Reservoir Baffling Seen by Disequilibrium of DFA Fluid Gradients and by

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Reservoir Baffling Seen by Disequilibrium of DFA Fluid Gradients and by
Wireline Pressure Transients and DSTs
Thomas Pfeiffer and Vladislav V. Achourov, Schlumberger; Terje Kollien and Sven-Erik Foyn, Lundin;
Soraya S. Betancourt and Julian Y. Zuo, Schlumberger; Rolando Di Primio, Lundin; Oliver C. Mullins,
Schlumberger
Copyright 2016, Offshore Technology Conference
This paper was prepared for presentation at the Offshore Technology Conference held in Houston, Texas, USA, 2–5 May 2016.
This paper was selected for presentation by an OTC program committee following review of information contained in an abstract submitted by the author(s). Contents
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Abstract
In this reservoir study, three adjacent structures have been subject to largely the same fluid charge with
an original oil charge and a very recent light hydrocarbon charge (all indicated by petreolum systems
modeling and organic geochemical analyses). In addition, all wells have an oil-water contact (OWC) and
two have a gas-oil contact (GOC), while the GOC in the third well is not far away. Thus, all
depth-dependent in-reservoir fluid geodynamic processes are visible within each well; no extrapolation
away from the wells is required. Moreover, the ~30 meter oil columns in evidently connected sands are
amenable to simple dynamic modeling thereby aiding in understanding. All three structures are found to
have very different reservoir realizations, particualry regarding the dispositions of asphaltenes in spite of
nominally similar initiation conditions after the secondary charge. That is, different reservoir fluid
geodynamic processes took place producing different constraints on production in each of the structures.
One well showed a light oil underlain by a tar mat. A second well showed large, disequilibrium gradients
of gas-oil ratio (GOR) and asphaltene content without phase separated asphaltenes in core. The third well
showed a tar mat on a shale break in the oil column not far form the GOC. There were no asphaltenes in
core above the shale break and tar mat. However, below the shale break there was asphaltene throughout
the core while retaining permeability, but no tar mat on the OWC. These differences were not ascribed
to any paleo-OWC nor are they related to differing biodegradation. In addition, these differences are not
consistent with any depressurization expalanation.
To resolve the differences, a variety of data streams were used including downhole fluid analysis
coupled with thermodynamic analysis from the Flory-Huggins-Zuo Equation of State (FHZ EoS) and its
reliance on the Yen-Mullins model of asphaltenes. In addition, well test results provide key production
information and are corroborated by vertical intereference testing on wireline. Petroleum system modeling
and organic geochemical analysis of oil and core extract samples have also been very useful. The
differences seen in the different wells relate to several important parameters such as the different extent
of baffling which impacts both production rates as well as equilibration rates of reservoir fluids. Another
key parameter is the extent of density stacking versus a lateral fluid front for the secondary light
hydrocarbon charge. Proximity to the charge point enhances the lateral nature of the charge yielding rapid
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asphaltene instability precluding tar mat formation in sections of the well. This information is very useful
when projecting reservoir properties away form wellbore.
Introduction
In order to optimize production, it is important to understand reservoir properties including the distribution
of fluids and possible asphaltene deposition. It is desirable to understand the petroleum system context if
not a petroleum system model (PSM) of the reservoir. Among other things, the PSM provides the timing
type and volume of fluids that enter the reservoir. A missing element in understanding reservoir properties
is accounting for the processes that take place in reservoirs that occur after charge and before present
day.[1] These processes are subsumed in the new technical discipline ⬙reservoir fluid geodynamics⬙.
Figure 1 shows a schematic of the time line of a reservoir.
