still open
0
DATE
CERTAIN WORKOVER OPERATIONS CAN PLUG UP OPEN
PERFORATIONS WITH DEBRIS, D-05
(d)
Kill pills may be needed to bring losses down to a controllable level (for
well control/safety purposes), but they may also be needed to prevent fines
– as generated in ‘c’ above – from entering the perforations/formation.
60
40
PI OF WELLS INCREASES
0.3
1.2
3.1
20
0
4.6
6.4
Perforations
protected by kill
pill. PI
maintained or
enhanced
-20
-40
-60
Short Term PI Change
Long Term PI Change
-80
-100
PRODUCTIVITY INDEX CHANGE ON RIG WORKOVER - PERFORATIONS
PROTECTED BY LCM PRIOR TO DELETERIOUS DOWNHOLE OPERATIONS
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WELL PRODUCTIVITY AWARENESS SCHOOL
60
40
PI OF WELLS INCREASES
0.3
0.5
1.1
2.1
3.1
6.1
18.9
20
No kill
pills
pumped.
PI's badly
affected.
0
S
U
R
G
E
-20
-40
-60
A
C
I
D
P
L
U
G
-80
-100
Short Term PI Change
A
C
I
D
Long Term PI Change
PRODUCTIVITY INDEX CHANGE ON RIG WORKOVER - PERFORATIONS NOT
PROTECTED BY LCM PRIOR TO DELETERIOUS DOWNHOLE OPERATIONS
10
PERFS NOT KILLED BY LCM
PRIOR TO SCRAPING
PERFS KILLED BY LCM
0
-10
-20
-30
Short Term PI Change
Long Term PI Change
-40
-50
-60
EFFECT OF SCRAPING OR MILLING ADJACENT TO OPEN
PERFORATIONS DURING RIG WORKOVERS
(e)
When selecting a kill pill, conduct careful research on the products and
types available. Check that the pill is compatible with all the fluids that will
be used prior to the clean-up. A means of actively cleaning up the pill
must be devised in case it does not clean up by itself.
In Prudhoe Bay ‘Liquid Casing’ is recommended as the kill pill for the
lower permeability wells, and a ‘Liquid Casing/OM Seal’ blend is
recommended for the higher permeability wells. These kill pills will clean
up with backflow; however if a well were not to return to production as
anticipated, the kill pill can be degraded with a 2% sodium hypochlorite
wash. Clean up of Liquid Casing has been so successful within N. Sea
wells that this contingency has yet to be required.
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Note: ‘Liquid Casing’ is a proprietary product of fine grained cellulose fibres.
OM seal is the same product, but of a coarser grade. The product manages
to form a thin internal filter cake, which effectively prevents further losses.
However the cake will easily be produced back and/or can be washed
away. Whatever the claims of the manufacturer, the product must be tested
with your kill pill formulation and with your core for return permeability
and lift off.
(f)
Low PI wells are more easily damaged than high PI wells. These wells
require killing by a particulate kill pill; not to reduce losses to an
operationally acceptable level, but to prevent damage.
(g)
Hydraulically fractured wells are easily damaged: a 40% loss of PI has been
recorded. They require a different approach. In Prudhoe Bay a 20/40
carbolite proppant pill is placed across the fractured interval before a
coarsely graded LCM pill is pumped on top.
(h)
Prudhoe Bay have found that XCD polymer is better for well clean-outs
than HEC.
10
SIZED BORATE
SALTS
HEC
CELLULOSE
FIBRES
5
0
SIZED SODIUM
CHLORIDE
4
NO PILLS
NO NEAR PERF NEAR PERF NO NEAR PERF NEAR PERF
MILLING OR MILLING OR MILLING OR MILLING OR
SCRAPING
SCRAPING
SCRAPING
SCRAPING
3
8
-5
12
6
-10
Number denotes number of back
analysed in each category
-15
-20
3
10
-25
KILL PILLS: SUMMARY OF OVERALL EFFECTIVENESS IN
NON-FRACTURED WELLS
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Water Shut-Off Treatments
WATER is the single most obvious culprit of production-related damage.
The science – or art – of water shut-off is included here.
Options include:
• Bridge plug to isolate part of well.
• Cement plug; dump cement in well-bore to shut off bottom perforations.
OIL
OIL
CEMENT
PLUG
WATER
WATER
WATER SHUT-OFF ACCOMPLISHED WITH CEMENT PLUG
• Cement squeeze; shut off all perforations and selectively re-perforate.
• Casing patches.
• Micro-cements and equivalents to repair failed cement jobs and near-well
fractures.
