The Relationship Between Recovery Efficiency and Depositional Setting in a Deltaic Plain Environment Shoup, Robert C.1 (1) Knowledge Reservoir, Kuala Lumpur, Malaysia A Full Field Review was conducted for a structurally and stratigraphically complex field offshore Sarawak Malaysia. The East portion of the field is a relatively simple, west-plunging flower-structure fold. The West portion of the field consists of a series of normal conjugate faults that formed in response to tensional bending over a deep-seated normal basement fault. These faults result in the severe compartmentalization of the western portion of the field. There are over 20 separate reservoirs in the field, comprising both channel sands and incised valley fill sequences that were deposited by a generally westward flowing river system. The eastern portion of the field was situated in the upper deltaic plain where deposition was from a fluvial environment. Production from these fluvial reservoirs exhibit little to no aquifer support and recovery efficiencies range from 20 to 35%. In contrast, the depositional setting for the western portion of the field was the lower deltaic plain which exhibits a more estuarine than fluvial setting. Production from these estuarine reservoirs exhibit significant aquifer support, and recovery efficiencies range from 35 to 50%. Integrated Geostatistical & Simulation Model for Optimizing the Oil Recovery Factor in the U1-3 Sands, Melones Field, Eastern Venezuelan Basin Benitez, Francisco1, Hector Marquez2, Jose Castillo1, Jeff Bayless2, Jorge Pérez3, Cristina Vera1, Terry Eschner2, Ana Rondon2, Rodolfo Perez1 (1) PDVSA, Puerto La Cruz, Venezuela (2) ROXAR INC, Puerto La Cruz, Venezuela (3) Universidad de Oriente, UDO, Ciudad Bolívar, Venezuela The Melones field is located in eastern Venezuelan basin. Its production started in 1957 by the well MM-407. An integrated study for this Field was performed to characterize the six highest producing intervals through geostatistical analysis. The structure is a gentle north-dipping monocline cut by east-west trending normal faults. Unconsolidated reservoir sands in the Miocene Oficina Formation (U1U-U1L) were deposited in coastal and deltaic depositional environments, whereas those in the underlying Oligocene Merecure Formation (U2U-U2L-U3U-U3L) were deposited by fluvial systems. Available data for this study includes facies and petrophysical evaluation logs, 3D seismic interpretation, core analysis and 24 instantaneous seismic attributes. A high resolution modeling grid was built using corner-point geometry. The final grid covers 500 Km2 and has a total number of cell of 250 millions. Facies modeling was performed by combining the Truncated Gaussian Simulation algorithm to describe sub- environments and coast lines, GMPP Simulated Annealing object based modeling to describe the stacked fluvial-channel fill and marine bars, and the Sequential Gaussian Simulation algorithm with trends for petrophysical modeling. Multiple realizations of different object sizes were evaluated using flow simulation to select the most representative model. The distribution and spatial variation of petrophysical properties within each facies was taken from 344 wells. The resulting geostatistical realizations reproduced the conceptual sedimentological model. This is the first full-field geostatistical model to honor the reservoirs heterogeneities. The result of the dynamic modeling stage was the optimization of the oil recovery factor to develop the estimated reserves of 340 MMSTB. 3D Modeling Study for Supporting Further Development of the M-19 Block, Carabobo Field, Orinoco Heavy Oil Belt, Venezuela Velasquez, Leonardo1, Benzaquen Isaac1, Jose Fleitas2, Zaida Perfecto1, Hector Figueroa1, Mauricio Herrera3 (1) PDVSA, Puerto La Cruz, Venezuela (2) PETROLEOS DE VENEZUELA, S.A, Puerto La Cruz, Venezuela (3) Schlumberger, Puerto La Cruz, Venezuela The objective is to present the results of an Geostatistical 3D Modeling Study, centered in the Characterization of Morichal Member in the Oficina Formation, Block M-19 of Carabobo Field, Venezuela, emphasizing Seismic Interpretation, geology, Facies Modeling and Petrophysics disciplines. Facies-based Rock Physics in the Nelson Field, UKCS - Part I: Petrofacies characterization Espejo, Irene S.1, Mark Kittridge1 (1) Shell International Exploration and Production Inc - EP Research and Development, Houston, TX Calibration of seismic amplitude response requires an accurate prediction of acoustic properties for reservoir and non- reservoir rocks and pore fluids at varying conditions. The estimation of seismic amplitude variation with offset