Layer | Fill | Outline |
---|
Map layers
Theme | Visible | Selectable | Appearance | Zoom Range (now: 0) |
---|
Fill | Stroke |
---|---|
Collaborating Authors
Results
Summary The significant quantities of oil contained in fractured karst reservoirs in Brazilian presalt fields add new challenges to the development of upscaling procedures to reduce time on numerical simulations. This work aims to represent multiscale heterogeneities in reservoir simulators based on special connections between matrix, karst, and fracture mediums, both modeled in different grid domains within a single porosity flow model. The objective of this representation is to strike a good balance between accuracy and simulation time. Therefore, this work extends the approach of special connections developed by Correia et al. (2019) to integrate both karst and fracture mediums modeled in different grid domains and block scales. The transmissibility calculation between the three domains is a combination of the conventional formulation based on two-point flux approximation schemes and the matrix-fracture fluid transfer formulation. The flow inside each domain is governed by Darcyโs equation and implicitly solved by the simulator. For proper validation and numerical verification, we applied the methodology to a simple case (two-phase and three-phase flow) and a real case (two-phase flow). For the simple case, the reference model is a refined grid model with (1) an arrangement of large conduits (karsts), which are poorly connected; (2) a well-connected and orthogonal system of fractures; and (3) a background medium (matrix). The real case is a section of a Brazilian presalt field, characterized as a naturally fractured carbonate reservoir. The reference is the geological model. The simulation model consists of a structural model with different gridblock sizes according to the scale of the heterogeneitiesโsmall-scale karst geometries, medium-scale matrix properties, and larger-scale fracture featuresโinterconnected by special connections. The results for both cases show a significant performance improvement regarding a dynamic matching response with the reference model, within a suitable simulation time and maintaining the dynamic resolution according to the representative elementary volume of heterogeneities, without using an unstructured grid. In comparison to the reference model, for the simple case and the real case, the simulation time was reduced by 42% and 87%, respectively. The proposed method contributes to a multiscale flow simulation solution to manage heterogeneous geological scenarios using structured grids while preserving the high resolution of small-scale heterogeneities and providing a good relationship between accuracy and simulation time.
- Europe (1.00)
- North America > United States (0.93)
- South America > Brazil (0.69)
- Geology > Rock Type > Sedimentary Rock (1.00)
- Geology > Structural Geology > Tectonics > Salt Tectonics (0.55)
- 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 (0.92)
- Information Technology > Artificial Intelligence > Machine Learning (0.68)
- Information Technology > Artificial Intelligence > Representation & Reasoning (0.46)
Re-Activation of Fractured Gas Reservoir with Active Bottom Water at the Late-Stage Development: A Success Story from Weiyuan Gas Field, China
Zhang, Tao (Southwest Petroleum University) | Ma, Guowen (Southwest Petroleum University) | Ye, Haifeng (CNPC Chuanqing Drilling Engineering Co. Ltd.) | Zhou, Lisha (CNPC Chuanqing Drilling Engineering Co. Ltd.) | Zhou, Hong (PetroChina Southwest Oil & Gas field Company) | Zhao, Yulong (Southwest Petroleum University) | Zhang, Liehui (Southwest Petroleum University) | Zhang, Ruihan (Southwest Petroleum University)
Abstract It is widely recognized that economical gas production from water-drive gas reservoirs is a challenging task due to water incursion, especially for naturally fractured gas reservoirs with active bottom water. The presence of unwanted water production leads to early abandonment of these reservoirs, and their recovery factors are typically below 50%. Enhancing gas recovery has been a constant topic for petroleum engineers. In this work, a new development strategy has been presented to reactivate water-invaded gas reservoirs using a combination of horizontal and vertical wells. Around the water-breakthrough regions, horizontal wells are drilled with the target point at the original gas-water transition zone to produce the invaded water. The surrounding old vertical wells are then rescued to produce gas again. Microscale porous simulation and macroscale reservoir simulation have been conducted to reveal the re-activation mechanisms, and the successful application case in Weiyuan gas field has been analyzed in detail. Using the VOF (Volume of Fluid) calculation method and digital rocks, the invasion pathways of the bottom water up to the gas reservoir have been tracked, and quick water intrusion through the fractures has been observed. The invaded water is easily produced after drilling a horizontal well due to its large drainage area. As a result, the gas production rate of the original vertical wells (typically sited at the top of the reservoir) experiences a rise. Microscale two-phase flow behaviors are consistent with the reservoir simulation results of Weiyuan gas field, where the water saturation of the entire reservoir is significantly decreased if a horizontal well is implemented to produce water. In the gas field, 8 horizontal wells were drilled along the water-breakthrough regions during 2008-2014. The good field response indicates the strategyโs success since the original vertical wells in the near-horizontal-well region have returned to producing gas, confirming that the invaded water is produced and further water intrusion is avoided, preventing damage to the upper gas reservoirs. This proposed method offers a solution to the nearly abandoned carbonate gas reservoir, providing the possibility of further recovering the remaining gas resource. The successful application in Weiyuan gas field can serve as a valuable reference for similar types of gas reservoirs worldwide.
