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Search North Slope Basin: Compositional effects during immiscible gas injection
...Immiscible gas injection performance Techniques described in this page are classic methods for describing ...immiscible displacement assuming equilibrium between injected ...gas and displaced oil phases while accounting for differing physical characteristics of the fluids, the...
This page has shown how a simple gravity drainage model can be readily applied to predict recoveries by gas drive and gravity drainage when flow rates are less than one-half the critical rate and permeabilities in the vertical direction are high. Some applications of the model have been unsuccessful because of lower-than-expected vertical permeabilities. As a practical matter, the simple model should be used to predict reservoir behavior only when it can be shown to match history or when applied to a field analogous to one that the model fits.
- North America > United States > Texas > East Texas Salt Basin > Hawkins Field > Woodbine Formation (0.99)
- North America > United States > Alaska > North Slope Basin > Prudhoe Bay Field > Ivishak Formation (0.99)
- North America > United States > Texas > East Texas Salt Basin > Woodbine Formation (0.98)
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...Displacement efficiency of immiscible gas injection The conceptual aspects of the displacement of oil by ...gas in reservoir rocks are discussed in this article. There are three aspects to this displacement: ...gas and oil viscosities, ...
The conceptual aspects of the displacement of oil by gas in reservoir rocks are discussed in this article. There are three aspects to this displacement: gas and oil viscosities, gas/oil capillary pressure (Pc) and relative permeability (kr) data, and the compositional interaction, or component mass transfer, between the oil and gas phases. One must first understand the viscosity and density differences between gas and oil to appreciate why the gas/oil displacement process can be very inefficient. Gases at reservoir conditions have viscosities of 0.02 cp, whereas oil viscosities generally range from 0.5 cp to tens of centipoises. Gases at reservoir conditions have densities generally one-third or less than that of oil.
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- North America > United States > Texas > East Texas Salt Basin > Hawkins Field > Woodbine Formation (0.99)
- North America > United States > California > Sacramento Basin > 4 Formation (0.99)
- North America > United States > Alaska > North Slope Basin > Prudhoe Bay Field (0.99)
- North America > United States > Alaska > North Slope Basin > Kuparuk River Field (0.99)
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...Vertical or gravity drainage gas displacement This page discusses the primary manner in which the ...immiscible gas/oil displacement process has been used in qualitative terms. This is the use of ...gas injection high on structure to displace oil downdip toward the production wells that are completed low in the...
This page discusses the primary manner in which the immiscible gas/oil displacement process has been used in qualitative terms. This is the use of gas injection high on structure to displace oil downdip toward the production wells that are completed low in the oil column. In many cases, an original gas cap was present, so the gas was injected into that gas cap interval (seeFigure 1[1] for cross-sectional view of anticlinal reservoir with gas cap over oil column with dip angleฮฑ and thickness h). In this situation, the force of gravity is at work, trying to stabilize the downward gas/oil displacement process by keeping the gas on top of the oil and counteracting the unstable gas/oil viscous displacement process. If the oil production rate is kept below the critical rate, then the gas/oil contact (GOC) will move downward at a uniform rate.
- North America > United States > Alaska > North Slope Basin > Prudhoe Bay Field > Ivishak Formation (0.99)
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...PEH:Immiscible Gas Injection in Oil Reservoirs Publication Information Petroleum Engineering Handbook Larry W. Lake, Edit...hysics Edward D. Holstein, Editor Copyright 2007, Society of Petroleum Engineers Chapter 12 โ Immiscible Gas Injection in Oil Reservoirs H.R. (Hal) Warner Jr., Warner Consulting Services and E.D. Holstein, Consultant... Pgs. 1103-1147 ISBN 978-1-55563-120-8 Get permission for reuse This chapter concerns gas injection into oil reservoirs to increase oil recovery by ...
The conceptual aspects of the displacement of oil by gas in reservoir rocks are discussed in this section. There are three aspects to this displacement: gas and oil viscosities, gas/oil capillary pressure (Pc) and relative permeability (kr) data, and the compositional interaction, or component mass transfer, between the oil and gas phases. The first two topics are discussed in this section; the third is discussed in the next section. Gas/Oil Viscosity and Density Contrast One must first understand the viscosity and density differences between gas and oil to appreciate why the gas/oil displacement process can be very inefficient. Gases at reservoir conditions have viscosities of 0.02 cp, whereas oil viscosities generally range from 0.5 cp to tens of centipoises.
