IPTC-18008-MS

Integration of Geological, PVT and SCAL Data to Reduce ReservoirUncertainty of an Unconventional Field in Kuwait

A. K. Jain, H. Ferdous, K. Ahmad, P. K. Choudhary, and T. Al-Mutairi, Kuwait Oil Co

Copyright 2014, International Petroleum Technology Conference

This paper was prepared for presentation at the International Petroleum Technology Conference held in Kuala Lumpur, Malaysia, 1012 December 2014.

This paper was selected for presentation by an IPTC Programme Committee following review of information contained in an abstract submitted by the author(s).Contents of the paper, as presented, have not been reviewed by the International Petroleum Technology Conference and are subject to correction by the author(s).The material, as presented, does not necessarily reflect any position of the International Petroleum Technology Conference, its officers, or members. Paperspresented at IPTC are subject to publication review by Sponsor Society Committees of IPTC. Electronic reproduction, distribution, or storage of any part of this paperfor commercial purposes without the written consent of the International Petroleum Technology Conference is prohibited. Permission to reproduce in print is restrictedto an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of where and by whom the paperwas presented. Write Librarian, IPTC, P.O. Box 833836, Richardson, TX 75083-3836, U.S.A., fax 1-972-952-9435

Abstract

The study involves a complex sandstone reservoir characterized by relatively thin stratified viscousoil-bearing net pays separated by localized shales and baffles in between. Some of the reservoir intricaciesinclude mappable gas cap intervals overlying net pays at places, water-bearing intervals on top of oil, longtransitional zones, and lateral as well as vertical variation in oil viscosity and API. Based on thestratigraphy and geological understanding derived from log interpretation of some initially drilledappraisal wells, the reservoir was divided into four oil-bearing layers: Upper-A, Upper-B, Lower-A, andLower-B. Upper Sands are separated by Upper Shale Baffle and Lower Sands are similarly separated byLower Shale Baffle; and Middle Shale acts as a regional barrier between Upper and Lower sand units.Initial reservoir description postulated that all the four oil-bearing layers are separate unconnected units,with no vertical communication. Several hundred wells have been drilled as of now; in many wells, it wasfound that Upper Shale is discontinuous, with Upper-A and Upper-B sands merging into a single net paylayer. The present study attempts to analyze and integrate various reservoir parameters to understand therealistic and credible shaliness of the Upper and Lower Shales. Analysis includes PVT and SCAL datafrom over 100 wells including viscosity, API gravity, compositional data, and volatiles. Steamfloodexperiments were conducted on plugs from Upper and Lower Shales. Many plugs were found to haveappreciable permeability and porosity with limited oil saturation. All these data suggest that Upper andLower Shales do not seem to be effective shale barriers and vertical fluid migration can occur. Duringcyclic steam stimulation in one of the pilot wells, steam was injected in Upper-B layer. Subsequenttemperature survey suggests that steam has passed through Upper Shale and migrated into Upper-A Sand.This further corroborates that Upper shale is not acting as an effective barrier.

It is thus concluded that to understand geological heterogeneities and to reduce reservoir uncertainty,integration of PVT, SCAL, and other reservoir information along with geology is required for optimumdevelopment of an unconventional reservoir.

IntroductionProper understanding of a reservoir is very impor-tant for the success of an EOR process. It becomescrucial when a thermal process such as steam injec-tion is used as an EOR process because cost perbarrel by thermal methods is much higher than forother EOR processes. If a reservoir is complex thenit is a must prior to application of any thermalmethod.

The reservoir under consideration is a complexone. Its thickness is relatively less with baffles andshales in between. At places it is having gas capwhich is mappable, some water is also found on topof oil. Laterally as well as vertically there is anappreciable variation in oil viscosity and API. Afterconsidering all the thermal EOR processes, steaminjection has been finalised as the optimum methodfor the development strategy. Considering the costof steam, it is always desirable that it should beapplied thoughtfully in view of reservoir complex-ity. Therefore, proper understanding of the reservoirwith an integrated approach is critical prior to steaminjection in the field for commercial developmentstrategy.