• Near-well permeability blockers; organic/inorganic gels, water-triggered
hydrogels, resins, injection of particulates, microbial emulsion formers,
precipitation of salts, rigid foams.
• Relative permeability modifiers.
• Viscous polymers, mobility control foams, in-depth gels.
COILED TUBING
OIL
OIL
WATER
The impermeable shale
barrier is incomplete. A
cement plug across the
water zone may actually
promote water coning.
GEL
Gel or resin is pumped into
the water zone via coiled
tubing. Although a c/t packer
is used for diversion the
treatment may still flow
upwards and shut off the oil
as well as the water!
GEL
FLUID
PROTECTIVE
PRESSURE
FLUID
OIL
WATER
PRESSURE
FLUID
WATER
GEL
FLUID
In this application the gel or resin
is prevented from flowing
upwards by a protective pressure
fluid (diesel or water) being
pumped dow the annulus. This
application needs careful
balancing of pressures and fluid
mobilities.
WATER SHUT-OFF WHERE CEMENT PLUG IS INSUFFICIENT
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WORKOVERS
r2
PRESSURE
FLUID
OIL
GELLING
FLUID
WATER
O
V
E
R
F
L
U
S
H
h1
A
h2
OIL
WATER
The gel or resin is pushed away
from the wellbore using an
overflush. The pressure fluid
keeps the gel in the water leg.
GEL
GEL
GEL
B
Gel block is effectively holding the
water back, yet is leaving a large
proportion of the perforations open
for the flow of oil.
WATER BLOCK AWAY FROM THE WELLBORE
There are hundreds of different mechanical and chemical methods for water shutoff to choose from. No-one is expert in all methods, and experts tend to be
partisan. There is no ‘industry manual’ for process selection and design. There is
no cure-all process at present and what is successful in one field may be
inappropriate elsewhere. Inappropriate target-process pairings have undoubtedly
led to some disappointments in the past. The ‘success’ rate has not been high
overall. In particular, the duration of the improvement obtained from small, nearwell treatments is often limited. These operations, which are usually of low cost,
often pay back quickly, but the average percentage effect on oil recovery has
been small.
It has not always been easy to find out what worked and what failed. Operators
and technology suppliers have previously been less than open. For example,
many thousands of gel-based treatments were carried out in the US in the
seventies, but relatively few results have been reported in detail. In part the US
anti-trust laws and issues involving the windfall profits tax prevented information
exchange. Often service companies and chemical vendors would perform a job,
but then never found out from the operator what went right or wrong, or were
not permitted to talk about it. Many operators developed in-house technology,
patented it, and considered it secret. The patent literature is now immense,
particularly for viscous polymers and chemical gels. Probably most of those
processes work in the laboratory as claimed, but clear-cut application results are
often lacking. It is hard to say whether a process or chemical failed when the
shortcoming might be in the target selection or in deployment. A success at least
proves the process works under some conditions.
This situation is changing. Co-operation between operators in general is
increasing in non-strategic areas of this type. Industry technology exchange
groups in water shut-off have just been set up in the USA and Europe. This
co-operation can already help the participating companies access the right
technology for the job, though there is still much to be gained.
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WELL PRODUCTIVITY AWARENESS SCHOOL
There are two areas where the technology of water shut-off has improved
dramatically:
• powerful, realistic, predictive numerical simulation tools that combine reservoir
structure, multiphase fluid flow, well test data, production history, process
mechanism and process deployment.
• the deployment of treatments using coiled tubing to accurately place water-blocking
materials.
There are two approaches to evaluating whether or not a water shut-off system will
work:
• ANALYTICAL APPROACH – Simulation. Expensive and time-consuming and yet
still has to be field proven.
• EXPERIENCED-BASED APPROACH – Experiment with process and procedures on
low cost (disposable) well. This second approach cannot be used on limited
expensive high production wells in such areas as N. Sea/Alaska.
Of all the methods of water shut-off there is increasing promise in the area of gel-type
water blocking. However, for proprietary reasons, few of these chemicals/processes
are reported in detail. The difficulty arises when trying to match the success of a
particular chemical/process in one area with the potential success in a new area. This
is where the analytical approach becomes so important.
There are several methods of blocking off the water using gel. Some of these are
illustrated on the previous page. Not illustrated is a method of pumping the gel into a
reservoir where water has broken through in the high permeability layers. The
treatment is pumped, and will naturally flow into the high permeability layers. In the
lower permeability layers the gel is prevented from becoming a block because it is
removed by adsorption and dispersion. Sometimes ‘cold flushes’ are used to help the
self-selective placement of the gels in the high permeability layers.
