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No. 1998.103

Reservoir Management of Heavy Oil Reservoirs of North Gujarat, India

A.K. Bhatia, Lehmbar Singh, and Daljit Singh, Oil Natural Gas Corporation, Baroda, India

Abstract

Oil production from a heavy oil reservoir involves high devel-opment as wells as operating cost and yields low primaryrecovery, especially if it is associated with an active aquifer.The adverse mobility ratio of water and oil results in low dis-placement efficiency causing water invasion into the oil zoneby viscous fingering. It is therefore, necessary to plan andimplement EOR technique at an early production life of thereservoir.

The Heavy Oil Belt of North Gujarat, India has around 108MMt of inplace oil reserves of 12–17°API oil with viscosityranging between 60 cp to more than 550 cp. The reservoirshave a potential of producing around 1.8 MMt per annum ofoil with thermal EOR technology as compared to the primaryproduction of around 0.7 MMt per annum. The oil pay is asand stone reservoir which abuts against a palaeohightowards updip and is supported by an active aquifer from thedowndip. During primary production phase these reservoirsexhibited various problems like low efficiency of lift mecha-nism, sand production, and early water production in wells.

The paper deals with the reservoir management techniquesadopted during primary recovery stage which includes, designof wells to produce heavy oil, optimizing well spacing patternsto accommodate future application of thermal EOR methods,artificial lift, conceptualization of EOR techniques and formu-lation of pilots, field application, commercialization of EORand delineation of updip pinchout prospects for better gravitydrainage during EOR application.

Introduction

The heavy oil belt of North Gujarat is a north-south trendingnarrow belt of about 30 km length, having an area of about 45sq km. Its western boundary is marked by Mehsana horst andeastern boundary by Jotana field. The rock and fluid propertiesin the reservoir vary gradually from north to south. Dependingupon the crude characteristics, the heavy oil belt has beendivided into northern, central and southern areas. The devel-opment wells have been drilled in a square pattern of 9 hectarespacing. Performance analysis shows that the southern areahas the best performance followed by central and northernareas. The problem of producing heavy oil has been dealt with

by analyzing the primary production and artificial lift perfor-mance. The analysis shows that progressive cavity pumpshave performed much better than the conventional sucker rodpumps in terms of liquid discharge rate and operating life.

The screening criteria for EOR favors application of

in situ

combustion as well as steam flooding as the EOR techniquesfor this oil belt. An

in situ

combustion pilot carried out in thecentral area proved to be successful. Based on this, fieldwidecommercialization of the process is planned in the central andsouthern areas. In the central area the process is being com-mercialized with the updip line drive whereas in the southernarea inverted five spot patterns are planned.

In order to take advantage of the localized structural dip inthe central part, undip pinch out delineation was carried outusing well test analysis, well logs and 2-D seismic data. Theair injection wells have been suitably located at the structur-ally highest points in the reservoirs to assist gravity drainage.

Tectonic Setting

Tectonically, the area falls in the northwest of an intracratonicrift graben of Cambay basin. Basaltic trap formed the floor ofTertiary sediments. Cambay black shale is the first marinesedimentation in the inner shelf environment. During earlyand middle Miocene time, coarse clastic sediments weredeposited which form reservoirs interbedded with shale andcoals. This was followed by deposition of Tarapur shaletowards the end of middle Eocene age, providing shale coverto the reservoir sands.

Stratigraphy

The Kalol sands occur at a depth of -900 m to -1,000 m MSL.The sands are aligned north-south, parallel to Mehsana Horstwhich controls deposition of reservoir sands. The flanks arecharacterized by development of Kadi and Kalol formations,whereas in the updip area only Kalol pays are developed.

The Kalol pay is layered and, on the basis of reservoir char-acteristics and coal/shale separations, it is divided into fivemain layers viz. Upper Suraj Pay (USP), KS-I,KS-II, KS-III,and Kalol lower stack. The fluid distribution in the sand shows

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that all the layers have a common oil-water contact which dipsfrom south to north. These pay sands are therefore hydrody-namically a single unit through a common aquifer. The num-ber of layers varies from north to south. In the north only twolayers USP and KS-I, in the central part three layers, USP, KS-I and KS-II, and in the south all five layers are developed.

