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Collaborating Authors
Hydraulic Fracturing
A Novel Approach To Detect Interacting Behavior Between Hydraulic Fracture and Natural Fracture by Use of Semianalytical Pressure-Transient Model
Xiao, Cong (China University of Petroleum, Beijing) | Tian, Leng (China University of Petroleum, Beijing) | Zhang, Yayun (China University of Petroleum, Beijing) | Hou, Tengfei (China University of Petroleum, Beijing) | Yang, Yaokun (China University of Petroleum, Beijing) | Deng, Ya (China National Petroleum Corporation) | Wang, Yanchen (Shengli Oilfield Service Corporation) | Chen, Sheng (China National Petroleum Corporation)
Summary The detection of interacting behavior between the hydraulic fracture (HF) and the natural fracture (NF) is of significance to accurately and efficiently characterize an underground complex-fracture system induced by hydraulic-fracturing technology. This work develops a semianalytical pressure-transient model in the Laplace domain to detect interacting behavior between HF and NF depending on pressure-transient characteristics. Our results have shown that no matter what the flow state (compressible or incompressible flow) within a hydraulically induced fracture system, we can easily detect interacting behavior between HF and NF depending on whether the "dip" shape occurs at the formation radial-flow regime. Referring to sensitivity analysis, distance between NF and well, horizontal distance between NF and HF, and NF length are the three most sensitive factors to detect fracture-interacting behavior. Depending on interference analysis, although the pressure-transient characteristics of a pseudosteady-state dual-porosity model can interfere with our proposed methodology, the difference between our model and a pseudosteady-state dual-porosity system lies in whether the value of the horizontal line of dimensionless pressure derivative is equal to 0.5 at the formation radial-flow regime. Our work obtains some innovative insights into detecting fracture-interacting behavior, and the valuable results can provide significant guidance for refracturing operations and fracture detection in an underground fracture system. Introduction The seepage behavior in a naturally fractured reservoir (NFR) has been extensively investigated because of its importance in safe storage facilities for captured carbon dioxide and geothermal and petroleum resource recovery. For some special underground fracture systems, including tight reservoir and shale reservoir, because of extremely low permeability and porosity values, hydraulic-fracturing stimulation has become an integral technology for their effective development. Not only can hydraulic-fracturing technology create several high-conductivity HFs as flow paths, but can also activate and connect pre-existing NFs to form a spatially complex fracture network (Mayerhofer et al. 2006; Ozkan et al. 2011; Stalgorova and Mattar 2012, 2013; Clarkson 2013; Sierra and Mayerhofer 2014). It is universally acknowledged that the complexity of the resulting HF network is caused by the interacting behavior between HFs and NFs. Some of these studies concentrate on the mechanical interaction when HFs encounter pre-existing NFs, and corresponding criteria to predict whether HFs will propagate across a randomly frictional interface were developed. These criteria are derived from the linear-elastic fracture-mechanics solution for the stresses near the fracture tip, and the criteria were validated by laboratory experiments.
