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Abstract This paper presents an enhanced oil recovery (EOR) evaluation for two heavy-oil fields in Africa. The objective of the evaluation is to identify the technically and economically viable EOR techniques for the fields. A total of thirteen established and emerging EOR techniques were evaluated in this study. The study included the first degree approximation of the oil recovery for the viable EOR techniques and the stand-alone project economics estimation. The data required for the study include:fluids and rock properties; driving mechanism; production data; OOIP and recoverable reserves; and relative permeability curves. Various EOR technique screening criteria, consisting of a list of reservoir parameters and their ranges which are likely to lead to a success, were applied to match the parameters of the study fields. The oil recovery predictions were estimated utilizing general reservoir parameters and developed correlations 1. The economic feasibility of the potential EOR techniques was then evaluated based on the stand-alone project economics that accounted for the revenue from the incremental oil and the associated operating and capital costs. The evaluation results showed that the thermal EOR techniques: steam flooding and in-situ combustion are technically the most viable EOR techniques for the fields. It was then followed by the chemical EOR techniques. The performances of steam flooding and in-situ combustion are both very promising, with oil recovery of up to 49% OOIP. Comparing to the oil recovery of water flooding, a significant incremental oil recovery of 24% OOIP was obtained. However, the in-situ combustion process is able to accelerate the oil production, which significantly impacts the economic viability assessment, rendering the in-situ combustion process as the most technically, and economically feasible EOR process for the fields. Based on the EOR evaluation, the oil recovery predictions and economic assessments of the thirteen EOR techniques, including the chemical, gas, thermal and microbial EOR techniques, served as a guideline to develop the long term corporate strategy regarding the EOR potential of the fields. Introduction Enhanced oil recovery (EOR) could increase technically and/or economically recoverable oil. In current reservoir management practice, various EOR options are considered much earlier in the productive life of a field. Adopting the same reservoir management strategy, EOR technology was considered to increase the oil recovery factor in two heavy-oil fields (18โ24oAPI) in African region. The predicted water flood oil recoveries of these fields are relatively low at about 17% to 25% STOIIP only. Thus, an EOR process instead of water flooding is worth to be considered at the beginning of these fields' lives. Inevitably, economics always play the major role in "GO/NO GO" decision-making for expensive EOR projects. This screening study was carried out to rule out the less-likely candidates. The objectives of this EOR screening study are to:Identify suitable EOR processes for the study reservoirs by a quick GO/NO GO screening. Estimate the expected recovery for the process (performance prediction using analytical methods) that passes the first screening criteria (GO/NO GO criteria). Carry out preliminary stand alone project economics assessment on the best two processes for each reservoirs evaluated. Select the most technically and economically suitable EOR process (for reservoirs screened to have more than one suitable process). The screening study flow chart is shown in Figure 1.
- North America > United States > Texas (0.28)
- North America > United States > Louisiana (0.17)
- North America > United States > Louisiana > Alpha Field (0.99)
- North America > United States > Wyoming > Powder River Basin > Shannon Formation (0.98)
Abstract Reservoirs declination in Apure State, Southwestern Venezuela, demands a huge technical effort in reservoir modeling when finding drilling opportunities to increase recovery factor and maintain oil production at attractive economical levels. One of these reservoirs, Escandalosa Inferior of La Victoria Oilfield was discovered by LVT-18 in 1991 with 38 MMSTB of STOOIP and in 1998, the last of its four producing wells was closed, reaching a recovery factor of 14%. An Asset Team revised and integrated geophysical, geological, petrophysical and production data to update Esc-Inf static model in 2005. No robust sedimentological model could be built because of cores absence; however, a facies and later a property distribution was designed with the help of well logs, regional knowledge and geostatistics. The resulting static model led to visualize the opportunity to drill a horizontal well in the highest attic of the structure to reactivate the reservoir. STOOIP calculation for this new model yielded a value of 13 MMSTB with 7.8 MMSTB of recoverable reserves and 2.5 MMSTB of remaining reserves, which could be extracted by the new well and finally obtain a recovery factor of about 60%. The dynamic model showed a reaccommodation of fluids due to its 5 years of closure, and certified the current presence of oil in the attic where the well was previously visualized. The prediction made by the simulator for a 5 years scenario, with a production of 650 STBD, highlighted the economical feasibility of drilling this well. Nowadays, the successful well LVT-46H is still active with 2 MSTBD and has accumulated 0.245 MMSTB, since its completion in 2006. These results validate the methodology presented in this work where data integration, the use of geostatistics and reservoir simulation are the main key for reactivating declined reservoirs and maintaining oil production. Introduction La Victoria Oilfield is located 40 Km to the west of Guasdualito Village, Apure State, Southwest of Venezuela and 6 Km to the East of the Colombian - Venezuelan boundary (see Figure 1). Escandalosa Inferior Reservoir, belonging to this oilfield, is a cretaceous unit (1) constituted mainly by massive and consolidated sandstones with a very continuous thickness in the whole oilfield of up to 140 feet, with few intercalations of shales, featuring porosity values between 20 and 25 % and permeability values between 0.5 and 3 darcies (see Figure 2). Escandalosa Inferior Reservoir had been reporting by the end of 90's high water cuts in the only four producing wells since its discovery, which is a contrasting fact in relation with its remaining reserves of 15.8 MMSTB following the official data yielded by the reservoir static model built in 2001. These high water cuts progressively caused the closure of the four producing wells, the last of which was closed in 1998, setting the reservoir to inactive with a recovery factor of only 14%. Under this perspective, no well could be workovered and even less drilled in this reservoir, without an appropriate structural reinterpretation. In 2003, a 3D seismic survey was completely processed and available for interpretation, and this was the starting point of the structural reinterpretation for generating a 3D static model supported by geostatistics techniques, well logs interpretation and the knowledge of regional geology since no robust sedimentological model was available due to core data absence in this reservoir. This new static model would then be used in a reservoir numeric simulation software in order to know the current state of the reservoir in terms of oil saturation after 7 years of inactivity, and in order to forecast the productivity behavior and future profitability of the prospect wells that probably could be highlighted by the static model and could help increase the reservoir recovery factor.