The chemistry of the resin systems, organically cross-linked gels, metal ion cross-linked
gels, in situ polymerisation systems, swelling hydrogels and relative permeability
modifiers etc. available would fill a book on their own. The mechanical methods
would fill another. Suffice to say here, that there are methods that work, but greater
industry co-operation is required to establish which system works where, and why.
Coiled Tubing
a)
Drilling
The technical feasibility and economic viability of coiled tubing drilling (CTD) has
been proven, and the progress of this emerging technology is evident in the
growing band of operating companies committing to multiwell CTD campaigns.
The first attempts at CTD drilling were in the mid-1970’s but the technique
essentially failed because of a lack of understanding of the fatigue damage that
results from bending and straightening the tube. By 1991, with better technology
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WORKOVERS
Re-entry
New wells
Straight
holes
Disposable
exploration wells
Well deepening into
new producing zone
Lateral
holes
Horizontal
extension
into
producing
zone
Original
Multiple
radial
drainholes
New
Deviated
development
wells
POTENTIAL APPLICATIONS FOR COILED-TUBING DRILLING
and larger OD coiled tubing, the technique had been re-introduced. CTD has
grown from 4 jobs in 1991 to an estimated 120 in 1994.
A standard CT unit has to be adapted for drilling; however this is not a massively
onerous task. All CT units already have the equipment to operate under pressure,
and can thus be adapted to drill, trip and complete wells in underbalanced
New Wells
17
Horizontal
Reentries
12
15
Well
Deepenings
Schlumberger Dowell
CT DRILLING JOB DISTRIBUTION AS OF 02/94
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WELL PRODUCTIVITY AWARENESS SCHOOL
conditions. Typical changes are those to the BOP systems to handle drilling
tools/motors, and a modular mud system (incorporating all the methodology
necessary to handle mud and kicks as explained in the previous section on
slimhole drilling).
Union
Stripper head
4 1/ 16 in, 10,000 psi blind rams
4 1/ 16 in. 10,000 psi cutter rams
Kill line
4 1/ 16 in. 10,000 psi slip rams
4 1/ 16 in. 10,000 psi pipe rams
Conventional
Coiled Tubing
BOP
Adapter spool
Blind flange
Spool
Blind flange
Spool
Return line
7/
16
in. 5000 annular
preventer
Return line (for underbalanced drilling).
Returning fluid goes through a separator
and gas scrubber. Oil is stored, gas is flared
7 1/ 16 in, 5000 blind rams
7 1/ 16 in. 5000 psi pipe rams
Extra BOP
to handle
BHA
Kill line
Spool
Casing bowl
* Hole size greater than 4 in
POSSIBLE BOP STACK CONFIGURATION FOR COILED TUBING DRILLING
Advantages
Without a long history of job performance it is difficult to define what all of the
advantages of drilling use coiled tubing drilling will be. We can, however, make
certain performance claims based on conventional coiled tubing experience:
–
–
–
–
–
shorter trip times
less space requirement on location
transportability
lower costs (specific applications)
directional control while underbalanced
An important feature of this technique is the ability to drill while underbalanced.
Continuous pipe, live snubbing and high pressure wellhead control are the
primary systems that make this possible. There are several reasons for drilling
underbalanced:
–
–
–
–
–
–
–
192
prevent formation damage
avoid using costly drilling fluids
prevent fluid losses
minimise fluid disposal costs
improvements in ROP
potential for oil production while drilling
avoid cost of stimulation
Revision 2001
WORKOVERS
Note that all
trips can be
achieved
underbalanced,
and
completions
can be run in
the same
manner.
Solids disposal
Fluid pumpers
Filter
skid
Flare stack
Return line
2" coiled tubing unit
Wellhead support
CTU control unit
Data
recording
BOP control
21 m
DIMENSIONS FOR TYPICAL ONSHORE SITE
It is sometimes possible to achieve an underbalanced condition with a single
phase liquid. Often, however, the drilling fluid must be gasified. While
formation gas or air can be used in this application, nitrogen, because it is an
inert gas, is most commonly used.
UNDERBALANCED
OVERBALANCED
Fracture
plugging
Drilling
fines
migration
Fluid
leakoff
Filter cake
Formation
Pressure
drop
Formation fines
production
Fluid
losses
Oil & gas
flow
Drilling fluid flow
Drilling fluid flow
Wellbore
CIRCULATION DESIGN
Proper analysis of the circulating conditions
is required to ensure that the underbalanced
objective is achieved. The rheological
effects of the two-phase fluid, both in the
CT string and returning up the annulus, must
be understood and interpreted. Pressures
must be tracked to assess both the
underbalanced condition and the nitrogen
volume factor. When using low viscosity
drilling fluids the turbulence characteristics
and liquid velocity profile must be known
to ensure cuttings transport.