and time- lapse response (4D) is similarly dependent on reliable rock and fluid property information. Building on Shell's successful efforts to characterize facies-based rock properties in unconsolidated sediments in Tertiary basins, this study extends the application to older, diagenetically complex rocks in the UK Central North Sea, and reveals significant variability in reservoir quality and elastic properties, for both sandstones and mudrocks. Nelson Field provides an excellent opportunity to examine the relationship between sedimentary facies and rock properties within channelized turbidites of a basin-floor submarine fan system. The large volume of core and well-derived petrophysical data available allows the creation of a simple lithofacies scheme, based on lithologies, surfaces, sedimentary structures and textural characteristics at mega- and microscopic scales. Reservoir types include coarse- grained and poorly sorted (S-Ta), medium-grained and moderately sorted (Tb and Ta) and fine-grained, laminated sands (Tc). Dirty sands comprise debrites (D) and possible slurry flows (SF). Mudrocks consist of silty, muddy turbidites (MT) and clay-rich, abandonment shales (HS). This classification allows a direct link between petrofacies, facies associations and elastic rock properties. Using this scheme, facies-derived rock properties can be generated for non-cored wells, integrate them into static reservoir models, provide a better understanding of in-fill targets, and serve as the basis for development of a field-scale elastic properties volume necessary for dynamic (4D) production monitoring. Facies-based Rock Physics in the Nelson Field, UKCS - Part II: Rock Properties Kittridge, Mark G.1, Irene S. Espejo2 (1) Shell International EP Inc. - EP Research & Development, Houston, TX (2) Shell International E & P, Houston, TX Our recent experience in a number of global basins has demonstrated the value of an integrated approach to developing rock and fluid acoustic properties for the quantitative interpretation of seismic data. Additional interpretive synergies are realized when the rock properties work is done within a collaborative workflow, leveraging petrologic and lithologic observations to constrain the development of rock physics models. Reservoir and elastic properties for the identified petrofacies were extracted from key (cored) well control, and subsequently used to develop rational, facies-speific rock physics relationships. The key wells were subject to rigorous data QC and deliberate ‘seismic petrophysics', including core-log calibration, fluid acoustic properties modeling, and quantitative shaly sand evaluation. In this workflow, the integration of lab- and well-based data is essential to the development of rock physics models with predictive capability. Distinct facies-specific elastic properties for the reservoir (sand) and non-reservoir (mudstone) lithologies were determined, which are clearly understood in the context of geologically meaningful facies associations. Two important examples of geologically-defined variability: 1) acoustically variable mudstones (‘soft' clay-rich mudstones vs. ‘hard' silt-rich muddy turbidites); and 2) reservoir quality (porosity, permeability) in clean high NtG sandstones. The development of these facies-specific results and relationships aid in the understanding of field-wide variation in reservoir properties and expected seismic response. The results can be used to enhance static reservoir model(s), and serve as the basis for developing a field-scale, facies-specific elastic properties volume amenable to dynamic (4D) production monitoring. Reservoir Characterization and Modeling of Bekasap FM for Waterflood Optimization & Field Development, Case Study Pungut Field, Central Sumatra Barkah, Rd. Rai Raya1, Gary W. Jacobs2, Jayadi H. H. Sitorus1, Sahid M. Sutanto1 (1) PT. Chevron Pacific Indonesia, Duri, Indonesia (2) Chevron International E & P, Duri, Indonesia Pungut Field is located in the CPI Rokan block, Central Sumatra Basin, approximately 60km northwest of Pekanbaru, Indonesia. The field was discovered in 1951 and to date 38 wells have been drilled. Oil is contained in the Miocene-age reservoirs of the Bekasap and Bangko Formations. Declining reservoir pressure prompted an evaluation focusing on waterflood potential. This paper/poster discusses the modeling methodology used to better understand facies distribution in the Bekasap reservoirs. This distribution controls reservoir heterogeneity and thus connectivity; an understanding of which is critical to the development of a successful waterflood. A facies-based geocelluar model was constructed