- Asia > China (0.95)
- North America > United States > Texas (0.68)
- Geology > Geological Subdiscipline > Geomechanics (0.46)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.34)
- North America > United States > Texas > Fort Worth Basin > Barnett Shale Formation (0.99)
- Asia > China > Shandong > North China Basin > Shengli Field (0.99)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
A Semianalytical Approach To Model Two-Phase Flowback of Shale-Gas Wells With Complex-Fracture-Network Geometries
Yang, Ruiyue (China University of Petroleum, Beijing) | Huang, Zhongwei (China University of Petroleum, Beijing) | Li, Gensheng (China University of Petroleum, Beijing) | Yu, Wei (Texas A&M University) | Sepehrnoori, Kamy (University of Texas at Austin) | Lashgari, Hamid R. (University of Texas at Austin) | Tian, Shouceng (China University of Petroleum, Beijing) | Song, Xianzhi (China University of Petroleum, Beijing) | Sheng, Mao (China University of Petroleum, Beijing)
Summary Two-phase flow is generally significant in the hydraulic-fracturing design of a shale-gas reservoir, especially during the flowback period. Investigating the gas- and water-production data is important to evaluate stimulation effectiveness. We develop a semianalytical model for multifractured horizontal wells by incorporating the two-phase flow in both shale matrix and fracture domains. The complex-fracture network, including both primary/hydraulic fractures and secondary/natural fractures, is modeled explicitly as discretized segments. The node-analysis approach is used to discretize the networks into a number of fracture segments and connected nodes, depending on the complexity of the fracture system. The two-phase flow is incorporated by iteratively correcting the relative permeability to gas/water for each fracture segment and capillary pressure at each node with the fracture depletion. The accuracy of the proposed model is confirmed by the numerical model. Subsequently, the early-time gas- and water-production performance is analyzed by use of various fracture geometries and network configurations. The model was also used to history match an actual multistage hydraulically fractured horizontal well in the Marcellus Shale during the flowback period. The research findings have shed light on the factors that substantially influence the gas- and water-production behavior during the flowback period. We also investigate the effects of fracture-network geometries and complexities on the gas/water-ratio (GWR) diagnostic plots. The results depict that the GWR behavior on the diagnostic plots is highly dependent on fracture-network geometry, configuration, and connectivity, which could assist in deriving the critical fracture properties affecting the production performance. This work extends the semianalytical approach previously proposed for modeling single-phase to two-phase flowback problems in unconventional reservoirs with various fracture-network geometries. The method is easier to set up and is less data-intensive than use of a numerical reservoir simulator, and is capable of providing a straightforward and flexible way to model complex-nonplanar-fracture networks in a multiphase-flow environment.
- North America > United States > Texas (0.93)
- North America > Canada > Alberta (0.68)
- North America > United States > Pennsylvania (0.66)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Geological Subdiscipline (0.93)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
Summary Fluid flow in unpropped and natural fractures is critical in many geophysical processes and engineering applications. The flow conductivity in these fractures depends on their closure under stress, which is a complicated mechanical process that is challenging to model. The challenges come from the deformation interaction and the close coupling among the fracture geometry, pressure, and deformation, making the closure computationally expensive to describe. Hence, most of the previous models either use a small grid system or disregard deformation interaction or plastic deformation. In this study, a numerical model is developed to simulate the stress-driven closure and the conductivity for fractures with rough surfaces. The model integrates elastoplastic deformation and deformation interaction, and can handle contact between heterogeneous surfaces. Computation is optimized and accelerated by use of an algorithm that combines the conjugate-gradient (CG) method and the fast-Fourier-transform (FFT) technique. Computation time is significantly reduced compared with traditional methods. For example, a speedup of five orders of magnitude is obtained for a grid size of 512โรโ512. The model is validated against analytical problems and experiments, for both elastic-only and elastoplastic scenarios. It is shown that interaction between asperities and plastic deformation cannot be ignored when modeling fracture closure. By applying our model, roughness and yield stress are found to have a larger effect on fracture closure and compliance than Young's modulus. Plastic deformation is a dominant contributor to closure and can make up more than 70% of the total closure in some shales. The plastic deformation also significantly alters the relationship between fracture stiffness and conductivity. Surfaces with reduced correlation length produce greater conductivity because of their larger apertures, despite more fracture closure. They have a similar fraction of area in contact as compared with surfaces with longer fracture length, but the pattern of area in contact is more scattered. Contact between heterogeneous surfaces with more soft minerals leads to increased plastic deformation and fracture closure, and results in lower fracture conductivity. Fracture compliance appears not to be as sensitive to the distribution pattern of hard and soft minerals. Our model compares well with experimental data for fracture closure, and can be applied to unpropped or natural fractures. These results are obtained for a wide range of conditions: surface profile following Gaussian distribution with correlation length of 50โยตm and roughness of 4 to 50โยตm, yield stress of 100 to 1500 MPa, and Young's modulus of 20 to 60 GPa. The results may be different for situations outside this range of parameters.
