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Results
Abstract To borrow from Shakespeare, fractures are the โundiscovered countryโ of reservoir modeling. Despite decades of research and the application of sophisticated tools and processes, building a model of a naturally fractured reservoir (NFR) that reliably predicts key aspects of reservoir performance often proves to be an elusive and costly goal. Some of the reasons for disappointing NFR modeling resultsโsystem complexity, paucity of data, and software/computing limitationsโare often beyond our control. Other reasons we bring on ourselves. These include a reluctance to use modeling early in the process to aid and guide reservoir characterization, and an adherence to high levels of precision despite great uncertainty. In this example from early development of a large carbonate reservoir, a concerted effort was made to design and apply a workflow that stresses integration, visualization, ease-of-use, flexibility, and speed. The high degree of uncertainty and long characterization times typical of NFRs are addressed by promoting early investigation of parameters impacting both volumes and fluid flow. A key component is to quickly test concepts to identify irreducible uncertainty and avoid unnecessary work. The workflow relies on sector models that are copied directly from the full-field model and are representative of large regions of the field, primarily with respect to degree and distribution of cements and solution-enlarged fractures. Discrete fracture networks (DFNs) are built within the sectors for various concept scenarios and converted to effective properties using flow-based scale averaging. Fracture intensity is used as the โbridgingโ property between sector and full-field models, and to facilitate calibration to pressure-transient-test estimates of permeability-thickness. Permeability continuity is estimated using experimental variograms derived from the scaled-up properties. Simulation-ready models take only a few weeks to complete and can quickly alter assumptions on parameters such as fracture distribution and porosity.
- Asia (1.00)
- North America > United States > California (0.28)
- Geology > Geological Subdiscipline > Stratigraphy (0.68)
- Geology > Geological Subdiscipline > Geomechanics (0.52)
- Asia > Kazakhstan > Mangystau Oblast > Precaspian Basin > Tengiz Field > Tengiz Formation (0.99)
- Asia > Kazakhstan > Mangystau Oblast > Precaspian Basin > Tengiz Field > Korolev Formation (0.99)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Sun Field (0.93)
- North America > United States > Michigan > Michigan Basin > Bentley Field > Dundee Limestone Formation (0.93)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Carbonate reservoirs (1.00)
- (3 more...)
Moving an Economically Marginal Project into a Major Project through Integrating Subsurface Uncertainty and Surface Design
Kawar, Ra'ed (Petroleum Development Oman) | Ferrero, Maria Boya (Petroleum Development Oman) | Al Wahabi, Nasr (Petroleum Development Oman) | Koksaloglu, Bengisu (Petroleum Development Oman) | Khabouri, Khalid (Petroleum Development Oman)
Abstract The X field is located in The Sultanate of Oman. It consists of stacked fractured carbonate reservoirs with Natih and Shuaiba Formations. Historically the field has been studied and stalled over the years (1999, 2005 and 2008). Making an integrated development plan for the X field is considered as challenging for the following reasons: 1) we are dealing with three different reservoirs at the same location; 2) the field has sparse datasets for the different reservoirs; 3) fractures properties differ within reservoirs; 4) the three reservoirs contain different hydrocarbon types; 5) The development is targeting relatively short transition zone hydrocarbon columns; 6) fluid contacts are highly variable and non flat; 7) the oil in the shallow reservoir is biodegraded and the gs oil contact does not match the oil the bubble point pressure; 8) the field is producing at high H2S level. As a consequence of the above the field development is confronted with a wide range of uncertainties in the production forecasts (between low and high cases). Surface design having to accommodate such large ranges in the production forecast translates into a project that is economically unattractive. To unlock the X field resource volume, a two-fold strategy was adopted: Big Loop and Decision Driven Modelling, and Concept engineering designing the cost while maintaining the project key value drivers. The Big Loop methodology enabler can be defined as the process of describing reservoirs conceptually to explore through modelling the uncertainties impacting major decisions. It results in exploring the subsurface unknowns in the decision space without anchoring to a base case. The Big Loop has resulted in the identification of the most relevant uncertainties in X field which led to drilling five appraisal wells and four well interference campaigns in 2012-2013. The appraisal results have proven GOGD as the most favourable recovery mechanism for the two deeper reservoirs; for the shallower reservoir uncertainty remains too large and the recommendation for an early production system in combination of a surveillance plan is proposed. Optimisation of the compressor size has been key to unlock the economic feasibility of this development. It has lead to the definition of the maximum affordable capacity and the operating envelope for production phasing. In conclusion the integration with surface design has driven the cost, and the Big Loop methodology has enabled the identification of appraisal needs and the optimum development mechanism. The combination of surface design for the three reservoirs and subsurface uncertainty screening has resulted in an economically feasible and robust project.