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- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
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- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
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- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Gas-injection methods (1.00)
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...SPE 75198 An Overview of Streamline Tracer Modeling of Miscible/Immiscible WAG ...Injection IOR F. Ruan, Schlumberger GeoQuest, S. Carhart, BP, R. M. Giordano, Consultant, G.H. Grinestaff, B... Bratvedt, R. Olufsen, Schlumberger GeoQuest Copyright 2002, Society of Petroleum Engineers Inc. compositional, three-phase streamline model to simulate the This paper was prepared for presentation at the SPE/...
...e defined by cell, by pattern, by region or solvent allocation logic routine distributes solvent to injection by field. In history mode, we usually match the timing of the wells by compiling a prioritized effi...tion logic can also be applied to develop new injector-producer Field Application: Prudhoe MIST WAG Injection patterns, or to encourage the formation of mature patterns. The Prudhoe Bay field is located on the...vent to injectors with relatively production rate of 590 MSTB/D. The field has active small solvent injection to encourage the expansion of gravity drainage, waterflood and miscible IOR depletion immature patt...
...ESTAFF, F. BRATVEDT AND R. OLUFSEN SPE 75198 MWAG. These processes are modeled as solvent and lean gas techniques such as the Todd-Longstaff approach, 9,10 since the tracer desorbing trapped IOR tra...r or cluster pattern. IOR rates can be calibrated by the tracer adsorption isotherm table. Fig. 1--Gas saturation in a vertical cross-section finite-difference The field-scale tracer model is calibrate...d by historical Truth Model of an MWAG process. WAG injection and IOR production data. This calibrated The mobilization curve is typically obtained by running a ...
Abstract The streamline-based tracer model has been successfully deployed to history match and predict miscible and immiscible Water Alternating Gas (WAG) processes at the field scale. The tracer model is a simplified method for the three-phase WAG process, and is computed parallel to the traditional streamline waterflood model. This paper provides an overview to illustrate the relevant concepts and applications of the streamline-based tracer model. A Prudhoe Bay example of the vertical Miscible Injection Stimulation Technique (MIST) is presented to demonstrate and to verify the field use of the tracer model. Introduction WAG injection has been recognized as an effective improved oil recovery (IOR) procedure and is widely applied to enhance trapped oil production in reservoirs such as in Prudhoe Bay. Our knowledge of the controlling physics of WAG injection in the field can be limited. WAG injection is a complex multiphase process influenced by important factors such as geologic heterogeneity, gravity, phase interactions resulting in changes in mobility, among many others. Historical efforts to develop simulation tools for WAG processes to history match and to predict field scale IOR operations have proven to be difficult yet challenging. Accurate modeling requires fine-scale, three-dimensional, fully compositional models that simulate rapid gas movements in a reservoir containing possibly thousands of wells. Such models can be very CPU-intensive for real reservoir management and decision-making. With the continuing development of streamline technology, it is possible to construct a field-scale, 3D, compositional, three-phase streamline model to simulate the dominant physics of the WAG process, although CPU times can still be large. The streamline model used in this paper was designed when the streamline simulator could only support two-phases. The tracer model is therefore an add-on to a traditional two-phase (oil and water), front-tracking reservoir simulator, leading to speed-up and flexibility in simulating the WAG IOR process. Future enhancements to the tracer model will utilize more of the current simulator's 3D and three-phase capabilities. This tracer add-on model was designed to simulate the WAG injection process in a simplified two-phase setting. Highly complex, faulted grids can be modeled and large times step can be taken with minimal numerical dispersion. As wellrates change, front locations are mapped and propagated along updated streamlines. This approach takes advantage of minimal numerical dispersion, which plays havoc with finite-difference prediction alternatives. This leads to the possibility of running large fine-scale models very quickly. The tracer model consists of two independent displacement processes propagating in parallel along each streamline. The first process is the traditional waterflood to reduce oil saturation to waterflood residual level; the second process is the MWAG to further reduce oil saturation to below waterflood residual level. An important feature of the streamline-based tracer model is the explicit modeling of IOR oil (i.e., the incremental oil recovery over waterflood) spatial distribution. In this paper, we use the term IOR to strictly refer to the incremental oil from the WAG injection operation in the field. The IOR displacement process is mimicked by the simplified movement of solvent and IOR tracers, each tracer flows along the existing streamline (for oil and water) at a user-specified multiple (accessible pore volume factor) of the Darcy velocity. This explicit approach allows streamlines to reveal WAG-injector/IOR-producer pairs and clusters dynamically.