- Research Report > New Finding (0.48)
- Personal > Honors (0.46)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (3 more...)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
Summary In this paper, we consider the development plan of shale gas or tight oil with multiple multistage fractured laterals in a large square drainage area that we call a โsectionโ (usually 640 acres in the US). We propose a convenient section-based optimization of the fracture array with two integer variables, the number of columns (horizontal laterals) and rows (fractures created in a lateral), to provide some general statements regarding spacing of wells and fractures. The approach is dependent on a reliable and efficient productivity-index (PI) calculation for the boundary-dominated state (BDS). The dimensionless PI is obtained by solving a time-independent eigenvalue problem by use of the finite-element method (FEM) combined with the Richardson extrapolation. The results of the case study demonstrate two decisive factors: the dimensionless total fracture length, related to the total amount of proppant and fracturing fluid available for the section, and the feasible range of actual fracture half-lengths, related to current fracturing-technology limitations. Under the constraint of dimensionless total fracture length, increasing the number of columns (horizontal laterals) increases the total PI but with only diminishing returns, whereas the optimal fracture-penetration ratio decreases somewhat, but is still near unity. When adding the technological constraint of a limited range of fracture half-lengths that can be routinely and reliably created, only a few choices remain admissible, and the optimal decision can be easily made. These general statements for the ideal homogeneous and isotropic formation can serve as a reference in the more-detailed optimization works. In other words, we offer a first-pass method for decision making in early stages when detailed inputs are not yet available. The information derived from the section-based optimization method and the efficient and reliable algorithm for PI calculation should help the design of multistage fracturing in shale-gas or ultralow-permeability oil formations.
- Europe (1.00)
- North America > United States > Texas (0.28)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.45)
- North America > United States > Texas > Fort Worth Basin > Barnett Shale Formation (0.99)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.89)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Eagle Ford Shale Formation (0.89)
- North America > United States > Texas > Maverick Basin > Eagle Ford Shale Formation (0.89)
- Well Drilling > Drilling Operations > Directional drilling (1.00)
- Well Completion > Hydraulic Fracturing > Multistage fracturing (1.00)
- Well Completion > Hydraulic Fracturing > Fracturing materials (fluids, proppant) (1.00)
- (3 more...)
Summary Microseismic mapping during the hydraulic-fracturing processes in the Vaca Muerta (VM) Shale in Argentina shows a group of microseismic events occurring at shallower depth and at later injection time, and they clearly deviate from the growing planar hydraulic fracture. This spatial and temporal behavior of these shallow microseismic events incurs some questions regarding the nature of these events and their connectivity to the hydraulic fracture. To answer these questions, in this article, we investigate these phenomena by use of a true 3D fracture-propagation-modeling tool along with statistical analysis on the properties of microseismic events. First, we propose a novel technique in Abaqus incorporating fracture intersections in true 3D hydraulic-fracture-propagation simulations by use of a pore-pressure cohesive zone model (CZM), which is validated by comparing our numerical results with the Khristianovic-Geertsma-de Klerk (KGD) solution (Khristianovic and Zheltov 1955; Geertsma and de Klerk 1969). The simulations fully couple slot flow in the fracture with poroelasticity in the matrix and continuum-based leakoff on the fracture walls, and honor the fracture-tip effects in quasibrittle shales. By use of this model, we quantify vertical-natural-fracture activation and fluid infiltration depending on reservoir depth, fracturing-fluid viscosity, mechanical properties of the natural-fracture cohesive layer, natural-fracture conductivity, and horizontal stress contrast. The modeling results demonstrate this natural-fracture activation in coincidence with the hydraulic-fracture-growth complexities at the intersection, such as height throttling, sharp aperture reduction after the intersection, and multibranching at various heights and directions. Finally, we investigate the hydraulic-fracture intersection with a natural fracture in the multilayer VM Shale. We infer the natural-fracture location and orientation from the microseismic-events map and formation microimager log in a nearby vertical well, respectively. We integrate the other field information such as mechanical, geological, and operational data to provide a realistic hydraulic-fracturing simulation in the presence of a natural fracture. Our 3D fracturing simulations equipped with the new fracture-intersection model rigorously simulate the growth of a realistic hydraulic-connection path toward the natural fracture at shallower depths, which was in agreement with our microseismic observations.