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GAS LIFTING
Two phase
annular flow
Two
phase annular flow
with liquid/gas
with
liquid/gas slippage
slippage
Nitrogen
Nitrogen
(lowers density)
(lowers
density)
Drilling fluid
Drilling
fluid
(transports
(transports
cuttings)
cuttings)
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WELL PRODUCTIVITY AWARENESS SCHOOL
HORIZONTAL EXTENSION
Distance limited by ability to maintain weight on
bit for given Hole and Coiled tubing diameters
Coiled tubing
Coiled tubing
Coiled tubing adapter
Coiled tubing adapter
Disconnect mechanism
(to disconnect coiled tubing
if BHA becomes stuck)
Disconnect mechanism
Drill collars
Drill collars
Orienting tool
Muleshoe sub.
Positive displacement
mud motors
Positive displacement
mud motors
Adjustable bent housing
Extended gauge length
fixed cutter bit
Angle holding assembly for coiled
tubing drilling. Add muleshoe sub. to
accommodate survey tool for
horizontal applications. Use
minimum account of collars for
horizontal applications. For vertical
applications, collars should provide
necessary weight on bit.
194
Short gauge length
fixed cutter
Angle building assembly for coiled
tubing drilling.
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WORKOVERS
At present, CTD tends to be more costly. The costs should come down as the
technique is refined and developed. Offshore, CTD will be quickly competitive
because of reduced mobilisation and demobilisation costs – if a derrick set is not
already installed on a platform.
The greatest disadvantage of CTD is the reliance on slimhole motors. These are
both costly and can be unreliable. There is also the productivity issue, as
discussed in the previous section on slimhole drilling in general.
Coiled tubing drilling has been used in the early stages by Elf in the Paris Basin,
and NAM in the Netherlands are experimenting with the technique. The first
NAM well was a re-entry drain hole through a milled window. An expensive
experimental formate mud was used to drill this well.
As seen above, CTD can have problems with milling windows because of
insufficient weight on bit. To overcome this one company has developed ‘thrusters’.
Such systems are available for hole sizes as small as 37/8”; however the larger
casing sizes, 7” and greater, may require larger coiled tubing (greater than 13/4”).
Coiled tubing drilling is becoming an important factor in the development of the
Arctic. Prudhoe Bay operators are industry leaders in the use of coiled tubing for
a wide variety of operations, and are now pressing ahead with CTD. Since a well
in the area can cost an average of $2.5 million, and a rig based sidetrack $1.7
million, there is an obvious time and economic advantage if CTD sidetracks can
be accomplished for $500,000.
Depth limits of coiled tubing drilling are governed more by the size and weight
restrictions of the reel trailer used to transport the coiled tubing than by the
strength of the coiled tube itself. The larger the coiled tubing diameter the
shorter the length of coiled tubing that can be transported legally on public roads.
Developments are underway to produce a reliable connector to join together two
reels of coiled tubing for drilling purposes.
The life of a coiled tube is a critical factor in this technique. Coiled tubing drilling
subjects a tube to far greater stresses than normal cased hole operations. The life
of coiled tubing used in drilling service can be maximised by:
• Ensuring that the coil is never used to pump corrosive chemicals
• Minimising solids in the mud.
• Minimising the number of times that a given section of coil is run over the
guide arch and injector head.
• Designing BHA's to minimise the weight that must be slacked off on the coil to
achieve acceptable penetration rates.
• Never 'stacking' the weight of the coil on the bit.
In CTD, PDC bits are applicable for use in medium to soft formations. TSD
(thermally stable diamond) or natural diamond bits are required for hard
formations. Core barrels developed in the mining and the engineering geology
(site investigations) industries can be adapted for coring with coiled tubing.
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WELL PRODUCTIVITY AWARENESS SCHOOL
Wellbore hydraulics
Cuttings transport is especially important because unlike conventional drilling
operations it is not possible to rotate the coiled tubing and therefore the build-up
of a cuttings bed on the low side of the hole must be avoided.