- North America > United States > Alaska > North Slope Borough > Prudhoe Bay (0.56)
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...gregation. This is because the second liquid phase consisted primarily of Performance of continuous injection, slug ...injection, and water CO2 and contained only negligible amounts (less than 0.05%) alternating ...gas (WAG) ...
...A SIMULATION STUDY OF ENHANCED RECOVERY OF SCHRADER SPE 76776 BLUFF HEAVY OIL BY IMMISCIBLE AND MISCIBLE ...GAS INJECTION 3 Slug ...Injection. Because continuous ...
...SPE 76776 A Simulation Study of Enhanced Recovery of Schrader Bluff Heavy Oil by Immiscible and Miscible ...Gas Injection R. R. Madarapu, Baker Hughes Inteq, S. Khataniar, SPE, S. L. Patil, SPE, and A. Y. Dandekar, SPE, ...ka Fairbanks Copyright 2002, Society of Petroleum Engineers Inc. to 21 o API with little solution gas. Due to the heavy nature of This extended abstract was prepared for presentation at the SPE Wester...
Abstract The Schrader Bluff Pool is a shallow, heavy oil reservoir in the Alaskan North Slope. Due to the absence of a significant primary drive, enhanced oil recovery methods must be considered for recovering heavy oil from the Schrader Bluff Pool. The objective of this study was to use reservoir simulation to evaluate immiscible and miscible solvent injection processes for improving oil recovery from Schrader Bluff. Typical reservoir heterogeneity encountered in the Schrader Bluff sands was incorporated into the simulation model. Performance of solvents readily available in the area was studied for different modes of injection such as continuous injection, slug and WAG injection. It was concluded that immiscible, lean gas type injectants would be ineffective for oil recovery from the Schrader Bluff Pool. The miscible WAG injection processes appeared to be promising. Introduction The Schrader Bluff Pool is located in the Milne Point Unit of the super giant West Sak field. The West Sak field is a part of the Kuparuk River Unit located to the west of the Prudhoe Bay Unit in the Alaskan North Slope. The Schrader Bluff reservoir is estimated to contain over two billion barrels of heavy oil at depths ranging from 4000 to 5000 ft. Detailed reservoir description of the Schrader Bluff is available in the literature. The oil bearing sands of interest in Schrader Bluff are divided into the upper N-sands and the lower O-sands. These sands are unconsolidated with porosities ranging from 25% to 35% and permeabilities from 100 md to over 2 darcy. The average reservoir pressure is approximately 1300 psi and the temperature 82ยฐF. The oil gravity varies from 14 to 21ยฐAPI with little solution gas. Due to the heavy nature of the oil and the lack of any significant drive mechanism, primary recovery is expected to be very low, so that enhanced oil recovery (EOR) methods may need to be implemented at an early stage. Injection of immiscible and miscible gases appears to be the most practicable EOR method for the Schrader Bluff Pool because of availability of gas. In fact, difficulties associated with disposal of surplus gas was one of the motivations for undertaking this study. Performance of an immiscible or miscible solvent injection process is affected by reservoir heterogeneity and gravity segregation. For a horizontal displacement, gravity segregation tends to reduce recovery by reducing sweep efficiency. However, permeability heterogeneity, if suitably located, can reduce the effects of gravity segregation. In addition, transverse dispersion also affects the sweep and hence, oil recovery. Another potentially significant factor in enhanced recovery of Schrader Bluff oil by gas injection is the possibility of formation of a second, non-aqueous liquid phase when the injected fluid contains significant amount of CO2. Formation of the second liquid phase has been observed at low temperatures (<122ยฐF). The Schrader Bluff Pool being at 82ยฐF is a strong candidate for formation of a second liquid phase. The second liquid phase is believed to improve oil recovery by extracting the heavy hydrocarbon components from crude oil. In displacement experiments of the West Sak heavy oil by CO2, although immiscible in nature, high oil recoveries were observed, which were attributed in part to possible formation of a second liquid phase. Similar observations were made in slim tube experiments using Schrader Bluff crude oil by Inaganti. Therefore, it would be of interest to study the performance of CO2 and other readily available solvents in the North Slope for displacement of Schrader Bluff oil under actual reservoir conditions.