- North America > United States > Texas (1.00)
- Europe (1.00)
- South America > Argentina > Neuquรฉn Province > Neuquรฉn (0.81)
- South America > Argentina > Patagonia Region (0.64)
- Research Report > New Finding (1.00)
- Research Report > Experimental Study (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- South America > Argentina > Patagonia > Neuquรฉn > Neuquen Basin > Vaca Muerta Shale Formation (0.99)
- South America > Argentina > Patagonia > Neuquรฉn > Neuquen Basin > Quintuco Formation (0.99)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- (29 more...)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
A Laplace-Domain Hybrid Model for Representing Flow Behavior of Multifractured Horizontal Wells Communicating Through Secondary Fractures in Unconventional Reservoirs
Jia, Pin (China University of Petroleum, Beijing) | Cheng, Linsong (China University of Petroleum, Beijing) | Clarkson, Christopher R. (University of Calgary) | Qanbari, Farhad (University of Calgary) | Huang, Shijun (China University of Petroleum, Beijing) | Cao, Renyi (China University of Petroleum, Beijing)
Summary In a multiwell pad, the chance of interwell communication increases because of the creation of primary and secondary fractures during hydraulic-fracture stimulation. The flow behavior associated with communicating wells is significantly different from that of a single isolated well, because of interplay of flow caused by the interconnected fractures, complex connections, and multiple production conditions. The main purpose of this paper is to develop a rigorous and efficient flow model and quantify flow characteristics of multiple pad wells communicating through primary and secondary fractures. In the model, matrix and primary- and secondary-fracture flows are captured. Fractures are explicitly represented by discrete segments. The Laplace-transform finite-difference (LTFD) method is used to numerically model fracture flow, with sufficient flexibility to consider arbitrary fracture geometries and fracture-conductivity distributions. The analytical matrix-flow model, derived with the line-source function in the Laplace domain, is dynamically coupled with the fracture-flow model, by imposing the continuity of pressure and flux on the fracture surface. Thus, a hybrid model in the Laplace domain is constructed. The main advantage of the solution occurring in Laplace domain is that computations can be performed at predetermined, discrete times, and with grids only for fractures. Thus, stability and convergence problems caused by time discretization are avoided, and the burden of gridding and computation is decreased without loss of important fracture characteristics. The model is validated through comparison with a fully numerical simulator and a semi-analytical model. Detailed flow-regime analysis reveals that pressure interference caused by communication significantly alters the flow signature compared with single (isolated) wells. Before interference, the communicating wells behave as single isolated wells, and will exhibit a fracture linear-flow period and possibly even a matrix linear-flow period. After interference, the flow behavior of the system will vary largely with different production strategies. When the communicating wells all operate under the constant-rate condition, the transient responses of the wells will gradually merge to develop another matrix linear-flow period. If the wells are operated under the constant-bottomhole-pressure (BHP) conditions, the response deviation caused by interference will increase with production; therefore, one of the wells will undergo a rate loss. The results of a sensitivity analysis for a two-well system demonstrate that the time to well interference is primarily determined by secondary-fracture conductivity, number of connections, and communicating-well operating conditions. With larger contrasts in these properties, interference time is accelerated. However, for different production strategies, the effects on the flow behavior after interference are variable.