Sometimes, only log response of some of thewells may not be enough to understand the reser-voir. An integrated approach is needed to under-stand it completely. In the present work, an inte-grated approach was used to understand the exactnature of various shales and cemented rocks andinterconnection between layers by considering allinputs such as geological, PVT, SCAL and logcorrelations. This would help in developing the reservoir in an efficient and disciplined manner.

A Brief Description of the FieldThe field under consideration is one of the biggest unconventional fields in the world having areal extentof over 1200 sq km. Rock and fluid properties vary greatly - laterally and vertically. Based on variationin rock and fluid properties, the field has been informally divided into three areas North, South andSouth-West (Figure-1).

The North area is the deepest part of the field, while South-west is the shallowest. Depth of thereservoir varies from 450 ft to 800 ft. Total net pay varies from 5 to 60 ft. Porosity is in the range of30-35% and permeability varies from 500 md to 10 darcy. Average reservoir temperature is on the orderof 88 - 90F and reservoir pressure varies from 50 psi to 275 psi. Large variation in oil gravity andviscosity has also been observed. In general, oil gravity varies from 11API to 18API, viscosity atreservoir conditions varies from 200 cp to 2000 cp.

On the basis of log interpretation of some initially drilled appraisal wells and geological understandingat that time, the reservoir had been subdivided into four main layers Upper-A, Upper-B, Lower-A and

Figure 1Map of the Field Under Consideration

Figure 2Stratigraphy of the Field

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Lower-B (Figure-2). In general, all the four layers are present in the Northern part of the field while inSouthern part only Upper-A and Upper-B are present. In South-West, presence of Lower-A and Lower-Bare seen along with Upper layers. There is a Mid Shale barrier in between main Upper and Lower sandunits, its thickness varies from 30 to 60 ft, however, its barrier competency needs further evaluation.Upper shale is in between Upper-A and Upper-B and Lower shale is in between Lower-A and Lower-B(Figure-2). From the geological point of view, it appears that the migration of oil took place at some pointof time during tectonic activities and it migrated into these sand units. Later biodegradation and gravitysegregation took place in the main sand units - Upper and Lower separately.

Log CorrelationOn the basis of the initial understandings, it was believed that Upper shale is a barrier between Upper-Aand Upper-B. Upper shale thickness is about 0-10 ft. Later, hundreds of wells were drilled and loggingwas done in all the wells. It was found that at many places Upper shale was absent and Upper-A andUpper-B are merging together. Logs of some of the wells are shown in Figure-3(a) and 3(b).

In these wells either Upper shale is absent or very thin. It raises concern on the nature of the so calledshale competency. We shall try to understand exact nature of the Upper shale using PVT and SCAL data.

Analysis of Reservoir Viscosity and API Gravity DataPVT sampling was done in more than 100 wells. Four samples were collected in each well in such a waythat at least one sample of each layer was available for the analysis. In many wells it was not possible tocollect samples from all the layers due to technical reasons or absence of some of the layers. It was foundthat viscosity increases while oil gravity decreases from top to bottom layers. Some examples are givenin Figures-4 and 5.

Figure 3(a)Log correlation of some of the wells showing either no shale or thin baffle

Figure 3(b)Log correlation of some of the wells showing either no shale or thin baffle

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Viscosity and oil gravity in all the four layerswere found to be different. Because of this, it waspresumed that all four layers are independent andisolated by shale barriers. But when two sampleswere taken in a single layer at different depths andanalysed then it was found that within the layersthemselves, viscosity increases and oil gravity de-creases with depth though the layer is very thin. Outof 100 wells sampled, in 18 wells two samples werecollected either in Upper-A or in Upper-B. It wasfound that there is a considerable variation in res-ervoir viscosity and API gravity within a singlelayer. If these values are compared with the valuesof nearest layer, a continuous increasing trend inviscosity and decreasing trend in API with depth isobserved. This suggests that variation in viscosityand API may not be because of isolated layers butbecause of gravity segregation within the entireUpper sand unit. This has been seen in other reser-voirs as well, such as Kern River (in California,please use REF) where viscosity varies from 400 cpto 100,000 cp in a single layer.