- North America > United States > Alaska > North Slope Basin > Kuparuk River Field > West Sak Field (0.99)
- North America > United States > Alaska > Schrader Bluff Formation (0.98)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Oil sand, oil shale, bitumen (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Miscible methods (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Gas-injection methods (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
...2 SPE-179604-MS Flue gas (a combination of several gases from combustion) Hydrocarbon ...gas, lean and enriched Air The type of ...gas injected is a function of the technical application, ...
...d can increase displacement efficiency. Christensen and Stenby 1998 noted that in an IWAG the first gas slug can dissolve to some extent, thus creating mass exchange that in turn produces some oil swelli...ng, hydrocarbon stripping, and viscosity reduction. Thus, the first gas slug may have the largest effect. However, the WAG process will divert ...gas into subsequently smaller pores and have the same effect, albeit lower oil volumes. Swelling increa...
...ere used for the testing. General characteristics of the IWAG after water flood are: Cumulative gas injection: 50 to 80% PV ...Gas slug size: 5-10% PV WAG ratio: 1:1 Number of cycles: 5 to 12 Six IWAG corefloods were perfo...ood ranged between 21 and 30%. Noteworthy is that this paper describes IWAG involving helium as the gas so that there would be no ...
Abstract Enhanced oil recovery (EOR) is a general application used in mature oil fields to generate additional reserve growth. Several types of EOR applications are implemented in the oil industry. One such application is the injection of gas into a reservoir as a gas displacement recovery (GDR) mechanism to induce additional reserve growth. A specific type of GDR application is the immiscible water-alternating-gas (IWAG) displacement process. In this application a slug of water is put into an injection well, followed by gas, which exists as a separate phase from the water and oil. Water and gas injection slugs are alternated until the designed amount of gas has been injected, or as field production dictates. Continuous water (case water) is typically injected after the IWAG process. Herein, the state-of-art of IWAG EOR is described from an extensive literature review. First, the theories of the recovery mechanisms that cause IWAG to produce incremental oil are described. These mechanisms include viscosity reduction, 3-phase relative permeability, oil swelling, and oil film flow, all of which are a function of fluid and rock-fluid interactions. Next, salient laboratory studies are summarized, including micromodel and core floods. These studies test pore-level characteristics, displaying ranges of residual non-wetting phase saturations (hydrocarbons) down to 0.13 to 0.25 and incremental oil recovery ranging from 14% to 20% of OOIP. Some experiments isolate a specific recovery mechanism in order to determine its validity and contribution to recovery. Studies generally point to the conclusion that the gas type shows no discernable difference in recovery character. The paper concludes with a synopsis of results from small-scale field trials and field-scale projects in both heavy and light oil. Both simulation modeling and field trials are summarized. Projects have been implemented with varying types of gases, WAG ratios, and gas slug sizes, resulting in incremental reserve growth being reported in the range of 2 to 9%. The fundamental immiscible recovery mechanisms in IWAG can produce lower cost and faster response EOR projects, with moderate recovery efficiency gains.
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- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.30)
- North America > United States > Alaska > Schrader Bluff Formation (0.99)
- North America > United States > Alaska > North Slope Basin > Milne Point Field > Kuparuk Formation (0.99)
- North America > United States > Alaska > North Slope Basin > Kuparuk River Field > Kuparuk Field > Kuparuk Formation (0.99)
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...SPE 63156 A FULLY COMPOSITIONAL STREAMLINE SIMULATOR 3 gravity segregation of the fluids. The gravity vector in The advantages of ...e the link between the pressure and saturation is high. This is especially the case for three phase compositional (Solve Equation 3) simulations. Earlier descriptions of ...compositional simulation with streamlines include a paper by Thiele et al 67 but this was limited to two phas...