Figure 1—Schematic of reservoir over (geologic) time.[1] The petroleum system fills the reservoir (among other things). Reservoir fluid
geodynamics redistributes fluids and can lead to tar deposition in the reservoir. Production is modeled by simulation software
Reservoir fluid geodynamic processes connect the petroleum system context to present day production
concerns about the reservoir. These processes include a variety of diffusive and convective processes as
well as other time dependent processes such as biodegradation. The requirement to resolve many
processes associated with reservoir fluid geodynamics was the development of a proper treatment of
asphaltene thermodynamics in reservoirs. The industry’s first equation of state for asphaltene gradients,
the Flory-Huggins-Zuo Equation of State (FHZ EoS) [2,3] with its reliance on the Yen-Mullins model of
asphaltenes [4] has been just the development needed. Nominally, very similar petroleum system
processes can lead to very different realizations within the reservoir, and thereby lead to very different
production concerns. Indeed, many reservoir asset teams do not make use of a PSM. A prevailing view
is that the PSM is primarily an exploration tool, and once a discovery is made and an asset team assigned,
the PSM is no longer needed. The distinct problem is that specific PSM scenarios are not currently able
to predict specific reservoir problems. The role of reservoir fluid geodynamics is to specific possible
reservoir outcomes of a given petroleum system conext.
An example of a petroleum system context that can give rise to an array of reservoir realizations is the
circumstance of a late gas (or light hydrocarbon) charge into an oil reservoir. If there is sufficient reservoir
pressure, this can give rise to an increase in solution gas which can then destabilize the asphaltenes. The
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destabilized asphaltenes can lead to a variety of fundamentally different realizations in the reservoir. The
destabilized asphaltenes can migrate to the base of the reservoir and form a tar mat.
Figure 2 shows the result of an oil reservoir that had a late gas charge.[5] Gas diffusion downward in
the oil column caused the asphaltenes to migrate down (both by diffusion and by gravity currents) until
they ran into an impermeable layer as shown in the schematic in Fig. 2. The impermeable layer was
cement as seen in the thin section in Figure 2. The tar mat which is evident in whole core (cf. Figure 2)
had nothing to do with water; it is on cement. The produced oil is very light, but the little heavy ends that
remained in the oil were unstable and appeared as tar blobs in the produced oil.[5] It is believe that this
was not bitumen in core that flowed with the light oil because the whole core showed good fluorescence
all the way down to the tar mat. In this paper, bitumen and tar are used interchangeably; they are organic
materials of high asphaltene content.
Figure 2—shows the outcome of an oil reservoir with a late gas charge.[5] The gas diffused to the bottom of the column. The
asphaltenes migrated down ahead of the gas front forming a tar mat on cemen at the base of the reservoir. The tar mat is evident in
the whole core images; it does not fluoresce. Thin sections show tar deposited on mineral surfaces. The resulting light oil had high
GOR and little asphaltene. In production, some tar was obtained in the light oil
A different reservoir realization when gas charges into an oil reservoir is shown in Figure 3. Again
asphaltene was destabilized in this process yielding a reservoir oil of high GOR and low asphaltene
content.
Figure 3—Another reservoir with a late gas charge into an oil reservoir. As in Fig. 2, a light oil of high GOR and low asphaltene content
is produced in this process.[6] However, in this reservoir the tar is upstructure and the tar zone is permeable. In addition, the
destabilized asphaltene migrated on order ten meters prior to undergoing a phase transition.[6]
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Figure 3 shows well data from two fields in the same basin.[6] The wells are upstructure, and near salt
as indicated in the cartoon inset in Figure 3. Both reservoirs have a late gas charge into oil. Figure 3 shows
the density-neutron crossover in field 2 (shaded yellow) indicating a high GOR fliud at the top of the
interval. The tar intereval is indicated on the petrophysical log as determined from whole core. For field
1, the whole core is shown; the tar zone on a shale break is where fluorescence disappears. A tar interval
was perforated and straddled with the MDT dual packer, a light oil flowed.[6] The tar zone is permeable.
In addition to the high GOR, low asphaltene produced fluid, a tar is also produced. A photograph of this
tar is also shown in Figure 3. This mobile tar helps create a flow dependent skin in the reservoir which
must be address with xylene soaks of the reservoir.[6]
The tar in these fields is permeable and upstructure. It is clear the tar results from gas charge into oil.
It is also clear that the asphaltenes could migrate some short distances (~10 meters) prior to undergoing
a phase separation producing the tar coating on the sand grains in sections. Consequently, this asphaltene
was subject to a relative fast instability to become phase unstable upstructure in comparison to the
asphaltene that destabilized in Figure 2 that migrated all the way to the base of the reservoir. However,
the details of the process that caused the migrating asphaltenes to become phase unstable have never been
adequately explained.