Rock and Fluid P rope r ties

The rock and fluid characteristics in the heavy oil belt varygradually from north to south. On this basis it has beendivided to northern, central and southern areas even though itis a single contiguous belt. The sands are medium to coarsegrained, well sorted, porous and permeable with occasionalshale bands. The binding of the sand grain is poor. The poros-ity of the reservoir ranges between 27–30% and it increasesfrom north to south. Similarly the permeability increases fromnorth to south and it ranges between 3,000 md and 5,000 md.

The API gravity of oil increases from 12°API in the northto 17 in the south. The crude is asphaltinic, with low GOR dueto less maturation. The most significant of the oil characteris-tics is viscosity, which decreases gradually from 550 cp in thenorth to 60 cp in the south. Due to this, the mobility ratio ofwater to oil becomes more adverse towards north leading toinefficient displacement of oil by water due to viscous finger-ing.

Table 1

shows the rock and fluid properties in the threeareas of heavy oil belt of North Gujarat

Primary P roduction

Primary production of an oil and gas reservoir is important asit yields early revenue from the oil property. During this phaseof production, the cost incurred is less leading to high rate ofreturns. However, in case of heavy oil reservoirs, the primaryrecovery factor is low because of low displacement efficiency.Similar is the case with heavy oil belt of North Gujarat. Thestudy of log data of exploratory wells drilled in this area hasrevealed the presence of an extensive aquifer associated withthe oil zone, which provides a good pressure support, a featurenormally favorable for energy replenishment. However, in thiscase the primary recovery is more affected by its presence;high reservoir permeability gives the water an easier path tofollow in the reservoir.

The primary recovery in heavy oil belt is more of academicimportance, as the EOR process is anticipated to start longbefore attainment of primary recovery. The initiation of pri-mary production from the wells itself was a difficult task asthe production equipment, like Sucker Rod Pumps (SRP)posed immense problems which are discussed in detail subse-quently. Performance predictions were carried out consideringmixed drive mechanism (in the absence of sufficient primaryproduction history) and adverse mobility ratio; the primary

recovery was estimated to be 21% in the south, 12% in thecentral part and 8% in the northern part.

The entire heavy oil belt has been developed by drillingwells in a square grid of 300m x 300m (9 hectares spacing).However, with the development of the field and generation ofwell data, it is known that the in some parts of central area andaround pinch out, the sand is heterogeneous. This is likely toleave by-passed oil leading to low primary recovery. In filldrilling in these areas will reduce the existing well spacing,and help in increasing the area sweep efficiency and applyingthermal EOR in 5–spot pattern.

Primary production history shows that the reservoir behav-ior in the southern part is much better than the central andnorthern part. The water breakthrough occurred much earlierthan expected in the northern and central areas, leading todeterioration in reservoir performance. The well specific pro-ductivity indices (SPI) which depend upon the effective rockand fluid properties, gradually increase from north to south. Itis 1.0 m

3

/d/kg/cm

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/m in the northern part, and 1.5 m

3

/d/kg/cm2/m in the south. As a result of this, the wells in the south-ern part are prolific producers. In the northern part, as the oilbecomes heavier, the SPI declines, resulting in poor welldeliverability. Performance graphs of the northern, central andsouthern areas, clearly show deterioration in the reservoir per-formance as we go from south to north.

The field watercut and production data was used to gener-ate fractional flow curves in the southern part where sufficientproduction history is available. The curves exhibit abrupt risein fractional flow of water with slight increase is water satura-tion after breakthrough. This shows that the maximum pri-mary recovery in this reservoir can be expected at highwatercut range of 85–90%.

Well Completions:

The completion design of the wells inthe heavy oil belt was conceived to meet the specifications offuture EOR applications, to accommodate large sized artificiallift and sand control equipment. The wells were to be com-pleted with 7" casing, cemented at surface with API class Gcement and 40% silica flour to allow wells to be used for ther-mal EOR applications like steam stimulation or

in situ

com-bustion. The tubing size of 3 1/2” was selected toaccommodate large sized sucker rod pumps. However, thisdesign, conceived earlier, could not be followed in most of thewells. Although 7" casing was invariably used, the type ofcement and cement rise behind the casing could not beachieved rendering many wells unserviceable for steam flood-ing and cyclic steam stimulation.