Beware fatigue
in coiled
tubing
Coiled tubing
connectors needed
for deep wells
Lift
limitation
on offshore
cranes
Conventional
coiled tubing
BOP
Extra BOP
for drilling
tools
Special muds
may be
required
e.g. formates
Depth limited
by lock-up
Orienting
Tool
No rotation beware of
cuttings
build-up
CT Pull or
Pressure Release,
flapper valves,
CT connector
3" OD Monel with
Slim 1MWD or
WL steering tool
2 7/8" to 3 1/2" OD
Downhole Motor
with bent housing
CONSIDERATIONS FOR COILED TUBING DRILLING
The avoidance of cuttings beds is most easily achieved through ‘turbulent’ flow
methods. The use of computer models becomes essential in order to ensure the
necessary liquid phase velocities in nitrified fluid dilling operations
NON-TURBULENT CUTTINGS
TRANSPORT
Non-newtonian
viscous fluid
Cuttings
Coiled tubing
TURBULENT CUTTINGS TRANSPORT
Newtonian fluid
Cuttings
Flow in
turbulence
Coiled tubing
Cuttings bed
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WORKOVERS
Data Telemetry
The use of coiled tubing with logging cable installed inside the tubing bore was
pioneered by Nowsco in 1985 and has been in regular service with conventional
CT units for logging horizontal wells since the late 1980’s. The availability and
practicality of hardwired communication methods permits the use of traditional,
reliable steering tools regardless of fluid mixtures being pumped through the
coiled tubing. This is particularly important for underbalanced drilling operations
where the use of nitrified fluid is required. (Conventional pressure pulse MWD
systems do not work in compressible fluid systems.)
Coiled tubing
Flow
Armour braid
Multiple conductors
Longest Section Drilled with Coiled Tubing
As of March 1993 this accolade goes to Dowell Schlumberger drilling
for Elf in the Paris Basin. D/S-Elf drilled 4182’ of 37/8" hole.
b)
Completions
The use of coiled tubing in the oilfield is perhaps one of the fastest developing
technologies. Traditionally CT has only been used for nitrogen lift to kick-off
wells, for conveying fluids (e.g. acid) to the perforations to obviate bull heading
or for fishing inside completions. Nowadays CT is used in many more
applications. For instance, coiled tubing re-completions have evolved from mule
shoes on the end of velocity strings to:
•
•
•
•
•
•
•
Revision 2001
pump-through shearable plugs
seal assemblies
locator subs
side-pocket gas lift mandrels
non-upset reelable gas-lift valves
jet pump equipment and landing nipples
surface controlled sub-surface safety valves
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WELL PRODUCTIVITY AWARENESS SCHOOL
Safety valve
hanging inserts
Safety valve
landing nipple
– Coiled tubing hung off in the
nipple profile of the sub-surface
safety valve. An insert SSSV
was installed that utilised the
existing control line.
Coiled tubing
connector
2 7/8" coiled
tubing
completion
– 6136 ft of coiled tubing installed.
– tubing/tubing connectors used to join
sectors of coiled tubing to make full
string length.
Temporary
formation isolation
packer
– in this particular completion the
permanent packer set early, which
necessitated the setting of a
temporary formation isolation packer
above.
– a velocity string is installed in the
later life of the field when the lower
production rates dictate a smaller
tubing size.
Permanent
packer (coiled
tubing conveyed)
2 7/8" coiled
tubing velocity
string
This operation was conducted on a
platform. No lift exceeded 16 tons.
The reel was shipped in three 2500 ft
lengths. Operating time for an
installation such as this is five days and
could save up to 50% of the cost of a
conventional workover. Five wells
were completed in this manner.
Similar completions are run in Alaska.
In the USA, Nowcam have
installed a 20,500 ft 11/4" coiled
tubing completion.
EXAMPLE OF NOVEL COILED TUBING COMPLETION
This completion was installed by Nowsco and Otis in the Shell Leman Field in
the Southern North Sea.
Manufacturers are developing more packers that can be set on coiled tubing.
These packers have to made up onto the CT without any rotation.
In Prudhoe Bay spoolable gas-lift valves were factory installed in a 23/8" reel of
coiled tubing and successfully run in a well. The downside of having to pull a
production string to change gas-lift valves is somewhat offset by the ease of
pulling continuous tubing.
Coiled tubing re-completion options will be nearly complete when downhole
control lines can be designed and incorporated in live installation applications.
Control lines are now available installed in coiled tubing, but they are not
attached to the coiled tubing.
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WORKOVERS
At present, coiled tubing used for completions is not available in the corrosion
resistant alloys that are necessary in many corrosive environments. This is
expected to change with time as coiled tubing completions gain acceptability.
c)
Well Maintenance
Reservoir monitoring is a critical factor in management of reserves and
maximising of productivity. With the advent of high-angle and horizontal wells,
such operations have moved from wireline to coiled tubing conveyed.
Coiled tubing can be used to run memory gauges into horizontal wells, or indeed
memory PLT’s. If the operator is prepared to expend the extra dollars, real-time
PLT’s can be run on ‘stiff’ coiled tubing, which has an electric line inside the tubing.