- Geophysics > Seismic Surveying (0.69)
- Geophysics > Borehole Geophysics (0.46)
- Asia > Middle East > Oman > Thamama Group > Shu'aiba Formation (0.96)
- Asia > Middle East > Oman > Ad Dhahirah Governorate > Fahud Salt Basin > Natih Field (0.89)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Carbonate reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- (5 more...)
Abstract The oil industry is developing more and more complex reservoirs, often lying in difficult environments like deep or ultra-deep water. At the same time, brown fields are systematically studied to implement IOR and EOR processes to increase the ultimate recovery factor. In this context one of the challenges is to simulate highly detailed models and provide robust answers for corporate decision making processes. Because conventional reservoir simulators are not very well suited for these purposes, new generation reservoir simulators are tempting solutions. During recent years eni is implementing a step-change in the way reservoirs are modeled and simulated, deploying a new generation, high resolution simulator for the most critical and complex assets. The purpose is twofold: computational efficiency on one side and enabling the development of more accurate models on the other one. The process is run in a selective manner, aimed at identifying opportunities when conventional simulators do not meet expectations. In this paper we present the methodology used by the Company in the selection of field cases, together with the results achieved for some of the most interesting and complex assets. In particular, comparative results, with respect to conventional simulators, are presented for: deep-water reservoirs, a tight oil development, CO2 injection schemes, and a large scale heavy oil project. The analysis is performed using key computational and engineering performance indicators. The deployment is run in cooperation with the technology provider: cases, logic, issues and solutions are discussed together in a critical manner. The process is run on the basis of long term corporate objectives, targeting the simulation of EOR processes and complex assets in a computationally efficient and accurate manner.
- North America > United States (0.68)
- Europe > United Kingdom > North Sea (0.48)
- North America > Trinidad and Tobago > Trinidad > North Atlantic Ocean > Columbus Basin > Galeota Block > Mango Field (0.99)
- Europe > United Kingdom > North Sea > Northern North Sea > East Shetland Basin > North Viking Graben > Block 211/26a > Cormorant Field > Etive Formation (0.99)
- Europe > United Kingdom > North Sea > Northern North Sea > East Shetland Basin > North Viking Graben > Block 211/26a > Cormorant Field > Brent Group Formation (0.99)
- (2 more...)
- Reservoir Description and Dynamics > Reservoir Simulation > Scaling methods (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (0.95)
- Reservoir Description and Dynamics > Reservoir Characterization > Geologic modeling (0.94)
- (7 more...)
