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Application of Material Balance and Volumetrics to Determine Reservoir Fluid Saturations and Fluid Contact Levels
Abstract
A methodology was developed to determine residual saturations in a reservoir from fluid contact measurements and to forecast future contact movement. The methodology is based on the remaining volumes of fluid in the reservoir. At any given time, the remaining volumes of fluid (oil, gas and water) can be determined from known pore volumes, fluid contacts and saturations. The remaining fluid volumes can also be determined from material balances. The volumetric and material balance calculations are equated to solve for either the unknown saturations or the location of the fluid contacts. To apply the method, production, injection, pressure, fluid property, pore volume versus depth and initial fluid contact data are required.
The methodology was demonstrated on the Westerose D-3 Pool. Residual saturations were determined to be: Swi = 6%, Sgc = 4%, Sorw = 25%, Sorg = 16%, Sgt = 23% and Sorwg = 13.5%. A history match of the historical contact levels for the Westerose Pool was obtained with an average absolute deviation of 2.0 m, which was within the measurement error. Contact movements were also forecast from 2000 to 2003. While there were no reported contact measurements in this period, the observed decline in oil rates was consistent with the predicted oil zone thickness.
Introduction
Reservoir simulation and analytical models require reservoir data, including: production, injection and pressure history; fluid properties; rock properties (porosity, permeability, water saturation, gross pay, net pay, top of structure); rock-fluid properties (relative permeability, capillary pressure); well locations and perforation schedules; and, contact (water-oil and gas-oil) measurements. Usually, the greatest uncertainty is in the rock properties and the rock-fluid properties. This paper focuses on rock-fluid properties; particularly, end point or residual saturations such as residual oil saturation to water displacement (Sorw), gas displacement (Sorg) and gas displacement followed by water displacement (Sorwg). These saturations limit the maximum oil recovery from a reservoir.
The end point saturations are usually determined from laboratory analyses of core plugs. However, these core plugs are sometimes altered during handling, sampling and preparation. Another problem is that the best core often turns to rubble and is not retrieved. In addition, core sample size is of the order of one billionth of reservoir scale and if the reservoir is heterogeneous, a set of relative permeability curves derived from laboratory analysis may not represent the actual reservoir end point saturations.
In theory, more representative field-scale saturation end points can be determined for reservoirs with fluid contacts from fluid contact movement data. Batycky et. al.(1) discussed using gas contact measurements to determine trapped gas saturations (Sgt). Their method involves equating volumetric oil- and gas-in-place to material balance oil- and gas-in-place and solving for the unknown Sgt. However, to the authors' knowledge, a generalized formulation of this method has not been developed. As well, such a method has yet to be adapted to forecast contact movement, given known residual saturations.
The objectives of this paper are:to develop a method for determining residual (end point) saturations from contact measurements; and,to develop a method to forecast contact movement in a reservoir once the end point saturations are known.
... Kirby, Stamm and Schnitz (1956) also studied the depletion history, future performance, and injection performance of a gascap-drive reservoir. Delauretis, Yarranton, and Baker (2008) also showed the application of material balance and volumetrics to determine reservoir fluid saturations and fluid contact levels for various reservoirs including a combination drive. Moreover, there are some authors who presented developed methods for obtaining original fluids in place and aquifer parameters from material balance equation by improving the solution of Havlena and Odeh (Havlena & Odeh, 1963;Havlena & Odeh, 1964), also applying mathematical elements such as curve fitting to determine the best accurate parameters. ...
... Delauretis et al. equations that describe the remaining gas, oil and water volumes, respectively, during reservoir depletion were used as follows (Delauretis, Yarranton, & Baker, 2008): ...
Depletion performance of combination drive oil reservoirs is highly influenced by changes in reservoir rock and fluid data, relative permeability data, and PVT data of reservoir. Therefore, future prediction of combination drive oil reservoirs is difficult due to the long terms, huge equations and the sensitivity of data especially the PVT data and relative permeability data. In this paper, an integrated analytical model was developed to simulate the combination drive oil reservoir's performance. It couples the general material balance equation with equations for water influx, water-invaded pore volume, gas-invaded pore volume, oil and gas saturation, and fluid contacts for combination oil reservoirs. All these equations are merged and solved simultaneously with reservoir depletion stages. A comparison with the various equations' results for the integrated model has been developed so that it can be utilized in history match mode. This is used to estimate fluid saturation distribution after water influx and gas-cap invasion, original fluids in place, aquifer parameters and type, fluid contact levels, and effective recovery factor during gas and water aquifer movement towards the productive hydrocarbon zone in all reservoir depletion stages. The developed model has been validated using published cases for various oil reservoirs' conditions, resulting in a good match between published case results and developed model results for these reservoirs. After validating the model, it has been used for two Egyptian combination drive fields. The field production history has been matched and future production performance for these reservoirs was simulated. Finally, the developed model also has the capability to predict reservoir performance for another Egyptian combination drive oil reservoir field under water and or gas injection, integrated with decline curve analysis.