- North America > Canada (0.68)
- North America > United States > Texas (0.67)
- North America > United States > West Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- (9 more...)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring (1.00)
Influence of Finite Hydraulic-Fracture Conductivity on Unconventional Hydrocarbon Recovery With Horizontal Wells
Mao, Deming (Shell International Exploration and Production Company) | Miller, David S. (Shell Exploration and Production Company) | Karanikas, John M. (Shell International Exploration and Production Company) | Lake, Ed A. (Shell International Exploration and Production Company) | Fair, Phillip S. (Shell International Exploration and Production Company) | Liu, Xin (Shell International Exploration and Production Company)
Summary The classic plots of dimensionless fracture conductivity (CfD) vs. equivalent wellbore radius or equivalent negative skin are useful for evaluating the performance of hydraulic fractures (HFs) in vertical wells targeting conventional reservoirs (Prats 1961; Cinco-Ley and Samaniego-V. 1981). The increase in well productivity after hydraulic stimulation can be estimated from the โafter fracturingโ effective wellbore radius or from the โafter fracturingโ equivalent negative skin. However, this earlier work does not apply to the case of horizontal wells with multiple fractures. A revision of the diagnostic plots is needed to account for the combination of the resulting radial-flow regime and the transient effect in unconventional reservoirs with ultralow permeability. This paper reviews and extends this earlier work with the objective of making it applicable in the case of horizontal wells with multiple fractures. It also demonstrates practical application of this new technique for fracture-design optimization for horizontal wells. The influence of finite fracture conductivity (FC) on the HF flow efficiency is evaluated through analytical models, and it is confirmed by a 3D transient numerical-reservoir simulation. This work demonstrates that a redefined dimensionless fracture conductivity for horizontal wells CfD,hโ=โ4 is found to be optimal by use of the maximum of log-normal derivative (subject to economics) for HFs in horizontal wells, and this value of CfD,h can provide 50% of the fracture-flow efficiency and 90% of the estimated ultimate recovery (EUR) that would have been obtained from an infinitely conductive fracture for the same production period. This new master plot can provide guidance for hydraulic-fracturing design and its optimization for hydrocarbon recovery in unconventional reservoirs through hydraulic fracturing in horizontal wells.
- Europe > United Kingdom > North Sea > Southern North Sea > Southern Gas Basin > Sole Pit Basin > Block 43/26 > Ravenspurn South Field > Rotliegend Formation (0.99)
- Europe > United Kingdom > North Sea > Southern North Sea > Southern Gas Basin > Sole Pit Basin > Block 42/30 > Ravenspurn South Field > Rotliegend Formation (0.99)
- Europe > United Kingdom > North Sea > Southern North Sea > Southern Gas Basin > Sole Pit Basin > Block 42/29 > Ravenspurn South Field > Rotliegend Formation (0.99)
- South America > Brazil > Parnaiba Basin > Block PN-T-68 > California Field (0.97)
- Well Drilling > Drilling Operations > Directional drilling (1.00)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics (1.00)
Approaches to modeling hydraulic fracturing and their development (Russian)
Khasanov, M. M. (Gazpromneft NTC LLC, RF, Saint-Petersburg) | Paderin, G. V. (Gazpromneft NTC LLC, RF, Saint-Petersburg) | Shel, E. V. (Gazpromneft NTC LLC, RF, Saint-Petersburg) | Yakovlev, A. A. (Gazpromneft NTC LLC, RF, Saint-Petersburg) | Pustovskikh, A. A. (Gazpromneft NTC LLC, RF, Saint-Petersburg)
The PDF file of this paper is in Russian. Modeling of hydraulic fracturing (HF) is the complex problem, which includes the description of many physical processes, including: the fluid flow in the fracture, deformation of the rock, fracture of the rock, proppant flow, etc. An effective solution of this problem requires a considerable number of simplifications and assumptions, which leads to various models of hydraulic fracturing. Presented article is devoted to the analysis and systematization of hydraulic fracturing models. A general system of equations for the fracturing problem is presented, and the aspects of transition from the initial equations to concrete models are considered. In this paper, we analyze both models that are traditionally used in industrial simulators (Lumped Pseudo3D, Cell-based Pseudo3D, Planar3D), and prospective models (Semi-analytical Pseudo3D, UFM Pseudo3D, Planar3D Bio, Full 3D), the implementation of which in the oil industry began recently. The basic approximations in the modeling of fracturing are considered, such as approximations of the effective continuous medium, the approximation of the small width, the incompressibility of the fracturing fluid, the approximation of small deformations and elastic mechanics, the approximation of the planar fracture shape, the approximation of the piecewise homogeneity of the formation along the vertical, the presence or absence of natural fractures network, the poroelastic effects, effects of proppant transport. It is indicated which approximations are used by each of the above-described fracture models. On this basis, conclusions about the range of applicability of certain models or fracturing simulators are drawn. To summarize the results of analysis of the considered HF models, the systematization and hierarchy of HF models based on assumptions and limitations is proposed. The article also discusses possible directions for further development of hydraulic fracturing models.