Abstract The Tengiz field is a giant naturally fractured carbonate reservoir with 44ยฐ API oil and 12% H2S content. This work presents a methodology to construct a sector model for the Tengiz field which is used to evaluate IOR/EOR processes to increase oil recovery through the life of the field. Current development plans call for expansion of sour gas injection in the platform area of Tengiz. Additional long term focus is now directed towards the fractured slope region of the field. IOR/EOR is a natural alternative to supplement reservoir energy, improve recovery efficiency, and convert resources to reserves, then to production. Reservoir simulation requires using a dual porosity dual permeability model and equation of state to model PVT properties. Unlike most published sector models which are usually limited to a section of 5-spot pattern, this sector model covers 1/6 of the field area and is complicated by natural fractures, plant capacity limitations, complex production rules, existing sour gas injection, and high well count. This work presents a method to treat plant capacity limitations, boundary flux, edge wells, and compositional effects to replicate full field model performance and subsequently to generate alternative predictions. This model matches production/injection data of existing wells and the anticipated performance of future wells in the full field model. Matching parameters include oil production rate, GOR, flowing bottom-hole-pressure (BHP), saturation profile, and reservoir pressure profile at the field and well level. The BHP at all future development well locations are also matched. The sector model was also used to determine optimal well count of infill producer. The methodology to do so is discussed in this work as well. The on-going work and forward plan focus on evaluating the concentration profile of all injectants, impact of injection rate, gas production management, new development well locations, and interference among all wells. The success of sector model enables Tengizchevroil to run numerous IOR scenarios in a much shorter time frame so that only those prioritized runs can be evaluated on a full-field basis.
- Geology > Geological Subdiscipline (0.46)
- Geology > Petroleum Play Type (0.34)
- Asia > Kazakhstan > Mangystau Oblast > Precaspian Basin > Tengiz Field > Tengiz Formation (0.99)
- Asia > Kazakhstan > Mangystau Oblast > Precaspian Basin > Tengiz Field > Korolev Formation (0.99)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Carbonate reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- (3 more...)
Abstract This field case present a risk analysis on production, plateau duration and ultimate recovery factor performed on a fractured carbonate reservoir. The field has been under early production for more than 48 years, with less than 2% cumulative produced Oil. Historical data measurements on Well Production Oil Rate, Well Gas Oil Ratio (GOR), Well Static Pressure and Well Bottom Hole Flowing Pressure have been utilized in order to constrain uncertain parameters during historical period and then propagate into prediction. The risk analysis takes into account reservoir uncertainties and geological uncertainties on Discrete Fracture Network (DFN). Several surface/controllable parameters have been considered for the Risk analysis evaluation on Plateau Length hypothesis and Recovery Factor. The risk analysis accounts for two main recovery mechanisms: gas injection from the crest for Gas gravity drainage and periphery down dip water injection with imbibition. Several scenarios of DFN's and 43 uncertain reservoir parameters with probability distribution were considered. Experimental Design and Response Surface Methodology have been extensively applied to minimize the number of Reservoir simulation runs of the study. Plackett and Burman Experimental Design has been used for the Screening Phase. During the screening phase, it has been revealed that 7 uncertain parameters account for more than 80 % of the total variation of Cumulative Oil Production. A detailed Latin Hypercube has been performed with 3 discrete fracture network, controllable uncertain parameters and these 7 most relevant parameters. This risk analysis identified the best cases of each phase of the development, P10 and P90, and the major uncertainties impacting the field development plan. Mitigation, acquisition and monitoring plan have been defined accordingly to reduce the major impacting uncertainties.
- Europe (0.94)
- Africa (0.94)
- Asia > Middle East > UAE > Abu Dhabi Emirate > Abu Dhabi (0.51)
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.34)
- Asia > Middle East > UAE > Abu Dhabi > Arabian Gulf > Rub' al Khali Basin > Abu Dhabi Field (0.99)
- Africa > Middle East > Algeria > Central Algeria > Ahnet-Timimoun Basin > Sbaa Basin (0.99)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Carbonate reservoirs (1.00)
- (8 more...)