... A case study was used to validate the theory proposed and a good match was obtained showing that a calibrated material balance can be used to predict fluid contacts to reasonable accuracy. Delauretis,Yarranton & Baker (2008) developed a methodology to estimate current oil-watercontact (OWC) and gas-oil-contact (GOC) in the field from initial fluid in place, production and, rock and fluid properties. The methodology was based on the volume of remaining fluid in the reservoir using material balance techniques and calculation of the fluid contacts assuming the whole reservoir as a single tank, and with best estimate of initial contacts and residual saturations. ...
... Reservoir simulation and analytical models require reservoir data, including: production, injection and pressure history; fluid properties; rock properties (porosity, permeability, water saturation, gross pay, net pay, top of structure); rockfluid properties (relative permeability, capillary pressure); well locations and perforation schedules; and, contact (water-oil and gas-oil) measurements. Usually, the greatest uncertainty is in the rock properties and the rock-fluid properties [50] . ...
This study includes a geological and reservoir study for the Shuaiba (Lower Qamchuqa) formation in the Khabaz field. The objective of this study is to construct a reliable reservoir simulation model that can be used to predict the future reservoir performance and suggest a dependable development plane of the field. This study is divided into two major stages, geological modeling and reservoir modeling to create a comprehensive basis of understanding for the field concerned. The first stage focused on construction a three dimensional geological model for the reservoir under consideration, Petrel (V.2015) software was used for this task, while the Interactive petrophysics (IP) software was employed for the log interpretation task. The results showed that unit B has good petrophysical properties and it represents the main reservoir unit in the Shuaiba reservoir. The oil originally in place was calculated to be 276 MMSTB. Black oil simulator (Eclipse 100) was used to simulate the reservoir to conduct the history matches with the real data. The percentage error of matching was 1% for oil production rate and between (1-8%) for reservoir pressure after adjustments on model. The reservoir support was week to moderate water drive since pressure decline was observed with production. Four cases of prediction performance for the Shuaiba reservoir were suggested. These cases start from 2019 to 2029. The results revealed that the plan with the four water injection wells and five production wells (five direct spots) beside the 4 existing wells attained a plateau of 3600 STB/Day for seven years, the reservoir cumulative production was found equal to 23.5 MMSTB and the recovery factor reaching 6.3% by the end of prediction period . The development of the field is infeasible economically, because the the oIIp was very low (276 MM STB) and the estimeated recovered oil was very low (6.3 %).
... A case study was used to validate the theory proposed and a good match was obtained showing that a calibrated material balance can be used to predict fluid contacts to reasonable accuracy. Delauretis,Yarranton & Baker (2008) developed a methodology to estimate current oil-watercontact (OWC) and gas-oil-contact (GOC) in the field from initial fluid in place, production and, rock and fluid properties. The methodology was based on the volume of remaining fluid in the reservoir using material balance techniques and calculation of the fluid contacts assuming the whole reservoir as a single tank, and with best estimate of initial contacts and residual saturations. ...
Most reservoir in mature oil fields are vulnerable to challenges of water and/or gas coning as the size of their oil column reduces due to extensive period of oil production. These often result to low oil production and excessive water and/or gas production. This study therefore seeks to evaluate the occurrence of coning through the movement of fluid contacts in mature oil field reservoir. MBAL petroleum software was used to study the tendency of coning in mature oil field in the Niger delta. Using reservoir production history; fluid saturation, initial pressure, initial fluid contacts and depth data, a simulation was run to predict the future movement of oil-water contact and gas-oil contact with declining pressure. Using the interception on a plot of oil-water contact and gas-oil contact against time, a point where both water and gas are likely to cone was identified. Sensitivity study was also carried out to evaluate the trend of the critical rate with the reduction in oil-column due to the shrinking fluid contact. It was observed that the critical rate reduces with declining oil rim fluid contacts. Therefore to avoid coning in mature oilfield rim, the critical rate of the respective decline in oil column thickness is determined to maximize oil production.