ADVANTAGES AND DISADVANTAGES OF CTD
COILED TUBING DRILLING APPLICATIONS
Re-Entry
CT can re-enter existing wells, set a
whipstock, mill a window in the existing
casing or liner, and drill into the reservoir
(usually horizontal, although several have
been vertical). Drainholes deeper than 1,400
ft have been drilled. Multiple drainholes
extended from a single well bore are under
consideration.
Combination Drilling
Conventional rotary drilling equipment is
used to drill upper zones and set casing.
The zone(s) of interest then are drilled using
CTD techniques
in underbalanced
conditions. The capability of drilling multiple
deviated well bores with minimal formation
damage will improve production potential for
such wells. The overall economics of single
well completions and field development
using this techniques is attracting much
attention.
Disposable Exploration And Observation
Wells
Inexpensive small holes are drilled to obtain
formation or reservoir data for exploration or
delineation. Typically,
these wells are
plugged and abandoned when sufficient data
has been acquired to monitor reservoir
parameters during subsequent production.
Production And Injection Wells
Under the right reservoir and production
conditions, a small hole is drilled and a CT
string cemented in place to provide a small
diameter, inexpensive well for production or
injection.
Underbalanced drilling and improved well control
• Full pressure control possible throughout drilling
operations.
• Underbalanced tripping, drilling, and completion reduces
formation damage and permits faster penetration with
reduced risk of differential sticking.
Continuous drillstring
• Allows continuous
circulation
while tripping.
• Eliminates joint related problems and allows faster
tripping.
• No pipe handling, which improves safety and reduces
noise.
• Reduced environmental impact. No spillage at joints.
• Simplified
automation,
reduced
manpower.
Compact unit and equipment configuration
• Reduced drill site size and associated
• Reduced mobilisation
and demobilisation
costs.
costs.
Wireline inside the CT drillstring
• Allows highspeed telemetry
for measurement and
logging while drilling (MWD, LWD).
• CT protects wireline and simplifies operations through
simultaneous spooling of tubing and wireline.
• Electrically operated directional control is possible.
Drillstring cannot be rotated
• Downhole motors required, even for vertical wells.
• An orienting tool is required for steering.
• Higher friction with the borehole wall.
Limited to slimhole applications
• Largest hole to date is 6 1/4 in., larger holes technically
are feasible.
• Small hole size limits the number of casing strings and
liners that can be run.
Wireline inside the CT drillstring
• Fatigued or damaged sections of CT cannot be removed
from the drillstring.
New technique
• Currently in the learning curve.
• Workover rig may be required to pull existing completion
or run large casing/liners.
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S U M M A RY
Summary
Revision 2: 2001
202
Where Do We Go From Here?
202
Communication
203
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WELL PRODUCTIVITY AWARENESS SCHOOL
Summary
Where Do We Go From Here?
There is only one way to go - FORWARDS!
EVERYONE must take responsibility.
THINK PRODUCTIVITY
By now you should have a fair understanding of the myriad of mechanisms that
cause formation damage. You should know most of the factors that affect well
productivity. What can you do to make things better?
This book cannot tell you, the individual, what specifically you can do. You
know your job and your part of the operation. It is up to you to go back to the
office or the field and think where this new or improved knowledge may best be
deployed. This school should have made you aware of the problems, and has
given you some of the solutions. You can go out and apply and develop those
solutions.
When you are involved in any operation, remember the old cliché,
‘PREVENTION IS BETTER THAN CURE’ .
Whenever you are planning a well, a workover, or a well servicing operation,
think in terms of the life of the well
and not just the immediate future. What
will be the consequences of your actions - this year, next year, and in several
years time?
BUT WHERE DO YOU GO FROM HERE?
Remember that
Awareness is all important
• Take an interest in well productivity
• Think before you act
• Try and improve your operation
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S U M M A RY
When you are on site, think of the consequences of all your actions; not just in
the immediate future but in the years ahead: a short cut to save time and money
now could cost dearly in future production and revenue.
Communication
BREAK DOWN THE BARRIERS
Even if you have inwardly digested everything taught in this school, you alone
cannot be totally effective in your quest for zero formation damage and maximum
well productivity. You must communicate with others and they with you.
For instance, you must involve the operator geoscientists and engineers when
planning your well or well management programme; they may have information
on the geology of the particular reservoir that will assist you to do your job better.
The engineer in the office must liaise better with the personnel on the rig;
everyone has a contribution to make towards the goal. The danger is of certain
people working in isolation, and ignoring the needs of others: the drillers may
want oil based mud to prevent stuck pipe and to get the hole down quicker,
whereas the reservoir engineer may not want certain surfactants in the formation.