Artificial Lift:

The high oil viscosity puts all conventionalmodes of lift to a great disadvantage by inhibiting the func-tioning of standard lift equipment. In order to make the stan-dard equipment work required innovative modifications. Theconventional SRP posed ‘no free fall’ problem in the down-stroke due to high oil viscosity. The upstroke started wellbefore the downstroke was completed. In order to mitigate thisproblem, the pumping speed was brought down to 2–2.5strokes per minute (spm). This permits the rod sufficient time

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to reach desired lowest point in the downstroke. The otheradvantage it gave was the minimum wear and tear differentsections of equipment.

The modifications in the conventional equipment howeverlimited its discharge capacity. The other equipment was alsoscreened. This included the progressive cavity pumps whichconsists of a screw rotor operated by a motor inside a close fitstator. The stator and the rotor move progressively from thepump inlet to the outlet, pushing the oil to the surface. Experi-ence has shown that these pumps have a greater operating lifeas compared to conventional SRPs. The mean time betweenthe installation and first repair of the two pumps shows thatthe progressive cavity pump has meantime of about 19 monthsas compared to that of SRP which has a meantime of 13months. This shows that the screw pumps are more efficientthan the modified SRP. The wells operating with screw pumpsare less prone to water production due to lesser draw down.

In order to attain a higher discharge capacity and betterpump efficiency, the modified SRP with hydraulic pump jackwith a variable speed can be an alternative. Such pumps areoperating successfully is Saskatchewan field since 1982. Thehydraulic pump jack has a variable speed on the upstroke aswell as downstroke regulated by a non-shocking cushioneddrive arrangement which regulates the pumping rate to suitchanging well conditions.

Enhanced Oil Rec overy P rocess

The performance of heavy oil belt during the primary produc-tion period led to the prediction of low primary recovery. Thisprompted application of EOR in the early life of the field inorder to recover substantial oil. The preliminary screening cri-teria of viscosity, hydrocarbon saturation, depth, reservoirtemperature, reservoir pressure, permeability, transmissibil-ity, lithology, porosity, clay content, and pay zone depth sug-gests application of thermal EOR methods, either steam-flooding or

in situ

combustion.

The trial application of both the techniques was studied.Both steamflooding and

in situ

combustion processes wereconsidered even though initial calculations showed that steam-flood would require high volume of high temperature (about340°C) steam at a depth of around than 1,000 m.

Laboratory investigations were carried out on combustiontube for

in situ

combustion process. The results showed aremarkable increase in the oil recovery and favored applica-tion of this process for the field trial. Similarly steamfloodingexperiments carried out in laboratory also favored field trial ofthis process.

Two pilots were conceptualized under similar field condi-tions in the central area to see the feasibility of field applica-tion of these processes. As the

in situ

combustion pilot wasperforming remarkably well, it was thought prudent not topursue steam flood pilot any more.

In Situ

Combustion Pilot:

An inverted five spot pattern of150 m x 150 m well spacing (5.5 hectares) with the air injec-tion well located in the centre was planned. An observationwell was drilled 20m undip from the injector to monitor theeffect of combustion and rate of advancement of the fire front.

The plan was to carry out dry combustion for 110 days byinjecting air at 48,000 Nm

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/d after igniting with a gas ignitor,followed by the wet combustion phase. The total pilot life wasenvisaged as 3 years with an average fire front velocity of 15cm per day.

The pilot was initiated in 1990 and early response to the airinjection was observed in the pilot producers as well as in theoffset wells. The initial response in the producers was in theform increase in flow rate and decrease in watercut. The pro-duced gases indicated high concentration of nitrogen and car-bon dioxide (70% and 15% respectively) and low concen-tration of oxygen (around 0.2%) indicating establishment ofcombustion and utilization of oxygen injected. During the wetcombustion phase the concentration of these gases persistedindicating sustenance of fire-front.