... Thus, both the gas breakthrough in oil wells and oil invasion in gas cap easily take place in gas cap reservoir. [1][2][3][4][5][6][7][8] Under the depletion development, the reasonable control of the recovery rate of gas cap and oil rim can reduce the pressure depletion effectively. Under the barrier water injection development, the injected water can establish the water barrier between gas cap and oil rim, which can supply energy to both gas cap and oil rim. ...
For the A South and Γ North reservoir of Zhanzhol oil field in Kazakhstan, only the oil rim was developed since 1983. Recently, the gas cap of A South reservoir was exploited in September, 2014. However, the concurrent production of gas cap and oil rim is likely to cause the pressure imbalance, which will lead to the worse development effect of the whole reservoir. In order to acquire the efficient concurrent production of gas cap and oil rim, the technique policy charts of concurrent production are established, involving three types of development mode such as depletion development, barrier water injection development and barrier plus pattern water injection development. For depletion development, rational oil recovery rate increases with rational gas recovery rate; for barrier water injection development, the rational position of barrier water injection well moves towards the inner oil-gas contact with the increase of gas recovery rate and injection-production ratio; for barrier plus pattern water injection development, the rational ratio of barrier water injection to pattern water injection increases with gas recovery rate and injection-production ratio. By improving the well network of barrier plus pattern water flooding and the ratio of barrier water injection to pattern water injection, the concurrent of oil rim and gas cap of A South reservoir was carried out. Furthermore, 2.3 billion of natural gas was yielded yearly. The control degree of water flooding of oil rim was enhanced; the natural decline rate of oil rim decreased and the development effect of oil rim improved greatly.
... Onwukwe [3] and Kartoatmodjo [4] proposed a model for determining the optimum horizontal well placement in a thin oil rim reservoir in order to control coning tendencies effectively and optimize oil production. Delauretis [5] caculated the migration law of oil-gas interface in different development patterns using material balance method. Ezzam [6] pointed that both gas production and oil production would lead to changes of oil-gas interface and mutual displacement between oil ring and gas-cap. ...
In order to study the mechanism of oil and gas coordinated development in oil rim reservoirs, three-dimensional visualized gas-cap reservoir physical simulation device was established to simulate the processes of oil and gas development at different gas production rates. According to experimental result, it is shown that migration speed of oil-gas interface was reduced with increasing gas production rates while migration speeds of internal and external oil-gas interfaces gradually became close, which effectively slows down occurrence of gas channeling, reduces production gas oil ratio and increases the swept volume of gas drive, so as to improve its development effect. Moreover, optimization of coordinated development methods of gas-cap and oil ring under three different conditions was studied as well,. According to optimization result, it is shown that optimal gas production rate for coordinated development of oil and gas was different under different conditions and policies. If well shut-in problem( due to gas channeling) is not considered, optimal gas production rate is small, since development years of reservoir will become longer and its development effects will become better. If well shut-in problem is considered, accumulative oil and gas equivalent will be maximized when gas production rate is between 2% and 4%.
... Onwukwe [3] and Kartoatmodjo [4] proposed a model for determining the optimum horizontal well placement in a thin oil rim reservoir in order to control coning tendencies effectively and optimize oil production. Delauretis [5] caculated the migration law of oil-gas interfaces in different development patterns using material balance method. Ezzam [6] pointed that both gas production and oil production would lead to changes of oil-gas interface and mutual displacement between oil ring and gas-cap. ...
For gas cap reservoir with strata dip, mechanical property of oil-gas contact movement is described by particle-tracing of Lagrange. With assumption of straight line movement, movement of oil-gas contact is obtained by basic differential equations of oil and gas seepage. Application results show that: With decrease of reservoir pressure, decline of gas phase potential is much greater than oil phase potential; Oil-gas contact intends to move towards oil well as oil rim is only developed; On the contrary, oil-gas contact intends to move towards gas well as gas cap is only developed; Rational control of oil recovery rate and gas recovery rate is beneficial to stabilize oil-gas contact.
