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Summary The Ekofisk reservoir is a high porosity, low matrix permeability naturally fractured chalk. Fluid flow is largely governed by the distribution, orientation, and interconnectivity of the natural fracture system associated with complex structure and reservoir distribution. Because of the impact heterogeneity has on preferential fluid-flow direction, significant attention was given to capturing as much of the intrinsic heterogeneity as possible, both laterally and vertically, in the new three-dimensionally geological model. Anon-uniform simulation mesh was defined for the fluid-flow model with a grid size of 450 ftร450 ft in the crestal area of the field and increasing towards the flanks. A flow-based upscaling technique was then applied to preserve the heterogeneity from the geological to the fluid-flow model. Because of the complexity of the Ekofisk field, with its numerous faults and fracture networks, anisotropy was one of the primary attributes calibrated to achieve an individual well and field history match. However, faults and fault sealing factors, vertical permeability, pseudorelative permeability curves, bubblepoint pressure correlations, local permeability, and rock compressibility were also key parameters in the history match, and are presented in this paper. A brief discussion on the preliminary implementation of water-induced compaction is included. Introduction The Ekofisk field is a prolific field discovered in 1969 that is located in the Norwegian sector of the North Sea. The reservoir consists of two fine-grained limestone producing formations, the Ekofisk formation (Danian Age)and the Tor formation (Maastrichtian Age), separated by a thin, impermeable Tight Zone. The reservoir was initially overpressured and contained an under saturated oil at 7,120 psi and 268ยฐF at a datum elevation of 10,400 ftsubsea. The bubblepoint pressure was approximately 5,545 psig. Production started from the chalks in 1971. Current estimates from the reservoir characterization project indicate about 7 billion barrels of oil originally in place. Production as of the end of 1998 from 76 deviated and horizontal wells was 310,000 BOPD and 510 MMcf/D of gas. Reinjection of natural gas in excess of sales has been ongoing in Ekofisk since 1975 with 1.3 Tcf of gas injected to date. Eight wells were initially completed for gas injection service, with five of the original gas injection wells being recompleted as production wells through time. A pilot water injection project was initiated in 1981 in the highly fractured Tor formation and in the Lower Ekofisk in1986. Fieldwide water injection began in 1987. Current water injection rates are 800,000 BWPD into 37 active water injection wells. A number of additional improved oil recovery techniques are being evaluated, and a water-alternating-gas (WAG) pilot in the southern area of the field was attempted. Fig. 1 shows a structure map of the Ekofisk field drawn on the top Ekofisk formation. Reservoir characterization of Ekofisk was directed at gaining a detailed understanding of reservoir hydrocarbon volumes, the architecture of the reservoir, and at fully describing the heterogeneity and anisotropy of reservoir parameters. Because water breakthrough not consistent with expectations has been observed in areas of the field, it is important that the highest degree of heterogeneity be represented in the flow model. This is especially significant given that the Ekofisk field is currently undergoing a major field redevelopment in which 45 new wells will be drilled before the end of 2003. To date a total of 25 new wells have already been drilled and are currently on production. The history match of the Ekofisk reservoir characterization fluid-flow model was completed in September 1997 after a period of approximately 12 months of intense work. The complexity of the Ekofisk field, with its numerous faults and fracture networks, provided quite a challenge in matching the 25 years worth of production and performance data. The heterogeneity that was captured in the three-dimensional (3-D) geological model, and preserved in the upscaling process to the fluid-flow model, proved to be the key to being able to match individual well performance. In general, a very good history match was achieved on both a field and platform basis, and on an individual well basis. Fluid-Flow Model Model Selection. In a fractured reservoir like Ekofisk, the large scale fluid-flow characteristics are primarily controlled by the distribution, orientation, and interconnectivity of the natural fracture system. One of the challenges in modeling this type of reservoir is to account for the fluid transfer between the high permeability fractures and the low permeability matrix blocks that contain the bulk of the pore volume. Full field modeling of the Ekofisk field is performed with a single porosity model that uses effective permeabilities for interblock flow and pseudorelative permeability functions to account for matrix-fracture and matrix-matrix interactions. Model Comparison. The main variation between the Ekofisk reservoir characterization (ERC) and previous fluid-flow models relates to improvement in the description of heterogeneity and anisotropy. These differences include permeability, simulation grid orientation, cell sizes and layering, and non-neighbor connections. Permeability in the ERC model is linked directly to fracture intensity through an algorithm developed based on the log linear relationship between fracture spacing (intensity) data from core and well test effective permeability. The orientation of the flow model was revised to better reflect current fault/stress regimes and, in turn, permeability and permeability anisotropy. Fault trend/system analysis indicates three primary fault systems, and orientation of the grid along the major axis of the structure and the NNW-SSE strike-slip faults was determined to be the optimum alignment. Typical well spacing in Ekofisk is 1600 ft and the average grid cell size in the crest of the field was established based on two criteria: the desire to have at least two grid cells between production and injection wells and the need to optimize the number of cells to allow the model to be used as an active tool in future field development decisions. The cells were 450 ftร450 ft as compared to the previous model definition of 600 ftร600 ft.