using conventional cores, 3D seismic data, and petrophysical properties derived from wireline logs. Facies were modeled with MBSIS and porosity and permeability populations were co-simulated for each facies using cloud transform with sequential gaussian simulation. This model was then moved into a 3D simulator which also incorporated pressure transient analysis and injectivity test data. Various scenarios were then simulated seeking the optimal waterflood design. Compartmentalization of reservoir zones occurs in some areas of the field and oil saturation is not uniformly distributed and the simulation predicted non-uniform fluids movement. Therefore, injection/producer well pairs were selected as the best design. This method also proved the most cost effective alternative. By integrating static and dynamic data into a geocelluar model, applying simulation for scenario planning, and utilizing 3D visualization our multidisciplinary team was able to develop various alternative scenarios for waterflooding Pungut field. The project is ongoing, but results to date have been good. Ultimate oil recovery is expected to increase by 3.5% and field life may be extended as long as ten years. Remaining Oil Prediction Based on Geological Methods Changmin, Zhang1, Yin Taiju1, Zhang Shangfeng1, Wang Zhenqi1 (1) Yangtze University, Jingzhou, Hubei, China Comprehensive geological analysis as an efficacious method, is widely used to predict remaining oil in China. The effect of this method depend on the reservoir model and the detailed understanding of production of the reservoir. In the studying of Shuanghe Oil Field, Nanxiang basin,Chian, a practical process for remaining oil prediction is summarized,whichincludes the following steps: 1 founding the reservoir architectural model, 2 analyzing the developing characteristics of the reservoir based on the basic architectural elements and 3 predicting the high remaining oil distribution areas through the production analysis. Geological data base should be developed before the founding of reservoir model, in which such things as the correlation of the lithofacies and well log, the geometry character parameter are included in the geological data base. Reservoir architectural model is established based on the outcrop analysis and densely spaced well development area, and the characteristics of model are analyzed. The studying shows that there are obvious differences in the liquid and oil production, water injection and the controlled level in different architectural elements. The connecting patterns are also an important factor that influences the subsurface fluid flow. Subaqueous distributery channel sandbodies, which are always with larger scale and good properties, are poor in remaining oil; gravity flow sandbodies and over-bank sandbodies are rich in remaining oil for its smaller scale and poor properties. Small scaled mouth-bar sandbodies can also be rich in remaining oil when they are not controlled by present well-net. Sheet sand are also rich in remaining oil for its poor properties though they are always widely spread. Static and Dynamic Modeling of the Malampaya-Camago Gas-Condensate Field, offshore NW Palawan, Philippines utilising an Experimental Design Methodology Singh, Updesh1, P. Montgomery2, Arman Vahedi3, Alexandre Castellini4 (1) Chevron Australia Pty. Ltd, Perth, Australia (2) Chevron Australia Pty Ltd, Perth, Australia (3) Chevron Australia Pty., Ltd, Perth, Australia (4) ChevronTexaco Exploration and Production Technology Company, The Malampaya-Camago gas-condensate field is an Oligocene-Miocene carbonate reefal build-up situated in the South China Sea, offshore northwest Palawan Island (Philippines) in 800-1200m of water. The field has been supplying gas from 5 sub-sea production wells since October 2001 to three Gas to Power plants on Luzon Island. This paper outlines an Experimental Design (ED) geocellular modeling workflow that was employed for uncertainty analysis of the Malampaya-Camago field. The ED workflow was used to define the required suite of static and dynamic models and model parameter combinations required to fully assess the impact of reservoir uncertainties on reserves and production forecast. Simple map-base geologic and material balance models were used initially to establish a preliminary field history match. Key geologic and reservoir uncertainty parameters with ranges were identified and analysed using a Plackett-Burman (PB) ED and multiple geocellular static earth models were built as specified by the ED run table. Subsurface data used included a high resolution 3D seismic survey and nine exploration/appraisal wells with