The Mahogany field was discovered in 1968 and appraisal was completed in 1996. The field is located 50 miles offshore eastern Trinidad (Fig. 1) with the platforms situated in water depths of 230 feet and contains more than 30 stacked sands (17 of which are gas bearing) with a development footprint area of c. 10000 acres. Initially the field’s resources were booked assuming volumetric depletion was the dominant drive mechanism (Nandalal and Gunter 2003), however the updated understanding showed that water drive was the prevailing mechanism with near volumetric depletion being exhibited by only two reservoirs within the field, the TQ51 FB4 and TQ51 FB5.
There were two development wells in the TQ51 FB4, MA04 and MB13. MA04 became liquid loaded and stopped producing in March 2004 after fourteen months of concurrent production with MB13. MA04 showed volumetric behaviour until late life. Due to the volumetric response exhibited by the reservoir, the MB13 well was assigned low pressure access resources and was also used as a swing well to compensate for gas market demand fluctuations.
Conventional material balance techniques (P/Z, Havlena Odeh, van Everdingen Hurst aquifer match) led to the belief that the drive mechanism was volumetric to very weak aquifer support. Pressure Transient Analysis (PTA) and pore volume material balance estimates showed the presence of an edge drive aquifer. This was corroborated by geological studies which showed that although the two reservoirs had the same initial gas water contact (GWC), with production they became two separate compartments exhibiting different properties, the aquifer acting via an edge drive mechanism.
The Westerose field produces hydrocarbons from a dolomitized Upper Devonian reef. Secondary pore systems dominate porosity. The effect of diagenesis on the depositional fabric has made it difficult to subdivide the reef using depositional facies-reservoir quality relationships. Horizontal permeability, vertical permeability and porosity increase from reef flank to reef interior and from the upper reef to the base of the cored reef. Although significant trends in the magnitude of permeability are present within the reef, the reservoir fluid flow model for the rock volume being drained by a single well is best described as a random arrangement of blocks of differing permeability. -from Authors
The Windfall D3A reservoir in north-central Alberta is a Devonian Leduc D-3 reef structure containing sour gas, condensate and oil. This paper describes the results of recent studies on rock-fluid relationship for the Windfall reservoir which led to several conclusions regarding the effectiveness of the past 15 years of cycling and the importance of maintaining high voidage replacement ratios. It is postulated that the sweep efficiency of the cycled gas in Windfall is low due to the heterogeneous permeability distribution within the reservoir. It is concluded that liquid recoveries can be further enhanced by altering production-injection flow patterns.
Black-oil and multicomponent compositional models were used to simulate a gas-cycling scheme. Reservoir fluid sample data were carefully matched to ensure realistic predictions of phase behavior during cycling. The study indicated that cycling was technically feasible and that an additional 64,906,000 bbl of hydrocarbon liquid would be recovered over the life of the cycling and blowdown.
Introduction
The Bonnie Glen D-3A pool, discovered in Jan. 1952, is situated approximately 43 miles southwest of Edmonton, Alta. The reservoir, which forms part of the prolific Leduc reef chain, is one of the most capable prolific Leduc reef chain, is one of the most capable producing fields in Canada. The original oil in place producing fields in Canada. The original oil in place is estimated to be 657,138,000 STB, with an original gas cap of 444,900 MMcf. The recovery mechanism is primarily gas cap expansion and natural water influx with excellent gravity segregation, which will effect an estimated recovery of 452,226,000 bbl of oil, or 68.8 percent of the original oil in place. Since simultaneous production of the gas cap during the life of the oil column could be detrimental to oil recovery, gas cap production would normally be deferred until depletion of the oil column. Gas cycling, however, can be carried on while the oil column is depleting, with a beneficial effect on the over-all recovery of hydrocarbon liquids.