Case Study
This case study compares the fluid distribution and asphaltene disposition of three structures with a single
well in each (Figure 4). Pressure gradient analysis and fluid contacts indicate that the three blocks are not
in flow communication. All three wells encounter an OWC and two wells have a GOC. The GOC of the
third well is thought to be nearby. The three structures are thought to have similar charge and alteration
histories. The first charge appears to have the same maturity and similar inferred source rock facies.
Biodegradation of the 1st charge is evident at various degrees in all three structures, while a more recent
higher maturity charge evidently caused the asphaltene to re-distribute and destabilize. There is evidence
that the OWC has moved in the course of the alteration processes. Elludicating the various realizations of
the distribution of asphaltene in each of the structures and the consequences on production is the primary
subject of this case study.
Figure 4 —Three fault blocks with a single well in each. Each fault block was subjected to a secondary recent hydrocarbon charge into
oil reservoirs
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Structures 1 and 2
We first consider Wells 1 and 2; both these wells have a GOC and an OWC. Figure 5 shows optical
density of the liquid phase, asphaltene content as a percentage of the organic matter extracted from the
core and GOR against depth. The schematics represent the processes associated with the late light
hydrocarbon charge into oil reservoirs.
Figure 5—Data from Wells 1 and 2 are depicted. The initial condition after charge is shown with gas above undersaturated oil. Gas
diffuses into the oil. In Well 1, the oil shows large disequilibrium gradients of GOR and asphaltene content. Production was low in this
well. In Well 2, the oil is equilibrated in GOR and asphaltene content. The liquid fraction is almost void of asphaltenes and tar has
accumulated at the OWC. Production was high in this well compared to Well 1
In Well 1, the oil columns shows large, disequilibrium gradients of both asphaltenes and solution
gas.[7] As shown in Figure 5, the oil in Well 1 contains 35% asphaltene towards the OWC. Core extract
data from this well (not shown) only contained residual oil; there was no phase separated asphaltene.[7]
This well was shown to be highly baffled by wireline vertical interference testing (VIT).[7] In addition,
the flow rate (after accounting for viscosity) was low. The cartoon in Figure 5 visualizes the process: Gas
only diffused part way down the column. Likewise the asphaltenes are still in the process of migrating
away from the high solution gas section, but have not undergone phase separation.[7] The baffling in this
well slowed down the rate of equilibration and also gave rise to poor production results.
Even though structure 2 has undergone the same alteration process, both the asphaltene content and the
solution gas of the oil are equilibrated.[7] Moreover, the oil from Well 2 has only a small quantity of
asphaltene. In addition, Well 2 has a thick tar mat at the bottom as shown on the right side of Figure 5
in the core extract data.[7] In this well, the gas diffused all the way to the bottom of the reservoir, the
OWC. The asphaltenes migrated ahead of the gas until they were held up at the OWC and accumulated
at the bottom of the reservoir. There they formed a thick tar mat. This example is very similar to that
shown in Fig. 2. Vertical interference tests indicated reasonably good vertical permeability and a lack of
baffling. The production in Well 2 is ten times higher than Well 1 (after accounting for viscosity).[7]
Wells 1 and 2 provide a ⬙movie⬙ of tar mat formation. However, the gas diffusion process started at
the same times in the two wells. The rate of diffusion in Well 1 was smaller due to the baffling which also
significantly impacted the production rate. The lesson is that if part of a field shows equilibrated
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asphaltenes (or fluids) and another part shows graded but not equilibrated fluids, then production might
be low for the part of the field in disequilibrium. Wells 1 and 2 confirm the concepts that have been used
to explain tar mats in other fields, (e.g. Figure 3). Nevertheless, these observations also reinforce that some
other process must be occurring in the example in Figure 3 to produce a permeable upstructure tar mat.