Summary Carbonate fractured reservoirs introduce a tremendous challenge to the upscaling of both single- and multiphase flow. The complexity comes from both heterogeneous matrix and fracture systems in which the separation of scales is very difficult. The mathematical upscaling techniques, derived from representative elementary volume (REV), must therefore be replaced by a more realistic geology-based approach. In the case of multiphase flow, an evaluation of the main forces acting during oil recovery must also be performed. A matrix-sector model from a highly heterogeneous carbonate reservoir is linked to different fracture realizations in dual-continuum simulations. An integrated iterative workflow between the geology-based static modeling and the dynamic simulations is used to investigate the effect of fracture heterogeneity on multiphase fluid flow. Heterogeneities at various scales (i.e., diffuse fractures and subseismic faults) are considered. The diffuse-fracture model is built on the basis of facies and porosity from the matrix model together with core data, image-log data, and data from outcrop-analogs. Because of poor seismic data, the subseismic-fault model is mainly conceptual and is based on the analysis of outcrop-analog data. Fluid-flow simulations are run for both single-phase and multiphase flow and gas and water injections. A better understanding of fractured-reservoirs behavior is achieved by incorporating realistic fracture heterogeneity into the geological model and analyzing the dynamic impact of fractures at various scales. In the case of diffuse fractures, the heterogeneity effect can be captured in the upscaled model. The subseismic faults, however, must be explicitly represented, unless the sigma (shape) factor is included in the upscaling process. A local grid-refinement approach is applied to demonstrate explicit fractures in large-scale simulation grids. This study provides guidelines on how to effectively scale up a heterogeneous fracture model and still capture the heterogeneous flow behavior.
- Europe (1.00)
- Asia > Middle East (0.94)
- North America (0.67)
- Geology > Structural Geology > Fault (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Structural Geology > Tectonics > Compressional Tectonics > Fold and Thrust Belt (0.94)
- (3 more...)
- Oceania > New Zealand > North Island > Taranaki Basin (0.99)
- North America > United States > California > Monterey Formation (0.99)
- Europe > Italy > Fucino Basin (0.99)
- (2 more...)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Carbonate reservoirs (1.00)
- (5 more...)
Integration of Pressure Transient Data in Modeling Tengiz Field, Kazakhstan โ A New Way to Characterize Fractured Reservoirs
Pan, Yan (Chevron) | Hui, Mun-Hong (Chevron) | Narr, Wayne (Chevron) | King, Gregory (Tengizchevroil) | Tankersley, Terrell H. (Tengizchevroil) | Jenkins, Steve D. (Tengizchevroil) | Flodin, Eric A. (Tengizchevroil) | Bateman, Philip W. (Tengizchevroil) | Laidlaw, Chris (Tengizchevroil) | Vo, Hai Xuan (Stanford University)
Abstract Tengiz is a supergiant oil field with 30 billion STBOOIP located in the Pricaspian basin of western Kazakhstan. The field produces from an isolated carbonate platform of Devonian to Pennsylvanian age, with a flat-lying central platform surrounded by a relatively steep depositional slope. Fractures are common and significantly enhance productivity in the outer platform and slope. Understanding the flow behavior of the matrix-fracture system is a key to successful field development. The characterization of naturally fractured reservoirs is especially challenging due to a high degree of heterogeneity and uncertainty. When modeling carbonate reservoirs โ and particularly those where fractures play a significant role โ we lack a consistent and robust methodology for utilizing dynamic data collected from pressure buildup tests, production logging, pulse tests between wells, and from increasingly deployed permanent down-hole gauges. Instead, this data, which contain rich information about wells and reservoir, is often neglected in the conventional production history matching. This project aims to fill this technology gap to better characterize fractured carbonate reservoirs. We apply numerical well testing techniques with discrete fracture modeling to understand and characterize the fracture-matrix properties. The effective utilization of pressure transient data should narrow the uncertainty, improve the characterization, and help optimize field development. First the numerical solutions from both Discrete Fracture Models (DFM) and Dual-Porosity Models using numerical reservoir simulator were validated against analytical pressure-transient solutions for a dual-porosity system. Next a systematic workflow to integrate single-well buildup test data into numerical models was developed based on synthetic case study results. Finally the new method was applied successfully to a sector model of Tengiz field. Some preliminary techniques were also developed to honor pulse test data and analysis results between wells with numerical simulation models. Continuous efforts are being made to improve field-scale reservoir simulation models using dynamic and static data of fracture-matrix systems for more accurate field performance forecast in Tengiz. The successful integration of all types of data would have a big impact on reservoir management by potentially minimizing the number of wells to be drilled, maximizing the production from each well, and substantially increasing reserves.