- Asia > China > Sichuan Province (1.00)
- North America > United States > Texas > Borden County (0.24)
- Asia > China > Xinjiang Uyghur Autonomous Region > Tarim Basin (0.99)
- Asia > China > Sichuan > Sichuan Basin > Weiyuan Field (0.99)
- Asia > China > Sichuan > Sichuan Basin > Southwest Field > Longwangmiao Formation (0.99)
- (9 more...)
- Well Drilling > Drilling Operations > Directional drilling (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...)
Application of Distance Based Generalized Sensitivity Analysis and Bayesian Inversion Method in Simulation of a Giant Fractured Carbonate Reservoir with Unstructured Grids
Fang, Junling (Tracy Energy Technologies, Hangzhou, China) | Li, Chen (China ZhenHua Oil Co.Ltd, Beijing, China) | Shi, Wen (ADNOC Onshore, Abu Dhabi, UAE) | Yang, Tao (China ZhenHua Oil Co.Ltd, Beijing, China) | Wang, Hehua (China ZhenHua Oil Co.Ltd, Beijing, China) | AL Marzooqi, Maitha (ADNOC Onshore, Abu Dhabi, UAE) | Al Ansi, Rasha (ADNOC Onshore, Abu Dhabi, UAE) | Zhang, Liang (China ZhenHua Oil Co.Ltd, Beijing, China) | Hu, Xuezhi (China ZhenHua Oil Co.Ltd, Beijing, China) | Xu, Jiafeng (China ZhenHua Oil Co.Ltd, Beijing, China) | Zhou, Shuisheng (China ZhenHua Oil Co.Ltd, Beijing, China) | Xu, Fengqiang (Tracy Energy Technologies, Hangzhou, China)
Abstract Multi-scale natural fractures bring challenges in geological modeling and flow simulation of carbonate reservoirs. History matching is extremely difficult due to significant heterogeneities and uncertainties, especially for those wells identified as "dominated by fractures". A novel, systematic approach is applied to model fractures explicitly, to perform flow simulation efficiently and eventually to match the production history accurately. First, a discrete model using unstructured triangular grids were built to fully resolve the geometry and distribution of large-scale fractures. Then the contribution of small-scale fractures was modeled using flow-based upscaling algorithms to yield enhanced porosity and permeability of matrix grid cells. Finally, the connectivity list was calculated for each pair of matrix-matrix, matrix-fracture, and fracture-fracture cells for flow simulation. Then the Distance-based Generalized Sensitivity Analysis (DGSA) method is applied to evaluate the sensitivity of the uncertain parameters in the reservoir model. Conditioning with the well production history as "given" information, the Bayesian inversion method is employed to reduce the uncertainty of fracture properties including exact position, length, and permeability etc. The entire workflow/approach was applied to a gigantic, naturally fractured reservoir with multi-billion-barrel oil reserves in Middle East. More than five hundred large-scale fractures are characterized in the simulation model explicitly using triangular prism grids. The resulted simulation model contains over 800,000 unstructured cells. It takes only one hour on a single CPU core to simulate the entire production history of over three decades for more than 100 production wells. The high simulation efficiency facilitates sensitivity analysis and history matching in which more than one thousand cases are simulated. In the meantime, due to the explicit representation of large-scale fractures, the rapid water breakthrough in some of the producers could be captured much more accurately than standard dual-porosity dual-permeability (DPDP) models. In the history matching process, the uncertainties of the sensitive parameters including most fracture and some matrix properties are systematically reduced following the Bayesian inversion method. The history-matched fracture network and matrix properties provides an accurate and efficient simulation model for future prediction and infill well optimization.