Structure 3
Structure 3 (Well 3) underwent the same petroleum system events as Structure 1 and 2. These structures
all experienced a late light hydrocarbon charge into the oil reservoirs. The asphaltene disposition in this
structure is yet different from Structures 1 and 2. There is evidence of two different tar deposition
mechanisms in the same well: a slow diffusional destabilization and settling of asphaltenes on a shale
break in the top part of the reservoir and local tar deposition from a rapid destabilization in the lower part.
The significance of this observation is such that it provides an explanation to the long standing puzzle of
upstructure permeable tar zones. Structure 3 shows a combination of vertical and lateral fluid fronts that
occur in one well and account for the different realizations of tar deposition.
As in the adjacent structures the oil was biodegraded in Structure 3. Biodegradation increases the
asphaltene content in the oil, at most by a factor of 3 for Peters-Moldowan levels of 6 and above.[8] The
lack of dominance of 25-norhopanes compared to hopanes indicates the intial biodegradation levels were
not that high. Geochemistry analysis indicates a Peters-Moldowan level of biodegradation between 4 and
5. Two depths of paleo oil-water contacts (OWC) with corresponding biodegradation are evident in the
residual oil below the present day OWC. An upward shift of OWC is possibly related to the oil being
consumed, but could also be related to tilting and spilling of the oil in the reservoir. The residual oil in
the water leg does not show systematic changes towards the OWC (Figure 6).
Figure 6 —Geochemical markers and process traces support 3 zones in reservoir and indicate decresing maturity towrds the OWC. The
GC analysis shows little to no biodegradation in the oil above the present day OWC. All paleo OWCs are below the present day OWC
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The Asphaltene content of the residual oil is in the order of 10-20% (of the extracted organic matter
EOM, not in terms of weight % of core). This should be representative of the asphaltene content in the
reservoir prior to the late secondary charge. It is also consistent with the current asphaltene content of the
oil in Well 1 and with the thick tar mat in Well 2. The biodegadation and inferred asphaltene content of
the original oil (from downhole fluid analysis) reinforces the view that in large measure, the petroleum
system context of all three structures is similar.
The secondary charge is believed to come dominantly from a deep kitchen, with contribution also from
terrestrially influenced upper Jurrassic depositional environment. The charge is believed to enter from a
westerly direction which puts Well 3 closest to the charge point. It is also volumetrically larger than in
Structure 2. The oil fingerprints based on gas chromatography shown in Figure 6 indicate that the
secondary charge is rich in n-alkanes with little to no biodegradation. In recent geologic time, the reservoir
temperature for all three structures has become too high for biodegradation. Geochemical markers and
process traces support 3 zones in reservoir and indicate decreasing maturity towards the OWC. All paleo
OWCs are below the present day OWC.
The late, high maturity charge raises the GOR and decreases asphaltene solubility of the original
asphaltene rich oil. Downhole fluid analysis shows that the mobile oil has very little suspended asphaltene
content. Analysis of the organic core extracts shows a complex pattern for Well 3, more complex than the
patterns observed in wells 1 and 2 (cf. Fig. 7). Asphaltene content as a percentage of the extracted organic
matter from the core indicates a low 5-10% asphaltene concentration at the top of the reservoir and a sharp
increase to over 60% just above a lithologic shale boundary (cf. Fig. 7). This is consitant with the diffusive
process in Well 2, with the exception that the asphaltenes are held up at a lithologic vertical boundary and
not at the OWC as in Well 2.
Figure 7—Asphaltene content in the organic extracts from core plugs vs. depth. Onlty small amounts of asphaltene is found in the core
at the top of the reservoir. High asphaltene content above 60% indicates a tar mat just on top of a shale layer. A complex pattern is
observed in the oil zone below the shale layer. In addition, two paleo OWCs are observed and corroborated by GC analysis. Core
photographs show the tar deposition on top of the lithologic shale barrier
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Core analysis clearly shows the tar deposition on top of the shale layer (cf. Fig. 7). Movement of the
OWC during the course of the alteration process is ony evident below the present day OWC. The tar mat
resting on the shale has nothing to do with water or the OWC.
Below the shale layer the core extracts indicate tar distribution scattered between 20% and 40%.