In six wells of North area, two samples werecollected in Upper-B. Viscosity variation with depthwithin Upper sand (one sample of Upper-A and twosamples of Upper-B) is shown in Figure-6(a). Allthe wells show increasing trend in viscosity withdepth. Likewise, API decreases within Upper layerin all the wells (Figure-6(b)).

In five wells of South Ratqa, two samples werecollected in Upper-B. They show the same trend aswas seen in North wells. Viscosity increases andAPI decreases with depth within Upper sand unit(one sample of Upper-A and two sample of Up-per-B) (Figure-7(a) and 7(b)).

In some wells, two samples were collected inUpper-A and one in Upper-B. Figure-8 shows con-tinuous increasing trend within Upper sands inWell-5 and Well-18. Likewise Figure-9 shows thatoil gravity decreases with depth within Upper sandsin both the wells.

Volatile and Asphaltene Fractions Trend in Upper-A and Upper-BVolatiles determined in few recently drilled wells are shown in Table-1(a) and Table-1(b). One sample inUpper-A and two samples in Upper-B at different depth were analysed. Volatiles are more in Upper-Athan Upper-B and they also decrease with depth within Upper-B layer.

Likewise, asphaltene fraction increases with depth within Upper-B in Well-20 (Table-2).

Figure 4(a)Viscosity at Reservoir condition, cp (Upper-A, Upper-B,Lower-A, Lower-B)

Figure 4(b)Viscosity at Reservoir condition, cp (Upper-A, Upper-B,Lower-B)

Figure 5(a)API gravity of North wells (Upper-A, Upper-B, Lower-A,Lower-B)

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These analyses clearly show that there is a defi-nite trend in viscosity, API gravity, volatile frac-tions and asphaltene not only within Upper-B orUpper-A, but within the Upper sand unit as a whole.This also suggests that these trends are because ofgravity segregation, and perhaps there are someform of communications between Upper-A and Up-per-B units.

Compositional AnalysisAs mentioned above, in 18 wells two samples werecollected either in Upper-A or in Upper-B. Compo-sitional analysis was done in all these samples. Itwas observed that in a single well, lighter fractionsdecrease from top to bottom. One such example isof Well-18 where two samples were collected inUpper-A at different depths and one in Upper-B. Inthis well, entire lighter fractions are decreasing con-tinuously from top to bottom (Figure-10).

Another example of Well-3 is shown in Figure-11. In this well, one sample was collected in Up-per-A while two samples were collected in Up-per-B. Just like well-18, similar trend is observed inthis well as well.

In Well-11, one sample was collected in Up-per-A while two samples were collected in Up-per-B. It is interesting to note that composition ofUpper-B top sample is quite similar to that of Up-per-A. It indicates that the upper part of Upper-Bhas the same composition as that of Upper-A (Fig-ure-12).

The case of Well-2 is quite unique. In this well,two samples in Upper-A and two samples in Up-per-B at different depths were collected. Plot ofcompositional analysis is shown in Figure-13. It isseen that compositional analysis of all four samplesare almost the same. It indicates that oil from top ofUpper-A to bottom of Upper-B is very similar.

All these analyses confirm that oil composition ischanging from top to bottom within the Upper sandunit in a definite trend, meaning lighter componentsare decreasing with depth. At some places even a same quality of oil is present in all the layers. This againre-affirms that layers Upper-A and Upper-B are not isolated, and variation in oil properties within themis caused by gravity segregation.