Reservoir Properties and Performance
The Bonnie Glen pool is a dolomitized, biotherm reef in the Leduc member of the Upper Devonian Woodbend formation and is completely underlain by the Cooking Lake formation. The reef, which forms part of the Leduc D-3 reef trend, is approximately 7 miles long, 21/2 miles wide at the original oil/water contact and less than 1 mile wide at the original gas/oil contact, Maximum original net pay thickness of the reef is 701 ft, of which 402 ft is gas cap and 299 ft is oil column. The Cooking Lake formation is an active aquifer extensive in all directions except to the west, where it pinches out almost immediately. The aquifer is common to other oil- and gas-bearing accumulations in the same reef trend (Fig. 1), and interpool interference is evident by past pressure trends of the D-3 pools. Fig. 2 presents a structure contour map of the top of the pool, based on the gross reef section, and Table 1 presents a summary of important reservoir properties. The original composition of the gas cap and oil column is presented in Table 2. Since discovery of the field, 166 wells capable of production have been drilled, most of them on production have been drilled, most of them on 40-acre spacing. Currently, 58 wells produce the field allowable of approximately 40,000 BOPD. Cumulative production to Dec. 31, 1971, was 154,078,000 bbl of oil, 114,500 MMcf of solution gas, and 1,204,000 bbl of water. The reservoir pressure at datum has declined from the original 2,477 psi to a current 2,005 psi. Fig. 3 presents the production and reservoir pressure history of the Bonnie Glen pool, and Fig. 4 shows a transverse cross-section of pool, and Fig. 4 shows a transverse cross-section of the reservoir, illustrating original and current gas/oil and oil/water interfaces. Interfaces were calculated by a combination of material balance and a knowledge of cumulative reservoir pore volume as a function of reservoir depth. Calculations agreed very closely with semiannual field measurements.
JPT
P. 1285
Gas production from Alberta's Leduc-age reservoirs, which originally contained more than 400 × 109m3 OGIP, has and will continue to be significant. Estimating recoveries from these bottom- water drive pools has been difficult. Recoverable reserves are dependent upon both the trapped gas saturation and aquifer performance. Generalizing core displacement tests and applying limited field experience has been problematic.
With a number of projects reaching maturity it is now possible to integrate core displacement data and field performance to clarify the factors that control gas recovery in these pools. This study is able to demonstrate the dependence of trapped gas saturation on a number of factors including wettability, initial fluid saturation and permeability. A simple analytical model was developed to estimate and interpret blowdown recoveries from these pools. The actual performance of a suite of Leduc-age pools has been interpreted and applied to validate the model's applicability.
Introduction
Gas recovery from a bottom water drive pool is primarily dependent on the amount of gas remaining unrecovered behind an advancing gas/liquid contact. Since 1990, Imperial has been producing the Leduc D-3A rese rvoir gas cap. The process is described as gas cap blowdown. This paper assesses the gas recovery that can be expected from the Leduc D-3A reservoir and implications for other Leduc-age pools. Evaluation of the trapped gas saturations included:reviewing the available documentation of laboratory studies;accessing industry expertise; and,material balance calculations on selected Devonian Reef reservoirs.
Recovery Concepts and General Terminology
Trapped gas, Gt, is defined as the total amount of unrecovered gas in a liquid-displaced volume of reservoir. The trapped gas therefore includes both the residual gas in the displaced pore volume and any gas remaining in unswept portions of the invaded reservoir. The amount of trapped gas within the liquid-swept zone can be determined using material balance calculations in conjunction with measurements that locate the gas/liquid contact. At any time during production, the amount of remaining or trapped gas, Gt, in standard units, sm3, can be determined from material balance, given by:
Equation 1 (available in full paper)
In Figure 1, the gas remaining unrecovered in the displaced volume, Vd, behind an advancing gas/liquid contact is the sum of the residual gas, Gr, which remains undisplaced within the liquidswept region and that remaining bypassed or unswept, Gu, i.e.,
Equation 2 (available in full paper)
During production, the amount of gas that is trapped by the displacing liquid phase is affected by the pressure changes that occur over time within the displaced zone, Vd. The pressure in Vd depends on withdrawal history and the underlying aquifer response. In Leduc's case the aquifer response is influenced as well by other Leduc-trend reefs on the common Cooking Lake aquifer. If the pressure in Vd increases over time, the initial value of Gt remains fixed even though the reservoir volume (and hence the saturation) containing that gas becomes reduced.
This paper entails the implementation and interpretation of the first successful interwell test ever reported in the industry to determine residual oil saturation in a gas-saturated reservoir. Two interwell tests were conducted in Golden Spike to measure the residual oil saturation to gas-flood at two different depths. This method, which involves the comparison of the whole partitioning and non-partitioning tracer curves to derive residual oil saturation values, is an improvement of the original method that compared only the breakthrough times. A chromatographic transformation technique was developed for curve comparison so as to avoid tedious simulation for data interpretation. For layers with different residual oil saturation, the transformation method works only for a pseudo single porosity reservoir with ordered layers, i.e. low residual oil saturation for a high permeability layer. The first test indicated that there were three layers with residual oil saturations of 7%, 15% and 20%. The results from the second test conducted in a lower production interval were masked by the presence of extensive fractures in the production zone. In spite of the interference from the fracture production, the residual oil saturation in some flow channels could still be estimated to be about 12%. Because it is unlikely that the tracers could enter the matrix during the test, the residual oil saturation measured is probably the oil saturation in some secondary channels. Sulphur hexafluoride, F13BI (brome-trifluoro-methane) and F12 (dichloro-difluoro-methane) were selected as the tracers from the previous lab tests. The tracers were pre-mixed and injected as a liquid. A Freon phase behavior program was developed to calculate the exact amount of the Freon's injected.