- Geology > Structural Geology > Fault (1.00)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock > Limestone (0.70)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Europe > United Kingdom > North Sea > Central North Sea > Utsira High > PL 006 > Ekofisk Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 018 > Block 2/4 > Greater Ekofisk Field > Ekofisk Field > Tor Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 018 > Block 2/4 > Greater Ekofisk Field > Ekofisk Field > Ekofisk Formation (0.99)
- (8 more...)
Summary A fully coupled geomechanics and single-phase, fluid-flow model is developed to evaluate the combined effects of stress, fluid flow, and reservoir property changes on well responses in stress-sensitive reservoirs. In particular, we pay attention to the interpretation of pressure buildup tests and to changes in the production characteristics of wells. In general, for weak hydrocarbon reservoirs that exhibit nonlinear, elastic and plastic constitutive behaviors, and stress-dependent properties such as permeability and porosity, the physical effect contributed from geomechanics may not be ignored in well test analysis. The coupled interaction between geomechanics and reservoir fluid production markedly affects the stress state and reservoir properties. Because we are using a coupled, numerical model, we evaluate the consequences of using simplified relationships (e.g., permeability as a function of pressure). Numerical analyses are performed to quantitatively assess the impact of reservoir stress sensitivity on practical well test problems. The key variables investigated in the study, that are important in evaluating stress-sensitive reservoirs, include permeability, porosity, and constitutive behaviors of reservoir rock including hysteresis and loading conditions. The development of high-stress regions around wellbores and its consequences on well performance are considered. The numerical results from the study indicate that for analyzing highly stress-sensitive reservoirs, a fully coupled geomechanics and fluid-flow modeling approach is necessary and the developed model employed in this study provides such a tool. Introduction Conventional treatments of pressure-transient analysis of stress-sensitive reservoirs are based on either Biot's formulation or by a simple decoupling of the fluid-flow and geomechanical considerations by the pore-volume compressibility. Regardless of the approach taken, the final step involves the solution of a nonlinear differential equation with permeability and compressibility dependent on pressure. This step permits us to draw on analogous problems in linear thermoelasticity to obtain solutions for the pressure distribution. Implicit in all of these works is the assumption of a linear-elastic medium with no hysteresis. What is not recognized is that pure compaction and stress sensitivity may follow different constitutive relationships and further loading and unloading conditions dictate the manner in which pore volume and permeability changes occur. In situations where fluid-flow and geomechanical processes are decoupled, the consequences of decoupling and conditions under which it appears that decoupling is appropriate are never mentioned. Intuitively, the decoupling would not be appropriate if the assumption of a linear-elastic medium does not hold. It is the objective of this paper to use a fully coupled geomechanical model to evaluate the interaction of the stress state and fluid flow on pressure behavior. This model permits us to address the issues we have raised in a comprehensive manner and thus presents a basis for the study of pressure-transient analysis in stress-sensitive reservoirs. This paper is divided into four sections. First, we briefly outline the coupled field equations, discuss stress-strain relationships for linear-elastic and elastoplastic systems and describe numerical procedures for obtaining solutions of each system. Second, we examine the effect of rock compaction on well responses in reservoirs with constant permeability. Third, we discuss characterization of pressure tests for linear-elastic and elastoplastic systems. Various dependencies of permeability as a consequence of compaction noted in the literature are examined and analyzed. Fourth, we present a method to determine initial permeability from pressure data even though the permeability around the sandface may not recover as a consequence of hysteresis in stress-sensitive reservoirs. Fifth, we compare responses for coupled and uncoupled systems under the assumption that the rock obeys linear-elastic behaviors. The discussion that follows should serve as an underpinning for further studies. The Model A numerical model based on a finite-element method was developed for analyzing the coupled problem of isothermal, single-phase flow in a deformable porous medium. In the following subsections, the mathematical formulation, stress-strain relations, and the numerical procedure used for the model are briefly described. The detailed description of the developed model and its validation was presented in Ref. 1.