Steamflood Experiments in Shale-PlugsSteamflood experiments were conducted in two plugs of Upper shale, one plug of Lower shale and threeplugs of Mid shale units. Upon injecting one pore volume of Cold Water Equivalent (CWE) steam in

Figure 5(b)API gravity of North wells (Upper-A, Upper-B, Lower-B)

Figure 6(a)Viscosity at Reservoir condition of North wells, cp (Up-per-A, Upper-B (1), Upper-B (2))

Figure 6(b)API Gravity of North wells (Upper-A, Upper-B (1), Up-per-B (2))

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plug#1 of Well-8, a recovery of 45% and in plug#1of Well-22, a recovery of 17.8% was achieved.However, maximum recovery of 63.7% and 29.1%respectively was observed in these plugs after in-jecting more than 10 PV. This clearly indicates thatnot only steam can pass through in Upper shale, butalso recovered the oil that is present in it. Samephenomenon was observed in the plug of Lowershale also. Steamflood experiment was done in oneplug of Lower shale of well Well-8 (plug#2). 40%oil has been recovered in only one pore volumeCWE steam injection while maximum recovery was58.1%. Summary of the results is given in Table-3.This suggests that so called Upper shale and Lowershales are not shale barrier but they are baffleshaving good permeability that is sufficient to estab-lish communication between Upper-A and Upper-Band Lower-A and Lower-B.

It is worth mentioning that most of the heavy oilreservoirs have permeability in the order of darcies.Air permeability of the plugs of Upper shale andLower shale are low ranging from 3 md to 11 md(except that of plug#2 of Well-8 which is 629 md).The low permeability sometimes may not allowheavy oil to pass through them under static reservoir(cold) condition, but during steaming viscosity ofoil will reduce to below 2 cp and permeability of theso called shale will increase under dynamic condi-tions. As such, during cyclic steam stimulation(CSS) and steamflood, these so-called shales cannotbe considered as a barrier, and significant amount ofheat loss may occur.

Steamflood experiments were also conducted inthree plugs of Mid Shale unit. In two of these plugs,there was no oil recovery. However, a recovery of49% was recorded in one of the plugs (plug#3 ofWell-24). This indicates Mid shale acts as a barrierin the studied area, but regionally it may vary, thisrequires further evaluation.

Temperature Survey of Well-21 after SoakingAs mentioned above, a trend in oil properties was observed in Upper Sand not only in North but also inSouth. This indicates that Upper Sand as a whole is a single sand unit. Steamflood experiments suggestthat steam can very well pass through Upper Shale and Lower Shale units, and recover the oil from themas well. It is thus a further confirmed from the temperature survey conducted in one of the cyclic steaminjection (CSS) wells. CSS has been conducted in six isolated wells of the field on pilot basis. Well-21was the fifth well in which CSS was conducted. This well was completed only in Upper-B considering

Figure 7(a)Viscosity at Reservoir condition of South wells, cp (Up-per-A, Upper-B (1), Upper-B (2))

Figure 7(b)API Gravity of South wells (Upper-A, Upper-B (1), Up-per-B (2))

Figure 8Viscosity at Reservoir condition, cp (Upper-A (1), Upper-A(2), Upper-B)

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that Upper-B is not connected with Upper-A and isisolated by intervening Upper Shale. Reservoirproperties of the well are given in Table-4.

Steam injection was initiated in this well 5 ftbelow the top of Upper-B. Average steam injectionrate was 500 b/d (CWE) at an average pressure of450 psi. A total about 18,000 bbl CWE steam wasinjected. Thereafter, the well was kept shut in forsoaking. Temperature survey was conducted duringsoaking period after 8 days of steam injection. Plotof temperature with depth is shown in Figure-14.