- Asia > China (0.30)
- Europe > Austria (0.28)
- Asia > Middle East > UAE > Abu Dhabi Emirate > Abu Dhabi (0.16)
- 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 > History matching (1.00)
- Information Technology > Modeling & Simulation (1.00)
- Information Technology > Artificial Intelligence > Machine Learning > Statistical Learning (0.47)
- Information Technology > Artificial Intelligence > Representation & Reasoning > Uncertainty (0.46)
- Information Technology > Artificial Intelligence > Machine Learning > Learning Graphical Models (0.46)
Sultanate of Oman Giant Fractured Carbonate Field, Fracture Model Impact on Understanding Field Connectivity from Seismic to Flow
Helmy, Mohmed (Petroleum Development Oman) | Farajzadeh, Rouhollah (Petroleum Development Oman) | Maqbali, Adnan Al (Petroleum Development Oman) | Sabahi, Mohamed (Petroleum Development Oman)
Abstract The paper presents an integrated reservoir modeling (IRM) of a giant complex fractured carbonate reservoir to get insights about the reservoir's displacement process. Historically the field has undergone many recovery mechanisms, nowadays two still remains: Gas-Oil Gravity Drainage (GOGD) and waterflood. A major change in understanding the vertical connectivity of the different reservoir units henders the future development options. A decision-based approach was followed to select an economically feasible field development option. Selection of economically feasible development option need; field performance review, full frame structure and geological model is built, ideal conceptual sector models sliced from the full frame structural model and numerical dynamic simulation is carried out with different development options (water injection (WI), gas oil gravity drainage (GOGD) and mixture of WI and GOGD). Understanding the fluid flow behavior in fractured carbonate reservoirs is complex and challenging. The complexity directly linked to the understanding of the fracture hierarchy and connectivity. The field development plan at the time of analyzing the field data was water injection with very good recovery factor that cannot be explained by the injected water pore volume. Applying the integrated reservoir modeling (IRM) procedures, full filed performance review is carried out, update of subsurface models with different fracture model realizations and run numerical dynamic simulations over idealized conceptual models with different development options. Full filed history match is carried out on the selected development option. Front Loading and data analysis is key for successful modeling strategy, the main uncertainty is the fracture distribution, better understanding of the reservoir units cross flow, understand the effect of different development options on recovery factor in significantly short time and create reasonable scenarios of subsurface. Well performance showed some effects of water injection. Gas oil gravity is the dominant recovery process. Gas recirculation of shallow wells have negative effects on the GOGD process. Adding water injectors with continuous gas injection has negative effects on the recovery factor. The fracture hierarchy is key to understand the subsurface. All the studied reservoir units are in communication via fracture corridors. The main recovery mechanism is gas oil gravity drainage (GOGD). WI may have local effects but as development concept it will not add value. Well location relative to fracture corridors is critical to achieve better history match. Water injection has negative effect on field recovery and operationally (WRFM). Filed operation optimization (optimize gas injection) can result in maintain the same rate with lower CPEX and OPEX (Capital spending efficiency). This paper presents significant importance understanding the integration and clear vision of the modeling strategy that saves effort and money.
- North America (0.93)
- Asia > Middle East > Oman (0.83)
- Geology > Geological Subdiscipline > Stratigraphy (0.68)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.47)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (0.46)
- Geology > Petroleum Play Type > Unconventional Play > Fractured Carbonate Reservoir Play (0.44)
- 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)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
The oil industry must continually and dependably meet the hydrocarbon demand as most of the easy oil is gone and future production will come from more challenging reservoirs that require complex technologies. Hydrocarbon producers must be cost-conscious, acknowledging that oil prices might not reach the high levels of the past, and as an industry ensure that oil prices do not drop significantly for long-term projects to remain sustainable. Also, in the age of ever increasing environmental scrutiny, the industry must be clever to minimize its environmental impact despite the associated added costs. To sum up these facts: In the next half a century or so, how do we maximize hydrocarbon recovery from challenging carbonate reservoirs while limiting our environmental footprint and keeping profit margins sufficiently high? In early February, porous media experts from all over the world assembled at the King Abdullah University of Science and Technology (KAUST) in Saudi Arabia for a research conference to find answers.