The pilot resulted in an incremental oil production of34,000 m

3

for a cumulative air injection of 34.3 MMm

3

. Thecumulative air oil ratio (AOR) of the pilot works out to be 968Nm

3

/m

3

. It was observed that the air injection rates greaterthan 30,000 m

3

/d resulted in higher H

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S concentration in theproduced gas streams and higher GOR in up-dip directionwells. Therefore, low air injection profile was maintained inBalol pilot project. Thus the optimum air injection rate wouldbe 20,000–25,000 m

3

/d for injectors of commercial scheme.

Following the success of initial pilot, an expanded patternwas taken up with a spacing of 9 hectares. This pattern gavean incremental oil production of 45,000 m

3

for cumulative airinjection of 33.68 NMMm

3

. The cumulative AOR from thispilot was 682 Nm

3

/m

3

. This showed that the process could besuccessfully adopted in commercial scale for a spacing patternof 9 hectares.

The crude oil produced showed lower oil viscosity in thewells located up-dip, where the overall effect of combustionwas more pronounced. This was because of two reasons: grav-ity drainage predominant in the recovery process, and theinability to enhance production in the down-dip wells due tovarious equipment problems which resulted in preferentialmovement of combustion front up-dip.

From the analysis of pilot and expanded patterns it can beconcluded that the air injection well could be successfullyignited and combustion could be established. The combustionfront was sustained during the dry combustion as well as thewet combustion periods. The pilot as well as the offset wellsexhibited improved production performance. The combustionprocess was efficient as oxygen utilization efficiency washigh. The cumulative production achieved as a consequence ofcombustion was with an air oil ratio of less than 1,000 Nm

3

/m

3

which is good as compared to the world standards.

1,2,3

Furtherexperiments on changing water-air ratio during wet combus-

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tion phase showed that the optimum water air ratio during wetphase was 0.002 m

3

/m

3

beyond which quenching took place.Even though the pattern size of 5.5 hectares was experi-mented, the process was not impaired even up to 22.2 hectarespacing patterns. The experience of the pilot showed thatgravity segregation played an important role in the recoveryprocess. This also led to the conclusion that in the central partwhere the dip is large, and the up-dip line drive would be suit-able for exploitation of oil by

in situ

combustion process on acommercial scale. Since the southern part has comparativelylow dip with vast area between the pinchout and the oil-watercontact, pattern

in situ

combustion would be economicallyviable. In order to achieve success and to enhance the effi-ciency of the process, delineation of up-dip pinchout of Kalolpay is very important.

Commercialization of EOR:

Following the success of

insitu

combustion pilot in the central part it was decided to com-mercialize this process in central and southern areas. In thecentral part of heavy oil belt, the sand is narrower and steeplydipping as compared to the northern and the southern areas.This favors application of the process in the updip line drivefor

in situ

combustion in this part. For this, injectors have beenlocated on the structurally highest part of the reservoir to takethe advantage of gravity.

In the southern part, the process is being applied in 15 pat-terns under Phase-I and in 31 patterns under Phase-II wheretwo sands, KS-I and KS-II, will be simultaneously subjectedto

in situ

combustion.

Northern part of heavy oil belt is still under primary pro-duction. Cyclic steam injection in the primary producers hav-ing suitable well completions can be used to enhance wellproductivity.The commercial scheme of

in situ

combustion incentral and southern areas is likely to increase oil productionfrom a present level of 0.7 MMt per annum to about 1.8 MMtper annum.

Two horizontal wells, one each in northern and centralareas, were drilled. Production performance of these wellsshow that a horizontal well of 300 m horizontal section canreplace 4–5 vertical wells. The northern most extremity ofheavy oil belt can be developed with the help of horizontalwells.

Delineation of Updip Pinchout of Sands

Due to large influence of gravity on the performance of

in situ

combustion pilot, it became logical to delineate the updip pin-chout of the paysands to take the advantage of regional dipduring commercial application.

Initial delineation of pinchout line was carried out based ondata obtained from 2-D seismic. However, drilling of develop-ment/delineation wells showed that the actual pinchoutexisted further westward by around 100–150m. Besides this,the top of the pinchout varied in depth, contributing to greateruncertainty. The seismic data was tied-up with well log data.Maps, corrected based on this data, could be used for locatingthe updip injection line during application of commercial

insitu

combustion, especially in the central part.