Maximum temperature against the depth of Up-per-B was 391F. Since target sand was only Up-per-B and it was considered that there is no com-munication between Upper-A and Upper-B becauseof intervening Upper Shale, it was assumed that thesteam will go into and remain inside Upper-B only.But the temperature survey shows that the temper-ature of Upper-A raised up to 384 degree F, veryclose to that of Upper-B. Possibility of heat conduc-tion either through casing or through Upper Shaleseems to be quite less because the temperature sur-vey was conducted only after 8 days of soaking.Conduction cannot be so fast that can raise thetemperature so much. So it seems to be a case ofsteam leakage and cross-formational steam migra-tion. This leak may be because of three possibilities:(1) either cement behind casing was not good, or (2)a fracture has developed in Upper Shale with timeor (3) so called impermeable Upper Shale in factdoes not act as a shale barrier. CBL indicates thatthe cement condition is good in this well. Alsoinjection pressure was below the fracture pressureand therefore chances of fracturing shale or creating

Figure 9API Gravity (Upper-A (1), Upper-A (2), Upper-B)

Table 1(a)Volatile Fractions in Well-l9 (Upper-A, Upper-B (1), Up-per-B (2)

Well-19

Layer Depth, ft Volatiles Fraction (Wt.%)

Upper-A 581 12.30

Upper-B (1) 623 9.68

Upper-B (2) 641 5.08

Table 1(b)Volatile Fractions in Well-20 (Upper-A, Upper-B (1), Up-per-B (2))

Well-20

Layer Depth, ft Volatiles Fraction (Wt.%)

Upper-A 600 11.75

Upper-B (1) 636 6.24

Upper-B (2) 653 4.77

Table 2Asphaltene Fractions in Well-20

Layer Depth, ft Asphaltene, wt%

Upper-A 600 11.9

Upper-B (1) 636 12.4

Upper-B (2) 653 12.5

Figure 10Compositional Analysis of Well-18 samples (Upper-A (1),Upper-A (2), Upper-B)

Figure 11Compositional Analysis of Well-3 samples (Upper-A, Up-per-B (1), Upper-B (2))

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cracks are rare. The only possibility is that Upper Shale is not acting as a barrier. Geological interpretationsuggests that so-called Upper Shale is not shale, but a baffle composed of cemented silty sandstone rockmatrix. At static reservoir conditions it appears like a barrier, but in fact the reservoir may become activeat higher temperatures and pressure regime, particularly when dynamic conditions are developed duringsteam injection.

Geology of the Upper and Lower Shale-Baffle: Understanding the Barrierand Baffle ComplexityFrom geological perspective, the conventional lithostratigraphic subdivisions of the reservoir underconsideration recognize Upper and Lower units as dominantly two sand packages separated by Mid Shale.At the top of the reservoir, Cap Shale is present overlying Upper Sand as a regional barrier. However, bothUpper and Lower sands are further subdivided into A and B separated by Upper and Lower Shale Baffleunits. Thus, the intended sand package of this discussion Upper Sand is informally divided into Upper-Aand Upper-B separated by Upper Shale baffle. This nomenclature is more useful for detailed reservoircharacterization and petrofacies evaluation to recognizing net-pay, free gas, wet non-reservoir and tightcemented intervals.

Figure 12Compositional Analysis of Well-11 samples (Upper-A, Up-per-B (1), Upper-B (2))

Figure 13Compositional Analysis of Well-2 samples (Upper-A (1),Upper-A (2), Upper-B (1), Upper-B (2))

Table 3Steamflood Recovery in Shale/Baffle Plugs

Well No. Plug No. Layer Air Permeability, md Maximum Recovery, %

Well-8 1 Upper Shale/Baffle 3 64

Well-22 1 Upper Shale/Baffle 11 29

Well-8 2 Lower Shale/Baffle 629 58

Well-23 1 Mid Shale/Baffle 9 0

Well-24 1 Mid Shale/Baffle 9 0

Well-24 2 Mid Shale/Baffle 5 49

Table 4Reservoir Properties of Well-21

Well No. Layer Sand Interval, ftPerforationInterval, ft Permeabi lity, md Porosity, %