Discuss it; reach a compromise, or implement a change of plan. The office-based
personnel may only allow one day for clean-up of an uncemented well; the rigbased personnel may well have more experience and know that this will
probably take far longer. Discuss it; set better criteria or adopt better
methodology or chemicals etc. etc.
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WELL PRODUCTIVITY AWARENESS SCHOOL
THE DANGERS OF WORKING IN ISOLATION
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S U M M A RY
'TEAMWORK' - REMOVE THE BARRIERS
Pull together to improve well productivity
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G L O S S A RY
Glossary
Acidisation
The use of acid to stimulate wells.
Anisotropy
Property of having different physical
properties when measured in different
directions.
Aquifer
The body of water below an oil/gas reservoir.
If a reservoir has a good water-drive, it means
that the aquifer if limitless and can maintain
the pressure in the reservoir as oil/gas is
removed. In multi-faulted reservoirs the
aquifer may be compartmentalised and it
cannot maintain the reservoir pressure. Water
injection into the aquifer assists in maintaining
reservoir pressure.
Barefoot
An open hole completion - no casing or liner
installed.
Big Hole Charges
Creates a big, shallow perforation with a large
entry hole for gravel pack operations.
Breaker
A chemical added to a viscous solution that
will ‘break’ (reduce) the viscosity with time
and/or temperature.
Cap Rock
An impermeable rock directly above a
reservoir which traps hydrocarbons in the
reservoir.
Capex
Capital expenditure. A term used in
economics to differentiate between fixed upfront expenditure and operating expenditure.
In normal tax regimes Capex cannot be
written off immediately against the project in
calculating profits before taxation.
Cash Flow
A financial expression of the cash flowing
through a business with time.
Chert
Cryptocrystalline silica (structure is so small
that it cannot be seen even under a
microscope). Very hard rock.
Clastic
Sedimentary rock made up from fragments of
silica laid down mechanically by water or
wind.
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WELL PRODUCTIVITY AWARENESS SCHOOL
208
Completion Fluids
Salt solutions, often filtered, which must be
non-damaging.
Coning
The phenomenon of inducing gas or water to
move into a wellbore due to high drawdown.
Crushed Zone
A small zone around perforation where rock
has been deformed.
Data Frac
A ‘small’ frac conducted before main
treatment providing data which is used to
‘fine tune’ main treatment.
Debris
Small flakes of material formed when
perforating charge disintegrates.
Deferred Production
Oil or gas production that is delayed due to
formation damage and/or well productivity
problems. The oil/gas is deferred to the end
of field life and therefore has a lower value in
NPV terms (unless the oil/gas price has soared
in the interim).
Discounting
See Net Present Value.
Diversion
A technique to ensure treatment of multiple
zones.
Drainage Radius
The area around a well from which a well
drains oil/gas. The closer that wells are
means the smaller the drainage radius of each
well.
Drawdown
The pressure difference between well and
reservoir which causes well to flow.
Feldspar
Silicate material. Pure silica is SiO2, but
feldspars also contain magnesium, aluminium
and other elements.
Filter Cake
A thin layer of material deposited from the
drilling fluid onto and into the surface of the
wellbore which controls fluid loss to
formation.
Fines Migration
Effect of inducing the movement of small
particles through the reservoir which may
plug the near wellbore area and reduce
oil/gas rate.
Revision 1: January 1995
G L O S S A RY
Flexing
Technique of applying pressure to tubing to
get it to “balloon”, and thus dislodge
corrosion and/or scale from the walls of the
tubulars. The dislodged debris must then be
circulated out of the hole, and must not enter
the perforations/formation. Flexing is often
done on a frac workstring that will be
subjected to high pressures.
Flow Efficiency
The ratio of low rate with actual skin/flow
rate with zero skin.
Fluid Loss (Invasion)
The rate of loss of fluid from wellbore to
formation.
Formation Damage
A reduction in permeability around the
wellbore due to drilling/completion/
production action.
Frac Pack
A combination of hydraulic fracturing and
gravel packing to prevent sand production
while maximising well productivity.
Fracture Conductivity
A measure of the ability of a fracture to permit
flow of oil/gas.
Gravel Pack
A means of preventing sand production into
wellbore.
Heterogeneous
A rock which displays differences in texture
which give differences in porosity and
permeability.
Hydraulic Fracturing
Deliberate fracturing or rock using viscous
gels to improve well productivity.
Microcrystalline
Very fine crystalline structure; not visible to
the naked eye, but can be seen under the
microscope.
Matrix
The actual body of a rock, as opposed to the
pore space. A matrix acidisation is one that
affects the whole rock as opposed to just the
perforations (an acid wash).