Pressure transient tests conducted in a self flowing well ofthe southern part of the field confirmed that although the wellwas considered to be 100m east of pinchout line, no barriercould be picked up within its radius of investigation of 350 m.A stepout location based on this data corroborated the findingsof well test data.

Con c lusions

From the above analysis it can be concluded that the primaryrecovery from heavy oil belt is low and depends upon natureof the reservoir rock and its fluid properties. The primary pro-duction performance of southern part of the field is better ascompared to northern part since oil in this area is compara-tively lighter and reservoir properties are better. The primaryproduction can be further improved by installing progressivecavity pumps and hydraulic pump jack, which will not onlyprevent premature water production but reduce operating cost.

The results of pilot

in situ

combustion show that this pro-cess can be successfully applied in the central part. The updipline drive will yield high recovery in this area as it is steeplydipping. Cyclic steam injection should be adopted in northernpart in the wells with suitable completions to enhance primaryproduction from this area. Later on steam flooding/

in situ

combustion can be used as commercial EOR techniques.

Horizontal wells can be successfully drilled and completedin unconsolidated sandstone reservoirs and can be used forproductivity enhancement in the northernmost extremity. Infilldrilling in northern and southern areas can reduce well spac-ing from 300m x 300m to 212m x 212m to improve sweepefficiency and to account for local heterogeneity during EORapplication.

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Acknowledgment

The authors are grateful to Director (Exploration), Oil andNatural Gas Corporation Ltd. for according permission topublish this paper.

References

1. Carcaona, A.T. “Results and difficulties of world’s largest

In Situ

Combustion Process: Suplacu de Barcau Field,Romania”.

2. Turta, A. “Development of the

In Situ

Combustion Pro-cess in an Industrial Scale at Videle Field, Rumania”,SPE, Reservoir Engineering, Nov. 1966.

3. Williams, R.L., Jones J.A., and Counihan, T.M. “Expan-sion of Successful

In Situ

Combustion Pilot in MidwaySunset Field”, SPE-16873.

4. Gupta, A.K., Singh, Daljit, and Bhatia, A.K. “Exploita-tion of Heavy oil from updip Pinchout area of Lanwa-Balol- Santhal Fields”, Presented in Petrotech–97, NewDelhi

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Table 1: Rock and Fluid Properties of Heavy Oil Areas of North Gujarat Area

Figure 1: Location Map of Mehsana Block

Table: 1(a) Rock Properties 4

Parameter South Central NorthPorosity (%) 28 27 26Permeability (md) 5,000 3,000 3,000Rock Compressibility(v/v/atmosphere)

3.25 x 10-6 3.25 x 10-6 3.25 x 10-6

Table: 1(b) Fluid Properties

Parameter South Central NorthSpecific Gravity at15°C

0.952 0.963 0.976

API° at 15°C 17 15 12Asphalt Content (%) 7 14 21Pour Point 15 15 21Viscosity of Oil in Reservoir Conditions (cp) 60 155 550Solution GOR 16 15 8Saturation Pressure (Kg/cm2) 64 29 12FVF 1.066 1.038 1.046

Table: 1(c) Reservoir Characteristics

Parameter South Central NorthReservoir Pressure (Kg/cm2) at -950 m MSL

102 102 102

Permeability of Oil Zone (md) 5,000 3,000 3,000Aquifer Permeability (md) 1,500 1,500 1,500Specific Productivity Index(m3/d/Kg/cm2/m)

1.5 1.1 --

Mobility Ratio 120 320 1100

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Figure 2: Log Mitifs of Pay Sand

Figure 3: Performance of Heavy Oil Belt

Figure 4: Fractional Flow Curve (FS VS SW)

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Figure 5: Performance Graph of

In Situ

Combustion Pilot Area

Figure 6: Structure Contour Map on Top of Sand-1 Kalol Formation, Northern Area of Heavy Oil Belt

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Figure 7: Structure Contour Map on Top of Sand-1 Kalol Formation, Central Area of Heavy Oil Belt

Figure 8: Structure Contour Map on Top of Sand-1 Kalol Formation, Southern Area of Heavy Oil Belt