Introduction
Upon evaluation of various conventional methods, the interwell tracer test ⁽¹⁾ has been identified as the most reliable means to determine residual oil saturation in Golden Spike, a low-pressure, low-porosity, gas-saturated carbonate reservoir. The original interwell method disclosed by Cooke ⁽²⁾ in 1971 involved the comparison of the relative breakthrough times of the partitioning and non-partitioning tracers for residual oil saturation calculation. Breakthrough time is not a well-defined quantity, as it is often obscured by dispersion, the detection limit, and most importantly, by the streamline and layer distributions. As a result, the interpretation technique, certainly inadequate, draws criticism (3,4). Consequently, because of the lack of suitable chemicals and interpretation technique, no single test has been tried in the field or, at least, published in the literature. To circumvent the problems anticipated in Cooke's method, our interwell method employed a whole curve comparison to derive a residual oil saturation value at any location on the curve using a simple “landmark ” comparison technique. Under ideal conditions, residual oil saturation can be determined by layers. To demonstrate the feasibility of the method, extensive tests were performed in the lab ⁽⁵⁾. Slim tube displacement results indicated that residual oil saturation could be measured in an accuracy of ± 1 % pore volume from the separation of tracers. This paper entails the design, implementation and interpretation of the two field tests conducted in Golden Spike in 1987.
Introduction
When Texaco Canada Resources Ltd. opened the $40 million addition to its Bonnie Glen gas processing facHities in June 1982, the three-plant complex located 80 km southwest of Edmonton, became one of Canada's largest natural gas liquids producers. The new Bonnie Glen Solution Plant No.2 can handle 1.4 million cubic metres of gas a day, including a 2780 cubic metre a day fractionation train. The new solution gas processing plant was completed on time and on budget under an engineering, procurement and construction turnkey contract.
The Oilfields
Texaco's Bonnie Glen complex serves two of Canada's most prolific oilfields, Wizard Lake and Bonnie Glen, discovered within a year of each other in the early 1950s.
The Wizard Lake oilfield, about 11 km north of the Bonnie Glen Gas Plant, has an original oil-in-place of 61.2 million cubic metres and has been under pressure maintenance since 1969. The Wizard Lake Miscible Flood is one of the largest and most successful enhanced recovery projects of its type in the world. The project increased the field's recoverable oil by 11 million cubic metres to an estimated 84% of the original oil-in-place. Over the years, some 4.4 million cubic metres of LPG solvent has been injected into its miscible slug. The field, 100% owned by Texaco, can produce up to 8700 cubic metres of oil per day.
The Bonnie Glen find differed from Wizard Lake because it had an original primary gas cap overlying the 119 million cubic metres of oil-in-place. This pool, 74% Texaco owned, is not under pressure maintenance. However, ultimate recovery is still expected to be 71% of the original oil-in-place with a production capability of 1300 cubic metres a day. In 1975, the gas cap was unitized and a cycling scheme was brought on-line which has successfully minimized retrograde losses and improved ultimate pool recovery by 4.3 million cubic metres.
The Processing Complex
The Bonnie Glen gas processing complex today includes three facilities: two solution gas plants, Nos. 1 and 2, each with a 1.4 million cubic-metre-a-day capacity and a cycle plant which has a 3.9 million cubic-metre-a-day capacity to extract natural gas liquids as part of the gas cap cycling project (Fig. 1).
The original Bonnie Glen Solution Plant No. 1 came into operation in 1954 with the capacity to handle 790 000 cubic metres of gas a day. It was one of the first gas plants built in Alberta, installed at that time for conservation purposes. Plant No.1 had five integral compressors, a mine sweetening and ambient temperature lean oil absorption systems and a fractionation facility.