- North America > United States > California (0.93)
- Asia > Kazakhstan > Mangystau Region (0.85)
- North America > United States > Mississippi > Marion County (0.24)
- North America > United States > Oklahoma > Anadarko Basin > M Formation (0.99)
- Europe > United Kingdom > North Sea > Central North Sea > Central Graben > Block 23/26a > Eastern Trough Area Project > Machar Field (0.99)
- Asia > Kazakhstan > Mangystau Oblast > Precaspian Basin > Tengiz Field > Tengiz Formation (0.99)
- Asia > Kazakhstan > Mangystau Oblast > Precaspian Basin > Tengiz Field > Korolev Formation (0.99)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Carbonate reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- (2 more...)
Techniques for Effective Simulation, Optimization, and Uncertainty Quantification of the In-situ Upgrading Process
Alpak, Faruk O. (Shell International Exploration and Production Inc.) | Vink, Jeroen C. (Shell International Exploration and Production Inc.) | Gao, Guohua (Shell International Exploration and Production Inc.) | Mo, Weijian (Shell International Exploration and Production Inc.)
Abstract Strongly temperature-dependent compositional flow and transport, chemical reactions, delivery of energy into the subsurface through downhole heaters, and complex natural fracture architecture render the dynamic modeling of In-situ Upgrading Process (IUP) a computationally challenging endeavor for carbonate extra-heavy oil resources. Economic performance indicators for such recovery methods can be considerably enhanced via simulation or simulation-based proxy models within an optimization framework (e.g., maximizing Net Present Value through achieving an optimal compromise between hydrocarbon recovery and the number of heater wells). The IUP is endowed with uncertain subsurface parameters as in the case of other recovery mechanisms. The number of subsurface uncertainties is especially large and the impacts of these uncertainties are intricate when IUP is applied to a complex naturally-fractured carbonate reservoir. Simulation results must reflect the impacts of these uncertainties; hence they should always deliver "expected-value production functions" and their attached uncertainty ranges, in short, the "error bars". Both the optimization and the uncertainty quantification workflows require (typically multiple) multi-scenario simulations, and are therefore very compute intensive. We describe our recent developments in simulation techniques, optimization algorithms, tool capabilities, and high-performance computing protocols that in unison form a massively parallel simulation/optimization/uncertainty-quantification workflow, in which it is almost equally easy to produce recovery time-functions with an attached uncertainty range, as it is to run a single simulation. Uncertainties are integral part of the simulation models in our dynamic modeling workflow. Our in-house simulation platform supports various optimization and uncertainty quantification methods, such as conventional as well as robust optimization using a novel Simultaneous Perturbation and Multivariate Interpolation technique, Experimental Design, and Monte Carlo simulation, that can be linked together through a unified script-based interface, to carry out optimization in the presence of subsurface uncertainties and to quantify the impact of these uncertainties on simulation results. Application of our massively parallel dynamic modeling workflow is illustrated on a proprietary IUP recovery method for a complex naturally fractured extra-heavy oil (bitumen) reservoir as example. After briefly explaining these recovery processes and the modeling approach, we show the techniques (including their accompanying application results) that (1) notably accelerate the (single-model) simulation process, (2) effectively identify the predominant subsurface uncertainties, (3) rapidly optimize heater-producer patterns under the influence of predominant subsurface uncertainties, and (4) efficiently compute expected-value production functions with error bars.