- South America > Venezuela (1.00)
- North America > United States > Texas (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.54)
- Geology > Structural Geology (0.47)
- Geology > Sedimentary Geology (0.45)
- South America > Venezuela > Apure > La Victoria Field > Navay Formation (0.99)
- South America > Venezuela > Apure > La Victoria Field > Escandalosa Formation (0.99)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Victoria Field (0.99)
Integrated Reservoir Modeling for Evaluating Field Development Options in Agua Fria, Coapechaca and Tajin Fields of Chicontepec Basin
Takahashi, Satoru (Japan Natl. Oil Corp.) | Abbaszadeh, Maghsood (Innovative Petrotech Solutions) | Ono, Kenji | Salazar-Soto, Humberto (Pemex E&P) | Alcazar, Luis Octavio (PEMEX Exploration and Production)
Abstract This paper presents a methodology for pixel-based hierarchical geostatistical reservoir characterization and flow simulation of submarine fan turbidite sandstone deposits in the Agua Fria, Coapechaca and Tajin fields of the Chicontepec basin in the Gulf of Mexico. Extreme heterogeneity of rock fabric and petrophysical properties prevails within the multiple stacks of turbidetic sequence events across the fields. Capturing this complex geologic heterogeneity in reservoir characterizations and reservoir simulation models forstrategic decision making in field development is a major challenge. We first present a general methodology based on multivariate Gaussian formalism for integrating various sources of data at different scales to build high-resolution geostatistical reservoir characterization models directly at log scale for the Agua Fria, Coapechaca and Tajin fields. Multiple seismic attributes and geological diagenesis information at sequence and subsequence scales are integrated into these models to generate representative reservoir descriptions. Next, we use the constructed geostatistical models to investigate recovery performance of Chicontepec fields under primary and waterflood processes. Sector models and pilots of multi wells in the Tajin and Agua Fria fields are considered for this purpose. The fine-scale and coarse-scale reservoir characterization models are calibrated to dynamic performance data by history matching the primary production and an actual waterflood pilot data in Agua Fria, and then used as predictive tools for other field development scenarios. The viability of waterflooding the very low permeability and highly diagenized Tajin filed is investigated, where large reservoirs are still left in-place because of loss of reservoir energy due to primary depletion. Introduction Integrated reservoir modeling by multi-disciplinary geostatistical approaches has spread to the industry in the past two decades as a basis to evaluate field development options in various types of reservoir depositional environments. Many attempts have been made to better utilize seismic data and geological scenarios in reservoir models because of dense areal coverage offered by seismic/geology that is not attained by sparsely drilled wells with vertically refined information. In the past several years, research has been conducted to develop practical technology for integrating geological, seismic and reservoir engineering information within the characteristics and constraints of Chicontepec basin fields for reservoir management and field developments. It had been recognized that the development of an integrated geostatistical methodology, verified by well data, would be an appropriate approach for this purpose. As a case study, Agua Fria, Coapechaca and Tajin fields are selected for research and benchmarking of the developed technology as a prototype to be expanded later to other fields in the Chicontepec basin. Lately, the focus has shifted to the design of optimum field development based on the constructed integrated geostatistical reservoir descriptions. Chicontepec basin, with a large field of 123 km in length and 25 km in width, has been formed by a complex system of submarine fan and turbidite sediment deposits in an eroded deep-water canyon originally formed in the Gulf of Mexico. This field was discovered in 1931, and commercial production commenced in 1952. The Chicontepec reservoirs consist of Upper Paleocene-Lower Eocene alternating sandstone and shale bodies. These bodies do not represent a continuous laminar extension throughout the entire field, and wide variations in clay-shale content and secondary porosity alterations by diagenesis are recognized. The major challenges are in modeling sand continuity, sand connectivity and effect of diagenesis on porosity to improve reservoir characterization for optimized field development planning and management of Chicontepec reservoirs.