ReservoirViscosity, cp API gravity

Well-21 Upper-A 565-594 Not Perforated 4000 34 420 14

Well-21 Upper-B 605-635 610-635 4123 35 1912 12

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Detail geological investigations using about 800logs, 140 cores, extensive petrography, RCAL andSCAL data confirm that Upper Shale Baffle is notan absolute shale facies (like Cap Shale). Thelithostratigraphic nomenclature Upper Shale is ageneralized lithological nomenclature that is oftenconfused with true shale facies. The term UpperShale is used in general to differentiate low poros-ity/permeable facies between high porosity/permeability channel sand facies of Upper-A andUpper-B. In reality, the Upper Shale unit is a dom-inantly cemented siltstone facies, with relativelylow porosity and permeability (porosity 15-20%,permeability 10-300 md, and often with low oilsaturation. Depositionally, it is a siltstone faciescemented by carbonate/clay minerals, thus, result-ing to baffle character. For thermal EOR purpose,

extreme caution must be considered since steam and heat migration (due to convection/diffusion andconduction processes) across this type of baffle usually occur in the long-term because Upper Shale unitis not a depositional low-energy marine facies, instead has significant amount of porosity and permea-bility. Ongoing laboratory experiments of samples of this reservoir suggest that steam and rock interac-tions would damage and modify reservoir rock properties by enhancing/modifying porosity and perme-ability. The role and significance of seals and barrier rocks to vertical fluid migration in EOR developmentare widely investigated and considered in many Canadian heavy oil reservoirs (Ferdous et al, 2004: Yuanet al, 2011, Yang et al, 2013).

Extensive lithofacies investigations and sequence stratigraphic analyses suggest that the entire UpperSand package is developed by continuous deposition consisting of ascending LST, TST, HST depositsbounded by two sequence boundaries (type 1 and 2) during a single sea level fluctuation cycle. Thissedimentation pattern could not support any environmental regime for depositing regionally extensive lowenergy marine shale facies (Upper Shale) that would favour rocks of seal or barrier characteristics. Assuch, the entire Upper-Sand package deposited in one depositional sequence consisting of Fluvial-Deltaic-Estuarine-shallow marine settings. During this typical basinal setting, Upper-Shale could nothave a distinct regional low-energy deep marine origin. Thus, Upper-Shale unit compositionally (grainsize) varies between shale-siltstone-sandstone lithology both vertically and laterally which is exten-sively bioturbated and cemented by various degree of diagenetic carbonate and silica minerals, and thuswould always have discontinuous lense or pinch-out type distribution pattern within the Upper Sandpackage. As such, Upper-Shale facies has gradational contacts with the underlying Upper-B and overlyingUpper-A channel sands, and does not truly exist as an isolated unit. Detailed reservoir characterizationshows Upper-Shale rocks have reasonable amount of porosity and permeability, and often contain patchyoil saturation.

Baffles vs BarriersEffects of vertical permeability anomaly (and their distributions) on cross-formational steam movementto distinguish barriers and baffles have been the subject of many studies (Fustic, 2011; Pooladi-Darvishand Mattar, 2002; Li et al., 2008; Shin and Choe, 2009; Heidari et al., 2009; Yang and Butler, 1992, Stroblet al., 1997; Ito et al., 2001; Yeung, 2009). In these studies, the low permeability layers within thereservoirs are commonly referred to as barrier or baffle to steam migration based on partial orextensive steam movement, duration and time scale involved, local or regional distribution of permeability

Figure 14Temperature Survey of Well-21 after 8 Days of Soaking

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obstructions etc. Baffles are commonly considered as low permeability layers that impede or delay fluidflow, but do not prevent the steam movement in the longer duration. Usually, these low permeabilitylayers are locally developed (limited extent), so steam can bypass laterally at its outer limits. Thus, bafflesare the temporary obstructions that may act as a barrier for a shorter duration under static conditions dueto relative variability in pore-throat size, capillary pressure, density contrast between water and hydro-carbon etc. However, under dynamic conditions when external energy is introduced under pressure, suchas steam/water/gas/chemical injection to enhance oil recovery, most baffles would rupture and breach withtime to act as fluid conduits for cross-formational heat and fluid migration. Baffles are usually locallydeveloped and as such, discontinuous, and may act as seals only locally for a short duration. During heavyoil development strategy, baffles are often considered to act as potential seal/barrier during primary coldproduction; however, for any enhanced oil recovery including thermal they are potential thief zones andtheir barrier competency is extremely uncertain.