...3-24, 1998. Heterougenous "FloW-UnitS": A Streamline 53. Porzuecek, C. and Ramirez, W.F.: "Optimal Injection Approach" SPE 22588, 66 th Annual Technical Strategies for Surfactant Flooding Enhanced Oil Co...95. and Application of a Streamline Micellar/Polymer 54. Porzuecek, C. and Ramirez, W.F.: "Optimal Injection Simulator" SPE 10290, 56 th Annual Technical Strategies for Surfactant Flooding Enhanced Oil C..." SPE Annual Technical Conference and Exhibition, San 28756 presented at the SPE Asia Pacific Oil & Gas Antonio, TX, U.S.A., Oct. 8-11 1989. Conference, Melbourne, Australia, 7-10 Nov., 1994. 72. Acs G...
...SPE 63156 A FULLY COMPOSITIONAL STREAMLINE SIMULATOR 9 22. Gimse, T., Thiele, M.R. and Tyrie, J.J.: "Simulation 37. LeBlanc, J.L.,... and Caudle, B.H.,:"A Streamline Model System Designed for PCs". The American Oil & Gas for Secondary Recovery" SPE 2865 presented at Ninth Reporter, March 1995. Production Techniques Sy...as, TX, 30. Higgins, R.V., and Leighton, A.J.: " Computer Sept. 27-30, 1987. Prediction of Oil and Gas Mixtures Through 44. Moissis, D.E., Miller, C.A. and Wheeler, M.F.: " Irregularely Bounded Porous ...
Abstract A new 3-D three phase compositional reservoir simulator based on extension of the streamline method has been developed. This paper will focus on the new methods developed for compositional streamline simulation as well as the advantages and disadvantages of this strategy compared with more traditional approaches. Comparisons with a commercially available finite difference simulator will both validate the method and illustrate the cases in which this method is useful to the reservoir engineer. Introduction Streamline methods have been used as a tool for numerical approximation of the mathematical model for fluid flow since the 1800's (Helmholtz and later Muskat) and have been applied in reservoir engineering since the 1950's and 1960's. The reason behind using the approach has been both the needs for solving the governing equations accurately and achieving reasonable computational efficiency. Streamline methods continued to be explored through the 1970's by LeBlanc and Caudle, Martin et al and Pitts et al and 1980's by Lake et al, Cox, Bratvedt et al and Wingard et al, but the focus of reservoir simulation was on developing finite difference simulators. In the 1990's streamline methods have emerged as an alternative to finite difference simulation for large, heterogeneous models that are difficult for traditional simulators to model adequately. These efforts are described in numerous papers notably by Renard, Batycky et al, Peddibhotla et al, Thiele et al, Ingebrigtsen, Ponting and in an overview paper by King and Datta-Gupta. The application of the method has been described by numerous other authors. Use of the streamline simulator used for the work in this paper has also been extensively described. Several similar approaches such as the method of characteristics, particle tracking and front-tracking have also been used in reservoir simulation. Conventional finite difference methods suffer from two drawbacks, numerical smearing and loss of computational efficiency for models with a large numbers of grid cells. Large models (10 โ10 cells) are routinely generated in order to accurately represent geologically heterogeneous, multi-well problems.. Finite difference methods based on an IMPES approach suffer from the time step length limiting CFL condition, so as the number of cells increases the maximum time step length get shorter for a given model. For a large number of cells the shortness of the time step can render the total CPU time for a simulation impractical. Fully implicit finite difference simulators can take longer time steps but require the inversion of a much larger matrix than the IMPES approach. This is an even larger issue with compositional simulation where a large number of components will make the matrix very large. Also the non-linearity of the governing equations might require a limitation on the time step length again making very large models impractical to run. This can be improved by using an adaptive implicit aproach. Conventional streamline methods are based on an IMPES method. In these methods the pressure is solved implicitly and then streamlines are computed based on this pressure solution. In this way the 3D domain is decomposed into many one-dimensional streamlines along which fluid flow calculations are done. This method assumes that the pressure is constant throughout the movement of fluids. One weakness with this concept is the lack of connection between the changing pressure field and the movement of fluids. This can cause instabilities and limitations on the time step length.
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...SPE 53714 MANAGEMENT OF WATER ALTERNATING GAS (WAG) ...INJECTION PROJECTS 3 projects, with a significant impact on the oil production Effect of changes in relative... permeability gas-water rate and recovery. Unstable displacements are normally In the WAG process there are changes i...