Net Present Value (NPV)
A method of expressing the time-value of
money by discounting all monies back to a
fixed point at the beginning of the project.
An NPV forecast requires a ‘discount rate’ to
express the time-value of money. The
discount rate is normally 10% or 15%.
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Opex
Operating expenditure. A term used in
economics to define monies spent to operate a
project on a day-to-day basis (e.g. personnel,
consumables, power etc.). Operating
expenditure can immediately be written off
against income when calculating pre-tax profits.
Overbalance
The amount of pressure in excess of hydrostatic
pressure exerted by the mud on the formation.
P and A
Plugged and Abandoned. When a well is
‘dry’ or some mechanical problem prevents its
use as a production well. In the past, most
exploration wells were ‘P and A’d’ but many
are now kept as future producers.
Perforation
The link between reservoir and wellbore.
Perforation Plugging
The blocking of perforations by any material
introduced from well/reservoir.
Perforation Skin
Mechanical skin created by poor perforation
design.
Permeability
A measure of the ability of fluids to flow
through a rock.
pH
Hydrogen ion potential. A measure of the
acidity of a solution.
5
6
7
8
9
210
=
=
=
=
=
more acidic
acid
neutral
alkaline
more alkaline
Pickling
Technique of circulating dilute acid around
the tubulars that are to be used for an acid
job. The acid would loosen and remove any
scale or rust products. Care must be taken
that these are circulated out of the hole, and
that they do not enter the
perforation/formation.
Plateau
The production level at which a field is
produced. During the plateau period the
production from the field is potentially higher
if wells are beaned up. After a certain time
(usually years) a field will come ‘off plateau’
and production will decline. Damaged wells
will come ‘off plateau’ sooner than wells
drilled without formation damage or
completion skins.
Revision 1: January 1995
G L O S S A RY
Pore Throat
The connections between the pore spaces.
Porosity (Pore Space)
The percentage of void space in rock where
fluids are stored, expressed as a percentage.
Proppant
Sand, ceramic beads or sintered bauxite used
to keep open a hydraulic fracture.
psia
Pounds per square inch - atmosphere. This
differentiates a gauge pressure measurement
from an absolute pressure measurement.
Atmospheric pressure is 14.74 psi or 1 bar, yet
a gauge at surface will read 0 psi.
Radial Flow
A description of how fluids flow from the
reservoir to the wellbore.
Relative Permeability
A comparative measure of the flow of oil in
the presence of water or gas.
Reservoir
A rock which contains oil/or gas.
Sand Consolidation
The use of plastics or resins to bond
unconsolidated sand grains.
Scale
Any inorganic solid material that precipitates
in the wellbore of reservoir due to oil/gas
production or related operations. Can
severely reduce well productivity.
Secondary Porosity
Primary porosity is that found in the spaces
between sand grains or carbonate clastics.
Secondary porosity is developed later by
leaching or diagenesis (pressure/temperature
changes).
Seismic
Exploration method whereby vibrations are
created at surface (dynamite, air-guns,
vibrators/thumpers etc.) and the reflections off
the subterranean rock surfaces are recorded
on geophones. The results are processed by
computers to provide the geophysicists with
traces than can be interpreted to identify the
rock structures (folds, faults, unconformities
etc.).
Shot Density
Number of perforations per foot.
Skin
An indirect measure of the unexpected
pressure drop near the wellbore. A
dimensionless number.
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Solubility
A measure of the ability of a solid to dissolve
in a liquid (temperature and pressure
dependent).
Stimulation
A technique to improve well productivity.
Stock Tank Barrel (stb)
Expression to relate the volume of a barrel of
oil at surface as opposed to a ‘reservoir
barrel’. Oil ‘shrinks’ as it comes to surface.
Each oil has a Bo measurement which relates
the volume in the reservoir to the volume in
the stock tank.
TCP
Tubing Conveyed Perforating Guns
Unconformity
A time break in the depositional sequence of
rocks, e.g. much younger rocks deposited on
an eroded surface of older rocks. This would
indicate a break in the deposition of
sediments in an area over a period of tens or
hundreds of millions of years.
Underbalanced Perforating
Perforating conducted with a large pressure
difference between reservoir (high pressure)
and tubing (low pressure).
Viscosity
A measure of how easy a fluid will flow
(honey is more viscous than water).
Wax
Organic product that deposits in reservoir,
tubing, flowlines, pipelines. Big impact on
well productivity.
Work string
Dedicated string of drillpipe or tubing. In
stimulation, such a string would be used
because of its acid resistance, pressure
capability, and its cleanliness.
Revision 1: January 1995