In contrary, barriers are considered as regionally extensive impermeable layers (permeability much lessthan 1 md) during typical thermal operation duration; thus, steam usually cannot penetrate through orlaterally bypass a barrier; however conductive heating may reduce the bitumen viscosity above the barrier.In Many Canadian heavy oil reservoirs the absolute permeability of the barriers and seals are very low,usually their porosity in the range of 10% to 20% and permeability in the order of micro to nano-Darcy(Yuan et al, 2011; Yang et al, 2013). Barriers usually compartmentalize the entire reservoir into severalsegments distinguished by distinctive pressure regime. Because of their regionally extensive development,barriers usually have hydrodynamic entity to characterize the entire petroleum migration and fluid flowsystem in a basin. Some simulation studies report the possibility of steam dehydrating and fracturing theimpermeable barriers over some extended periods of time after several years of injecting steam due toexceeding injection pressure or volume. The integrity of impermeable barriers under various reservoirconditions is a matter of ongoing research by industry and academia (Ito et al., 2001).

Significance of Baffles in Thermal EORThe ongoing discussions on baffles and barriers focusing on nature, distribution and quality of UpperShale and Lower Shale have enormous significance for the thermal development strategy of thereservoir under consideration. The impact of Upper Shale within Upper Sand Reservoir (Upper-A andUpper-B) or Lower Shale within Lower Sand Reservoir performing as barrier or baffle, their shalecompetency, and the degree of cemented rock characteristics, all these parameters would impact thephysical processes of convection, diffusion, and conduction. They would act as potential Thief Zonesand would influence the steam injection, cross formational fluid flow, heat loss, sweeping efficiency, andultimate oil recovery. Likewise, the comprehensive understandings of reservoir geology, acquired labo-ratory data, reservoir parameters need to be considered to plan and develop the completion design andproduction scenario for the long term thermal EOR strategy.

Upper and Lower Shale Baffle UnitsConsidering the conventional geological characteristics of the stratigraphic traps and barrier rocks (Berg,1975; Nelson, 2009; Camp, 2011), the Upper and Lower Shale units in order to perform as barrier unitshould be composed of: i) rock materials of primary depositional origin with inherent barrier charactersand integrity, ii) deposits of thinly laminated and fissile low energy marine shale made of clay and veryfine grains, iii) pore-throat size 0.1 um to 0.005 um and very high capillary pressure (Nelson, 2009), andiv) excessive mercury injection entry pressure, v) additionally, the unit should be regionally extensivewith at least 15 thick shale lithology between Upper-A and Upper-B (as well Lower-A and Lower-B)to inhibit cross formational steam migration in the long duration under dynamic conditions. Detailreservoir characterization suggests that Upper and Lower Shale units are locally developed shales with 0to 10 thickness, dominated by largely siltstone-sandstone-shale rocks. They are associated with exten-sively cemented lithology, mainly by carbonate (calcite and dolomite), minor silica and clay, and