- Asia > Middle East > Saudi Arabia (0.25)
- North America > United States > Texas (0.17)
- Europe (0.15)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Simulation (1.00)
- (4 more...)
Reviving a Mature, Watered-Out Fractured Carbonate Reservoir: An Integrated Approach to Design a Miscible EOR Scheme for the Bigoray Field in Alberta
Rivero, Jose A. (Schlumberger) | Faskhoodi, Majid M. (Schlumberger) | Mukisa, Herman (Schlumberger) | Zaluski, Wade (Schlumberger) | Ali Lahmar, Hakima (Schlumberger) | Andjelkovic, Dragan (Schlumberger) | Xu, Cindy (Schlumberger) | Ibelegbu, Charles (Schlumberger) | Kadir, Hanatu (Schlumberger) | Sawchuk, William M. (Pulse Oil) | Pearson, Warren (Pulse Oil) | Ameuri, Raouf (Schlumberger) | Gurpinar, Omer (Schlumberger)
Abstract The Bigoray area of the Pembina field in western Alberta consists of approximately 50 naturally fractured Nisku carbonate reefs. Production from the Bigoray Nisku D and E pools started in 1978, and shortly after, water injection was initiated to maintain reservoir pressure as a secondary drive mechanism. By 2013, the pools had reached high water cuts, making them uneconomical to produce. In 2017, a decision was made to reactivate the pools and initiate a solvent injection enhanced oil recovery (EOR) project feasibility assessment. A multidisciplinary team was assembled to review and reinterpret all the geoscience data with modern methodologies to characterize the reservoirs and create new static model descriptions to be used in a dynamic model. Data from well logs, seismic, core measurements, and image logs were integrated into a comprehensive and consistent model that could be used with certainty as a prediction tool. A history-matching process was carried out by creating different realizations of the static model to honor well-to-well connectivity and water movement within the pools. The history-matching process was performed while ensuring that the model updates were global in nature and consistent with the geological understanding of the reservoirs. The history-matched model was used to optimize the location of new producers and injectors based on remaining oil saturations and reservoir structure. Optimization of the EOR scheme involved testing a matrix of scenarios to investigate the effect of injection rates and solvent volumes as well as production pressures and voidage ratios. Additionally, in an effort to improve displacement efficiency, a large number of simulation runs were devoted to test and establish the most efficient locations for the well perforations in both the new injectors and producers.
- North America > Canada > Alberta > Yellowhead County (0.84)
- North America > Canada > Alberta > Parkland County (0.70)
- Geology > Sedimentary Geology > Depositional Environment > Marine Environment > Reef Environment (0.54)
- Geology > Geological Subdiscipline (0.47)
- Geology > Petroleum Play Type > Unconventional Play > Fractured Carbonate Reservoir Play (0.40)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (0.34)
- Geophysics > Seismic Surveying (1.00)
- Geophysics > Borehole Geophysics (0.89)
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Alberta Basin > Deep Basin > Pembina Field > Viking Formation (0.99)
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Alberta Basin > Deep Basin > Pembina Field > Cardium Formation (0.99)
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Alberta Basin > Deep Basin > Brazeau River Field (0.99)
- (3 more...)
- 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 > History matching (1.00)
- (6 more...)