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Integration of geomechanics in models (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
This paper (SPE 51396) was revised for publication from paper SPE 36753, first presented at the 1996 SPE Annual Technical Conference and Exhibition, Denver, Colorado, 6-9 October. Original manuscript received for review 24 October 1996. Revised manuscript received 23 October 1997. Paper peer approved 7 July 1998. Summary This paper presents the calculation of near-wellbore skin and non-Darcy flow coefficient for horizontal wells based on whether the well is drilled in an underbalanced or overbalanced condition, whether the well is completed openhole, with a slotted liner, or cased, and on the number of shots per foot and phasing for cased wells. The inclusion of mechanical skin and the non-Darcy flow coefficient in previously published horizontal well equations is presented and a comparison between these equations is given. In addition, both analytical and numerical solutions for horizontal wells with skin and non-Darcy flow are presented for comparison. P. 392
- North America > United States > California > Sacramento Basin > 2 Formation (0.99)
- North America > United States > Louisiana > East Gulf Coast Tertiary Basin > Austin Chalk Formation (0.98)
- Well Drilling > Drilling Operations > Directional drilling (1.00)
- Well Completion > Completion Installation and Operations > Perforating (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Well performance, inflow performance (1.00)
This paper (SPE 50990) was revised for publication from paper SPE 29111, first presented at the 1995 SPE Symposium on Reservoir Simulation, 12-15 February. Original manuscript received for review 15 February 1995. Revised manuscript received 20 May 1998. Paper peer approved 3 June 1998. Summary This paper describes a three-dimensional (3D), three-phase reservoir simulation model for black oil and compositional applications. Both implicit pressure, explicit saturation/concentration (IMPES) and fully implicit formulations are included. The relaxed volume balance concept effectively conserves mass and volume and reduces Newton iterations in both formulations. A new implicit well rate calculation method improves IMPES stability. It approximates wellbore crossflow effects with high efficiency and relative simplicity in both IMPES and fully implicit formulations. Multiphase flow in the tubing and near-well non-Darcy gas flow effects are treated implicitly. Initial saturations are calculated as a function of water/oil and gas/oil capillary pressures, which are optionally dependent upon the Leverett J function. A normalization of the relative permeability and capillary pressure curves is used to calculate these terms as a function of rock type and gridblock residual saturations. Example problems are presented, including several of the SPE comparative solution problems and field simulations. P. 372
- Europe (0.94)
- North America > United States > Texas (0.28)
- North America > United States > Alabama (0.28)
- North America > United States > Alabama > Chatom Field (0.99)
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Alberta Basin > Deep Basin > Carson Creek Field > Beaverhill Lake Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 018 > Block 2/4 > Greater Ekofisk Field > Ekofisk Field > Tor Formation (0.99)
- Europe > Norway > North Sea > Central North Sea > Central Graben > PL 018 > Block 2/4 > Greater Ekofisk Field > Ekofisk Field > Ekofisk Formation (0.99)