...g the WAG process to will allow to perform detailed simulations taking into ensure that the limited gas supply is being effectively utilized. account the lithology and stratigraphy at high resolution, Th...is is accomplished by routinely sampling the produced gas in order to determine the size of the blocks required in the from the wells in the WAG area to dete... the process design it has to be take into account the Ideally, a full field, finely gridded, fully compositional quality of the sediments and the flowunits net thickness in coupled with surface facility calculati...
...ocesses which include greater field proposed in mature reservoirs and secondary recovery use of WAG injection, well technology for drilling projects are planned to be conducted below the minimum horizontal, ex...ser well spacing, and select chemical process (Refs. 5,6,7). The reservoir and fluid properties are injection. Many fields have the possibility of using key factor for the design of the ...injection strategy. Reservoir combinations of methods; i.e. horizontal wells with WAG simulations indicate th...
This paper was prepared for presentation at the 1999 SPE Latin American and Caribbean Petroleum Engineering Conference held in Caracas, Venezuela, 21โ23 April 1999.
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- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
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...2 SPE 137062 (2004) proposed Gravity Assisted Gas Drainage as a Field Presentation tertiary recovery mechanism for low-relief fields. ...Gas The carbonate reservoir under consideration was part of a injected in vertical wells at the top of ...Its development called for a zone and the permeability in both zones of a two-zone peripheral water injection scheme, targeting the bottom composite system under the assumption that the outer part of the reser...
... SPEJ (June 1968), Trans., AIME 243, 149-of North Sea Enhanced-Oil-Recovery Projects Initiated 156. During the Years 1975 to 2005. SPE Res Eval & Eng 11 (3): 497-512. SPE-99546-PA. doi: 10.2118/99546-PA Mat..., 809-818; Trans., AIME, 257. Caudle, B.H., and Dyes, A.B. 1959. Improving Miscible Displacement by Gas-Water ...Injection. In Trans., AIME Oak, M.J. 1990. Three-Phase Relative Permeability of 213: 281-284. Water-Wet Bere...
...SPE 137062 Interpretation of Immiscible WAG Repeat Pressure Fall-Off Tests Bruno A. Stenger, Salem A. Al Kendi, Ammar F. Al Ameri, Abdulla...as the major tests acquired in two vertical pattern injectors operating in expected benefit from an immiscible WAG displacement a carbonate reservoir undergoing full field development. mechanism. All available ...observations were reviewed and Water Alternating Gas first pattern (WAG-1) started in integrated using a history-matched reservoir simulation August 200...
Abstract This paper reviewed the interpretation of repeat fall-off tests acquired in two vertical pattern injectors operating in a carbonate reservoir undergoing full field development. Water Alternating Gas first pattern (WAG-1) started in August 2002 with a period of continuous gas injection until 2006 when the first water cycle was initiated. In the second pattern (WAG-2) water injection was initiated in June 1998 until September 2007 when the first gas cycle started. A few pressure fall-off tests were acquired during the monophasic injection phase mostly to verify well injectivity. After Water Alternating Gas (WAG) cycles started, pressure fall-off tests were usually acquired at the end of each three-month injection cycle with 1:1 WAG ratio. Analytical fall-off test interpretation relied on the use of the two-zone radial composite model. The apparent permeability thickness product was corrected with the Perrine formulation of multiphase mobility. Triphasic oil permeability was calculated using the modified Stone I model. Multiple fall-off test interpretations indicated that the two pattern vertical injectors behaved differently even though both being fractured. The difference in behavior was linked to different perforated intervals and reservoir properties. Gas and water injection rates were showing differences between both pattern injectors as a consequence. No major operational issue was reported during the three-year operation of both WAG patterns. During the WAG cycles, gas banks were found to be of a small inner radius and almost undetectable at the end of the subsequent water cycle. Changes in the pressure derivative slope at the end of the subsequent water injection cycle indicated most likely the creation of an effective mixing zone of injected gas and water in the reservoir. Numerical finite-volume simulation was required to account for potential injected fluid segregation and, the multi-layered and heterogeneous nature of the reservoir. Repeat saturation logs acquired in observation wells provided critical information on the saturation distribution away from the injection wells. Enhanced vertical sweep conformance through phase mobility control in the presence of strong reservoir heterogeneity was the major expected benefit from an immiscible WAG displacement mechanism. All available observations were reviewed and integrated using a history-matched reservoir simulation sector model with boundary conditions obtained from a full-field model.
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