Fully Implicit Reservoir Simulation Using Mimetic Finite Difference Method in Fractured Carbonate Reservoirs
Zhang, Na (Division of Sustainable Development, College of Science and Engineering, Hamad Bin Khalifa University) | Abushaikha, Ahmad Sami (Division of Sustainable Development, College of Science and Engineering, Hamad Bin Khalifa University)
Abstract A fully-implict mimetic finite difference method (MFD) for fractured carbonatereservoir simulation is presented. MFD, as a novel discritization, has been applied to many fields due to its local conservativeness and applicability of any shape of polygon. Here we extend it to fractured reservoirs. Our scheme is based on MFD method and discrete fracture model (DFM). This scheme supports general polyhedral meshes, which gives an advantage for reservoir simulation application. The principle of the MFD method and the corresponding numerical formula for discrete fracture model are described in details. In order to assure flux conservation, fully implicit method is employed. We test our method through some examples to show the accuracy and robustness.
- 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)
Beyond One-Dimensional Evaluations: The Search for Genetic Reservoir Regions through Time & Space
Hadidi, Shahab (Petroleum Development Oman) | Yaarubi, Hilal (Petroleum Development Oman) | Baaske, Uwe (Petroleum Development Oman) | Suwannathatsa, Sakharin (Petroleum Development Oman) | Farsi, Shadia (Petroleum Development Oman) | Bazalgette, Loic (Petroleum Development Oman) | Hamdoun, Lana (Petroleum Development Oman)
Abstract The infill potential of one of the most complex fractured carbonate reservoirs in the Sultanate of Oman has been evaluated through the integration, visualization and analysis of different data sources. The field has been split into different simplified genetic geobodies which contain the culmination of facies changes that define rock quality, fluid fill, oil saturation distribution and fracture network, amongst other properties that affect fluid flow. The long production history of more than 45 years, along with the large number of logged long horizontal wells scattered around the field, were key enabler for the analytical methodology. Production data, coupled with resistivity logs in horizontal wells, viewed through time were the backbone of the analysis. Data analysis was achieved by combining these data in a single platform and performing the analysis at different slices of time. At each timeslice, different interpretations were inferred that explain the observed production behaviour and remaining oil saturation from the logged wells. The interpretations were narrowed down into a minimum number of realizations by combining interpretations from the same area gathered from different slices of time. The analysis has resulted in the identification of four genetic performance regions in the field. Each region approximates a primary depositional facies belt and has a general defined relative behaviour of initial wells potential, water-cut development, initial and remaining oil saturation and, most importantly, infill wells potential. The analysis has aided in narrowing the subsurface uncertainties and has given a promising explanation for the large variations in wells behaviour. Infill wells opportunities have been identified, selected and ranked relatively in each of the regions. The value of data analytics on large volumes of acquired information normally not used was demonstrated. Visualization of different data sources in one platform is a challenging task that usually stops engineers from experimenting. The team has found fit for purpose solutions to visualize different data sources through time. The shift of mind-set from uncertain complex models and evaluations into finding simple genetic performance regions of the reservoir was vital in unravelling infill potential.
- 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)
- (4 more...)
Driving Reservoir Modelling Beyond the Limits for a Giant Fractured Carbonate Field - Solving the Puzzle
Spagnuolo, M.. (Eni S.p.A.) | Scalise, F.. (Eni S.p.A.) | Leoni, G.. (Eni S.p.A.) | Bigoni, F.. (Eni S.p.A.) | Contento, F. M. (Eni S.p.A.) | Diatto, P.. (Eni S.p.A.) | Francesconi, A.. (Eni S.p.A.) | Cominelli, A.. (Eni S.p.A.) | Osculati, L.. (Eni S.p.A.)