By 1969, the plant's rated capacity was increased to 1.4 million cubic metres a day through a series of improvements which included the addition of compression, a propane refrigerated gas fractionator downstream of the lean oil absorber and a second depropanizer. Then as now, Plant No.1 extracted more NGL than it could fractionate. The excess raw NGL formed one of the solvent streams injected in the Wizard Lake Miscible Flood.
Much of western Canada's conventional crude oil occurs in vertically continuous reefal carbonate structures. A common strategy has been to support oil production through downward vertical gas displacement. The gravity-stable displacement yields excellent conformance and high oil recoveries, with typical residual levels of 20% pore volume (PV). Once the oil zone has been depleted, leaving only a sandwich loss, the pools enter a blowdown phase to produce the gas cap from the top of structure. During the blowdown phase, if there is an underlying aquifer, the oil sandwich is displaced upward into the previously gas-displaced oil zone, trapping gas. Owing to the presence of the trapped-gas saturation, the remaining oil saturation in this zone, is reduced to near miscible levels (10 to 15% PV) as it is displaced by the underlying water, mobilizing incremental oil equal to 5 to 10% PV. When an aquifer is not present, bottomwater injection can be applied to ensure displacement through the entire gas-displaced oil zone. The successive displacement process (SDP), as this tertiary waterflood concept has been named, has been confirmed with full-diameter reservoir-condition core tests on carbonate cores in the laboratory. Observation from the initial stages of a full-field SDP application in Imperial Oil's Bonnie Glen reservoir after approximately 4 years of operation provides further encouragement, with performance indicating a reduction in the oil residual of 5 to 6% PV.
An aquifer model study investigated the effect of the Leduc Woodbend D-3A Pool gas cap blowdown on nine other communicating pools situated on the common Cooking Lake Aquifer. A three-dimensional, three-phase black oil model was constructed to represent the ten pools along the trend and the Cooking Lake carbonate platform on which they rest. An excellent history match of the pools' performance substantiated the investigation of several production alternatives to optimize gas cap blowdown recovery, as well as study the impact of the blowdown on the other communicating pools on the Cooking Lake chain.
Several production cases investigated the effect of void age replacement, water injection site selection and gas cap blowdown rate. The aquifer model also provided the necessary boundary conditions, such as pressure and water influx/efflux histories, for other Leduc simulation models. The primary focus of the paper, then, is on the operational impact of the blowdown, not on the mechanics to the simulator, or the simulation process.
Introduction
The ten, prolific Leduc-aged Pools that stretch for 145 km from St. Albert to Homeglen-Rimbey have come to be known as the "Golden Trend " (Fig. 1). Known too, is that these ten pools, as well as other distant D-3 reefs, receive pressure support from the vast Cooking Lake Aquifer. Being concerned about the impact the proposed Leduc-Woodbend D-3A Pool gas cap blowdown could have on the nine neighbouring pools. Esso Resources Canada Limited retained INTERCOMP to conduct an aquifer model study of the local system.
The objectives of the study were to:develop a reliable, predictive tool for the Golden Trend by obtaining a pressure match for the period 1947 to 1981 for the ten major pools (St. Albert D-3B, Big Lake D-3A, Acheson D-3A, Leduc D-3A, Glen Park D-3A, Wizard Lake D-3A, Bonnie Glen D-3A, Westerose D-3, Westerose South D-3A and Homeglen-Rimbey D-3. See Fig. 2); andpredict the pressures of these ten pools to the end of their forecasted productive lives during:—a gas cap blowdown at Leduc; and—selective water injection, designed to isolate pressure influences in other major pools along the aquifer during a Leduc blowdown.
In recognizing :the great quantity of remaining reserves in the ten pools; andthe potential to increase the reserves in some of these pools by miscible flooding;
the authors wish to make their efforts known to the industry. The approach of the writers is to summarize the work with the expectation that, if needed, the reader will reference Application 830340(1) to obtain the details desired.
Setting up the Simulator
The model used in this study was Intercomp's Beta II(2) black oil reservoir simulator. Consistent with a three-phase, three-dimensional, Cartesian application of the simulator, the following data were prepared.
Aquifer Description
Area
The area of the Cooking Lake Aquifer included in this study extends southwesterly from Edmonton for a distance of over 136 km (Fig. 1). The width of the study area varies from 7.9 to 13.1 km, following the lateral extent of the Cooking Lake platform.