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occasional hematite and pyrite cements with average thickness of 16 (range 0 to 50). Thus, the bafflerock materials are of secondary diagenetic post-depositional origin, made of coarser grains of silt to sand,highly variable range of porosity and permeability (up to 20% and 300 md). Their barrier competencywould be highly controlled by degree of cementation and their intricate bonding. This kind of cementedinterval is highly susceptible to artificial diagenesis during EOR processes as chemical interactionsbetween minerals, steam, fluid, temperature, and pressure occur. There are many documented evidencesin Canadian heavy oil reservoirs in Cold Lake, Lloydminister, Saskatchewan reservoirs where diageneticalterations modify the rock behaviour in cemented zones (Oldershaw, 1983; McKay and Longstaffe, 1997,Weatherford Report, 2014). Thus, understandings the barrier performance of this kind of cemented zoneis of utmost significance before committing to planning Upper-A and Upper-B (also Lower-A andLower-B) as isolated compartments separated by Upper and Lower Shale Baffle. These cementedintervals will vary on a regional scale from place to place in terms of its homogeneity, integrity etc. Thesefundamental geological parameters need to be understood and evaluated for heavy oil field development;all available technical data and pilot well performances should be assessed prior to committing thermalrecovery scheme. Also, considerations should be given that any rock interval may act as a baffle/barrierunder static conditions, however, may act as potential thief zones and could be breached under dynamicconditions (during thermal operation) when external heat/pressure/mass introduced into the reservoirsystem. Thus proper and continuous monitoring during short and long duration is particularly significant.

Conclusion

1. There is a continuous variation in fluid properties from top to bottom not only in different layersbut also within individual layers of Upper-A and Upper-B. This is observed in North as well asin South part of the field.

2. Steamflood experiments in plugs of Upper Shale and Lower Shale shows that not only steam butoil at higher temperature and pressure can pass through them, and oil recovery occur.

3. During CSS, steam injection was performed in Upper-B of Well-21 five feet below the top ofUpper-B presuming that Upper-B is isolated by Upper Shale and steam will not pass through it.But temperature survey taken 8 days after steam injection suggests that steam has migrated intoUpper-A also. Therefore, Upper Shale is no longer acting as a barrier to steam flow under dynamicconditions.

4. Log correlation shows that at many places there is no distinction in Upper-A and Upper-B as bothsands merge together. It also proves that Upper Shale is not a permanent barrier.

5. Geological interpretation suggests that so-called Upper Shale and Lower shale are not a shalebarrier on a field scale. They are baffles and therefore locally at some places they may act asbarrier to oil under static reservoir conditions, but may not be a barrier during dynamic steaminjection phase.

6. From above mentioned evidences, we can conclude that Upper Shale and Lower Shale are notshale barriers but they are baffles on a regional field scale. They are not marine shale but fluvialin nature, so it cannot be correlatable at regional level. At some places Upper-A and Upper-B oilzones are separated by tight calcareous/dolomitic sandstone which has porosity in the range of 15- 25 % and permeability in the range of 10 - 300 md. These shales are mostly deposited in fluvialenvironment (as overbank channel), as such, very discontinuously distributed and should nottreated as regionally extensive competent barrier.

7. In cold static conditions they may act as local barrier for a short duration, but at higher temperatureand pressure regime during dynamic steam injection phase they may be communicating with thenet pay intervals. Not only steam but oil at high temperature may also pass through them. Viscosityof oil at 450F comes down to less than 2 cp that can very easily flow though baffles.

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AcknowledgementAuthors are thankful to Dr. S.M. Farouq Ali for his valuable suggestions.

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12 IPTC-18008-MS

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IPTC-18008-MS 13

Integration of Geological, PVT and SCAL Data to Reduce Reservoir Uncertainty of an Unconventiona ...IntroductionA Brief Description of the FieldLog CorrelationAnalysis of Reservoir Viscosity and API Gravity DataVolatile and Asphaltene Fractions Trend in Upper-A and Upper-BCompositional AnalysisSteamflood Experiments in Shale-PlugsTemperature Survey of Well-21 after SoakingGeology of the Upper and Lower Shale-Baffle: Understanding the Barrier and Baffle Comple ...Baffles vs BarriersSignificance of Baffles in Thermal EORUpper and Lower Shale Baffle Units

Conclusion

AcknowledgementReferences