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Oil sand, oil shale, bitumen (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Carbonate reservoirs (1.00)
- (2 more...)
- Information Technology > Modeling & Simulation (1.00)
- Information Technology > Artificial Intelligence > Representation & Reasoning > Optimization (1.00)
Abstract The need to develop new tools that allow reservoir engineers to optimize reservoir performance is becoming more demanding by the day. One of the most challenging and influential problems facing reservoir engineers is well placement optimization. The North Kuwait field (NKF) consists of six fields containing four naturally fractured carbonate formations. The reservoirs are composed of relatively tight limestone and dolomite embedded with anhydrate and shale. The fields are divided into isolated compartments based on fault zones and supported by a combination of different fluid compositions, initial pressures, and estimated free-water levels. Due to natural complexity, tightness, and high drilling costs of wells in the NKF, it is very important to identify the sweet spots and the optimum well locations. This paper presents two intelligent methods that use dynamic numerical simulation model results and static reservoir properties to identify zones with a high-production potential: reservoir opportunity index (ROI) and simulation opportunity index (SOI). The Petrel* E&P software platform was chosen as the integrated platform to implement the workflow. The fit-for-purpose time dependent 2D maps generated by the Petrel platform facilitated the decision-making process used for locating new wells in the dominant flow system and provided immense support for field-development plans. The difference between the two methods is insignificant because of reservoir tightness, limited interference, and natural uncertainty on compartmentalization. At this stage, pressure is not a key parameter. As a result, unlike brown fields, less weight was given to simulated pressure, and SOI was used to select the well locations. The results of this study show that implementing these workflows and obtaining the resulting maps significantly improve the selection process to identify the most productive areas and layers in a field. Also, the optimum numbers of wells using this method obtained in less time and with fewer resources are compared with results using traditional industry approaches.
- Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > North Kuwait Jurassic (NKJ) Fields > Marrat Formation > Upper Marrat Formation (0.98)
- Asia > Middle East > Kuwait > Jahra Governorate > Arabian Basin > Widyan Basin > North Kuwait Jurassic (NKJ) Fields > Marrat Formation > Sargelu Formation (0.98)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Carbonate reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- (2 more...)
- Information Technology > Modeling & Simulation (0.87)
- Information Technology > Mathematics of Computing (0.61)
Abstract This paper describes the workflow used to assess modeling the impact of fractures (and faults) on the dynamic performance of a Lower Cretaceous reservoir located offshore Abu Dhabi. The reservoir is not highly fractured and the modeling challenge is to identify a practical method to incorporate their impact in a geologic and simulation model. The work plans developed to address these issues consist of four elements of a conceptual fault and fracture model - these are: two groups of diffuse fractures in specified layers; seismic scale faults; and fracture corridors. This paper focuses on learnings from the study of the first two elements of the developed work plans - i.e., modeling the impact of diffuse fractures on water movement. The workflow began by modelling diffuse fractures at mini-sector scale (single geo-model grid-cell with layers and properties). Fracture parameters have been defined for low-side, most likely and high-side cases based on core data from 80 wells. By preparation of discrete fracture network (DFN) models for these cases and calibration to well test permeability, we are able to define a permissible range of fracture parameter values; and also to define the sensitivity of each fracture parameter. Dual media mini-sector simulation models are then used to compare water breakthrough time and evolution for different DFN models. The mini-sector models are also used to estimate the range of possible behaviours given the uncertainty in fracture data and other key factors like matrix-fracture transfer. The results of this modeling work were used to formulate plans and recommendations for full-field modeling. A key conclusion derived from this study was that an effective single medium model would be adequate for full-field modeling of the subject reservoir. Work on the effective single medium full-field model is currently underway and the results-to-date are promising in terms of modeling reservoir behavior.
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (0.93)
- Geology > Structural Geology > Fault (0.76)
- Geology > Geological Subdiscipline (0.68)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Carbonate reservoirs (1.00)
- (3 more...)