Permeability is affected in the area, yet the DST results prove flow and permeability in that tar zone. There
is no indication of an inpermeable tar mat at the OWC like in Well 2. The implication is that upon
destabilization, the asphaltenes had no time to migrate downward. If the instability were induced by
methane diffusion downward form the gas cap, then the asphaltenes would have plenty of time to migrate
down to the OWC especially as the shale baffle slows down the methane diffusion as shown in Well 1.
A rapid process must have destabilized the asphaltenes below the shale break, while slow destabilization
is seen above the shale break.
The proximity to the charge point and the large volume of the secondary charge leads to the
understanding that the destabilization below the shale break is due to a lateral instability, a lateral fluid
front of light hydrocarbon. Figure 8 schematically visualizes the movement of the fluid front in the
proximity of the charge point.
Figure 8 —In proximity to the charge point fluids fronts can sweep laterally through the reservoir. The process is fast compared to
diffusion. Away from the charge point, the fluids density stack in the reservoir
Wells 1 and 2 and many other case studies (e.g. Figure 2) show that when gas (or light hydrocarbon)
charges into a reservoir, the gas can rapidly migrate to the top of the reservoir at least in some cases. That
is, the charge fluids can density stack without mixing.[9] The newly charged gas diffuses downward in
the oil column. In this slow diffusive process, the asphaltenes have time to migrate down away from the
vertical fluid front of high(er) GOR oil. The migration of asphaltenes ceases when they are held up by an
impermeable barrier or the OWC at base of the oil column.
Indeed, the top of Well 3 shows just this process. Little asphaltene is found in core extracts above the
tar mat on the shale break. These migrating asphaltenes deposited on the shale break forming a thin tar
mat of very high asphaltene content. The top of the core section of Well 3 fits what is also observed in
Well 2 and is not surprising.
Below the shale break the asphaltenes are deposited throughout the oil column with no accumulation
of asphaltenes on the OWC (cf. Fig. 9). The core below the shale break is permeable; these asphaltene
deposits do not reduce permeability to zero unlike the tar mat in Well 2. The implication is that upon
destabilization, the asphaltenes had no time to migrate downward. If the instability were induced by
methane diffusion downward form the gas cap, then the asphaltenes would have plenty of time to migrate
down to the OWC especially as the shale baffle slows down the methane diffusion as shown in Well 1.
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Figure 9 —Mixing of secondary and original charge destabilizes the asphaltenes differently as a function of the speed and direction of
the process. Diffusional mixing gives the asphaltenes time to migrate down and deposit on a shale break. The lateral charge front and
precludes migration downwards of the asphaltenes causing them to deposit locally. The result is a tar rich, but permeable zone below
the shale break
A change in reservoir pressure is likely throughout the various alteration stages of this structure. While
asphaltene deposition though depressurization is observed in laboratory experiments it is not the cause of
the deposition observed in Well 3. Pressure changes equilibrate rapidly in time [10] and as such the effect
would result in a uniform local asphaltene deposition. This is not the case as the top and the bottom of
the reservoir give evidence to two different destabilization mechanisms.
In light of the petroleum system model, the nature of the structure, the proximity of the charge point
and charge direction it seems plausible that the secondary charge caused a lateral sweep throught the lower
part of the reservoir. Figure visualizes such a lateral charge which occurs fast compared to diffusive
mixing. The asphaltenes destabilize and deposit locally at a medium concentration range (30%-40%).
Conclusion
All three adjacent structures show similar charge and alteration history, but are found to have ended up
in very different reservoir realizations at present day. An asphaltene rich original charge mixed with a
recent light hydrocarbon that destabilized the asphaltenes in all three structures. The rate and direction of
mixing is different in all three wells and causes the differences in reservoir realization as a function of
baffling and proximity to the charge point. At the foundation of the analysis stands a comprehensive
evaluation of the reservoir fluids using downhole fluid analysis and sample acquisition.
The lateral charge process is evident here and offers a plausible and likely solution to long standing
puzzle of upstructure permeable tar zones (as observed here). This study shows that a combination of
vertical and lateral fluid fronts can occur in one well and account for this puzzling observation.
Acknowledgement
The Authors would like to thank Lundin Norge AS for the permission to publish this paper.
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