- North America > Mexico > Veracruz (1.00)
- North America > Mexico > Tlaxcala (1.00)
- North America > Mexico > Puebla (1.00)
- (2 more...)
- Phanerozoic > Cenozoic > Paleogene > Eocene (0.74)
- Phanerozoic > Cenozoic > Paleogene > Paleocene (0.54)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.70)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.57)
- Geology > Sedimentary Geology > Depositional Environment > Marine Environment > Deep Water Marine Environment > Submarine Fan Environment (0.45)
- Geophysics > Seismic Surveying > Seismic Interpretation (0.49)
- Geophysics > Seismic Surveying > Seismic Processing (0.46)
- 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)
- Asia > Middle East > Oman > Ad Dhahirah Governorate > Arabian Basin > Rub' al-Khali Basin > Block 5 > Daleel Field (0.99)
- (7 more...)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Geologic modeling (1.00)
- (3 more...)
Abstract Methodology is presented and proven for determination of the best estimate parameter values affecting the matrix-to-fracture interface fluid transfer in naturally fractured reservoirs. Improved matrix-fracture-transfer models are applied based on presumed matrix block shapes. Fracture surface hindered interface fluid transfer is considered between the matrix blocks and surrounding natural fractures. Analytical solutions developed for special boundary conditions are applied for the typical laboratory tests for rectangular and cylindrical shape rock samples. The workable equations and straight-line data plotting schemes are developed for effective analysis and interpretation of laboratory data obtained from various shape oil-saturated reservoir rock samples immersed into brine. This allows the rapid determination of the characteristic parameters of the matrix-fracture transfer models for various shape matrix blocks, which are essential for prediction of petroleum recovery from naturally fractured reservoirs by computer simulation. The methodology is verified using various experimental data concerning water imbibition into oil-bearing rock, and the values of the characteristic parameters, such as the diffusion coefficient, and skin coefficient and thickness, are determined. Introduction Flow through naturally fractured petroleum reservoirs is generally described by simultaneous numerical solution of the equations describing the flow of gas, oil, and brine phases in the fracture and matrix media, coupled with the matrix-fracture interface boundary conditions. The overwhelming computational effort required for this purpose is usually alleviated based on a fracture-flow and matrix-source/sink formulation. This requires the utilization of approximate analytical matrix-fracture interface-transfer functions derived under certain simplifying assumptions (de Swaan, 1978, 1990, Civan, 1998, Rasmussen and Civan, 1998, and Civan and Rasmussen, 2001), the parameters of which are estimated by laboratory core imbibition tests. There is considerable amount of experimental data available in the literature, but the present data analysis and interpretation techniques lack in accuracy and suitability for practical applications. The derivation of adequate transfer functions to express the matrix-fracture interface flow has attracted much attention. Consequently, many theoretical models (Warren and Root, 1963, de Swaan, 1978, 1990, Kazemi et al., 1976, 1992, Moench, 1984, Zimmerman et al., 1993, Civan, 1993, Gupta and Civan, 1994, Lim and Aziz, 1995, and Reis and Cil, 2000)and empirical correlations (Zhang et al., 1996, Guo et al., 1998, and Matejka et al., 2002) have been proposed. Reviews of the formulation and evaluation of matrix-fracture fluid transfer functions can be found in various publications, including Lim and Aziz, 1995, Panfilov, 2000, Reis and Cil, 2000, Babadagli and Zeidani (2004), and Civan and Rasmussen (2005). In general, the derivation of theoretical transfer functions has been based on approximate analytical solutions of the linearized and/or simplified diffusion equation within simple shape matrix blocks, such as those shown in Figs. 1, subject to certain matrix-fracture interface boundary conditions. Mostly, the previous approaches assumed constant fracture fluid conditions (Dirichlet type), such as prescribed saturation, over the surfaces of the matrix block. Then, Duhamel's rule has been applied to account for variable fracture fluid conditions (de Swaan, 1978, 1990). In contrast, Moench (1984), Wallach and Parlange (2000), and Civan and Rasmussen (2005) considered the fracture skin effect (Cauchy boundary condition) caused by the fracture surface damage by deposition of mineral matter and debris, mechanical processes, and build-up of a stationary fluid layer, as described in Fig. 2.
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (22 more...)