Abstract In this work, we address the challenge of modelling a complex, carbonate reservoir, where the fractures network, connected throughout a complex fault framework, represents large part of both the storage and the flow capacity of the system. The asset is a giant, onshore field, developed since the 90's by primary depletion through several horizontal wells, targeting anomalous fluid columns. Different culminations are characterized by specific production drive mechanisms. The objective is to integrate an impressive amount of data into a digital model, suitable to understand fluid flow behavior and support decision. The field is challenging in every geological and dynamic feature. The reservoir complexity ranges from the intricate structural framework (several hundreds of reverse faults), to the puzzling fractures network at different scales, to the unclear role of the low-porosity rock matrix, to the heterogeneous distribution - both laterally and vertically - of fluid properties, related to different combinations of hydrocarbon and acid components. The workflow is based on the adoption of Volume Based Modelling (VBM) to account for seismic faults. Then, large-scale fractures are modelled using a blend of stochastic and deterministic Discrete Fracture Networks (DFNs), while background fractures (BGF) are characterized using a Continuous Fracture Modeling (CFM) formulation. A Dual Porosity - Dual Permeability (DPDK) approach is then implemented for reservoir simulation. The model is finally reconciled with the production data by iterating between geology and simulated dynamic response. The whole modeling and simulation workflow, from static to dynamic model definition, is developed relying on company's top-class computational resources. The DPDK formulation, where DFN is the second medium while the first medium consists of BGF and rock matrix, allows us to simulate the main production mechanism: large-scale discontinuities โ DFN โ are withdrawal first, and then fluid is recharged by smaller scale features. Besides, the history matching phase, together with accurate production and Pressure-Volume-Temperature (PVT) data analysis, sheds light on the extreme heterogeneity of the field. Petrophysical properties, storage and effective apertures of discontinuities are calibrated according to the production history, and integrated into a comprehensive understanding of the reservoir. Eventually, we reveal how a robust history matched model may be used as a powerful tool to understand the impact of all the involved criticalities on the subsurface fluid behavior and movement in a complex fractured carbonate setting. The challenges addressed in this work provide relevant best practices for carbonate reservoir modelling, in particular highlighting the role of the integration between geology and reservoir engineering to minimize subsurface uncertainties. Furthermore, the PVT model developed in this study proposes new migration scenarios to explain the sour gas distribution. Finally, optimized procedures to tackle numerical criticalities using advanced reservoir simulators are disclosed.
- North America > United States (0.46)
- Asia > Middle East > UAE (0.28)
- Geology > Geological Subdiscipline > Geomechanics (0.94)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (0.68)
- Geology > Structural Geology > Fault > Dip-Slip Fault > Reverse Fault (0.34)
- Geophysics > Seismic Surveying (0.90)
- Geophysics > Borehole Geophysics (0.69)
- 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 > History matching (1.00)
- (3 more...)
Summary Field-scale simulations of complex processes often suffer from long simulation times. One of the main reasons is that the Newton-Raphson (NR) process used to solve each simulation timestep requires many iterations and small timestep sizes to converge. Because the selection of solution variables affects the nonlinearity of the equations, it is attractive to have a practical method to rapidly explore the use of alternative primary variables in general-purpose reservoir simulators. Many reservoir simulators use pressure, saturations, and temperature in each gridblock as the primary solution variables, which are referred to as natural variables. There is also a class of reservoir simulators that uses pressure, total component masses (or moles), and internal energy in each gridblock as primary variables. These simulators are referred to as mass-variable-based reservoir simulators. For a given choice of primary variables, most simulators have dedicated, highly optimized procedures to compute the required derivatives and chain rules required to build the Jacobian matrix. Hence, it is usually not possible to switch between mass and natural variables. In this work, however, we establish a link at the numerical-solution level between natural- and mass-variable formulations and design a novel (nonlinear) block-local method that transforms mass-variable shifts (computed at each NR iteration) into equivalent natural-variable shifts. We demonstrate on a number of simulation models of varying complexity that by use of the proposed approach, a mass-variable-based flow simulator can still effectively use natural variables, where the change of variables can be made locally per gridblock. Results indicate that in some models the total number of NR iterations, linear-solver (LS) iterations, and timestep-size cuts (caused by the nonconvergence of the NR procedure, also known as backups) are reduced when using natural variables instead of mass variables. However, the improvement is relatively modest and not generally observed. Our findings also signify that depending on the specific characteristics of the simulation problem at hand, mass-variable-based simulators may perform comparably or outperform natural-variable-based simulators. The proposed variable-switching method can be used effectively to evaluate the effect of using different primary solution variables on problem nonlinearity and solver efficiency. With this method, the effect of interchanging primary solution variables on problem nonlinearity can be rapidly evaluated.
- Europe (0.92)
- North America > United States > Texas (0.46)
- Geology > Geological Subdiscipline (0.67)
- Geology > Petroleum Play Type > Unconventional Play (0.46)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Thermal methods (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Fluid modeling, equations of state (1.00)
- (6 more...)