wireline and borehole image data, including spot core in selected wells, magnetic susceptibility from cuttings, almost continuous static reservoir pressure data and well test data. High resolution geologic three dimensional grids were built with 1m vertical layering and aerial grid dimension of 100m2. The geologic models were upscaled for flow simulation and history matched with production data. A genetic algorithm was utilised to optimise on the mismatch of the initial 25 geologic models with production data. This produced a selected set of acceptable models which could be evaluated in predictive runs to generate a range of production forecast. The above analysis and results are based on Chevron technical work and may not reflect operator's view. Application of Probabilistic Fault Seal Analysis in the Estimation of Reserves of the South Furious Field Sarawak Malaysia Murray, Titus1, Nick Turner2, Greg Christie3, Gill Kovack4 (1) FaultSeal Pty Ltd, Sydney, Australia (2) Sarawak Shell, Miri Sarawak, Malaysia (3) Faultseal Pty Ltd, N/A, (4) FaultSeal Pty Ltd, South Furious is a complex offshore field in Sarawak, Borneo Malaysia. It has been under production by Shell for 25 years. The hydrocarbon bearing sequence is 2500 ft thick and has 30 sands variously filled with water, oil and gas. It is structurally compartmentalised and each compartment is isolated. Lateral variation in hydrocarbon fill between blocks, pressure gradients and calculated SGR initially indicated fault seal. The field is analogous to a Rubik Cube, except there are many tilted cubes. Development is challenging, in particular the block sizes limit ultimate recovery per well. The process of predicting the distribution of oil sands and draining 1000 ft of pay from multi-layered, commingled, wells that cross-cut several compartments with the risk of depletion from adjacent producers, carries a high level of risk and uncertainty. As part of the planning for development extensions a probabilistic assessment of fault seal and breaching processes was carried out. The aim of which was explain the unusual distribution of fluids, and to predict fluids in un- drilled compartments. This study yielded a 3D probabilistic fault connectivity model of the field. The probability of each fault block being connected to another was analysed for connected volumes (clusters) and traversed using a percolation code (floating Bagatelle). The results of this work are in the process of being validated using detailed geochemical finger printing. Integrated Modeling for Brown Field Reservoir Management, Forties Field, North Sea Clare, Alan1, P.T.S. Rose2, Alistair Gray3, Alison Jagger4, Donald Keir3, Owen Vaughan5, Richard Jones6 (1) Apache Corporation, Houston, TX (2) Apache North Sea Ltd, Aberdeen, United Kingdom (3) Apache North Sea Ltd, (4) Apache Corp, Aberdeen, United Kingdom (5) Apache North Sea Ltd, Aberdeen, (6) Apache Corp, Houston, TX The keys to making mature assets give up their remaining wealth lie in the equipping of technical staff with the skills, time and tools to efficiently re-evaluate the asset. Fundamental to this is the integrating of the abstract and non-abstract - the assimilation of inherited field lore with new techniques for interpreting and managing the quantitative field data. Skills can obviously be enhanced by technology. Equipping the geoscientist with the best technology and tools to aid their analytical skills and make them more efficient is essential. Time, not only to do the everyday tasks more efficiently, but to think creatively is crucial. Workflows in the mid to late 90s to map, model and simulate fields were time consuming and the driver often spent more time under the hood than at the wheel. It permitted little time to do what the geoscientist was employed for, to think and to impart abstract creative expertise into the quantitative, simulated world. The time available to think has, supposedly, increased in direct proportion to computing power and is an area that corporate culture needs to jealously safeguard for its staff. Apache's acquisition of the Forties Field in the UK Sector of the North Sea is an example of where the integration of an inherited strong geotechnical legacy, new technology and improved computing performance within a focused working environment is enabling a mature asset to re-perform. Initial results from the modeling have been incorporated with the current seismic volumes to cross-validate in-fill targets, independently assess target volumetrics and remaining reserves and forms part of the long term field management of a mature asset.
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