- Well Completion > Hydraulic Fracturing > Fracturing materials (fluids, proppant) (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (0.89)
Operational efficiency improvement in horizontal wells though optimizing the design of multistage hydraulic fracturing at Priobskoye Northern territory (Russian)
Zorin, A. M. (RN-UfaNIPIneft LLC, RF, Ufa) | Usmanov, T. S. (RN-UfaNIPIneft LLC, RF, Ufa) | Kolonskikh, A. V. (RN-UfaNIPIneft LLC, RF, Ufa) | Fakhretdinov, I. V. (RN-UfaNIPIneft LLC, RF, Ufa) | Sudeyev, I. V. (Rosneft Oil Company, RF, Moscow) | Zernin, A. A. (RN-Yuganskneftegas LLC, RF, Nefteyugansk)
The PDF file of this paper is in Russian. Priobskoye oil field plays an important part in Rosneft Oil Company activities. The undoubted importance of the field to the Company is defined by three factors at least, each of them being fundamental: oil production volumes (both current and prospective); a unique amount of recoverable oil reserves (according to the Russian classification); the field development receives increased attention from the state (oil recovery efficiency, environmental safety). The development of the edge parts of Nothern license area of Priobskoye field is complicated by low-permeable and heterogeneous reservoirs. Despite this, bringing a maximum volume of reserves into development as well as increasing the oil recovery factor remains one of the strategic objectives of Rosneft Oil Company. With the tight oil share growing, the profitability of developing such zones falls sharply. Besides searching for new technologies, the company pays much attention to optimizing the existing ones to improve the development performance of hard-to-recover oil deposits. The paper discusses an approach to the design optimization of multistage hydraulic fracturing in new horizontal wells. Methods of calculating the optimal number of multistage hydrofracturing stages as well as proppant injection are discussed in detail, and pilot test results are listed.
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > Europe Government > Russia Government (0.45)
- Government > Regional Government > Asia Government > Russia Government (0.45)
- Reservoir Description and Dynamics > Reserves Evaluation (1.00)
- Well Completion > Hydraulic Fracturing > Multistage fracturing (0.91)
- Well Drilling > Drilling Operations > Directional drilling (0.71)
Analytical approaches to reserves recovery evaluation and long-term planning of investment in development (Russian)
Sergeichev, A. V. (Rosneft Oil Company, RF, Moscow) | Vasilyev, V. V. (TNNC LLC, RF, Tyumen) | Zimin, P. V. (TNNC LLC, RF, Tyumen) | Stepanov, A. V. (TNNC LLC, RF, Tyumen) | Kuzovkov, A. A. (TNNC LLC, RF, Tyumen)
The PDF file of this paper is in Russian. To date, one of the most important tasks for any oil and gas producing company is the effective planning of field development and operation. According to the authors, the solution to this problem would be a unified Company's approach to the estimation of recoverable reserves, typing, and ranking thereof according to investment potential. The approach proposed by the authors to reserves typing allows to estimate the depleted areas, the zones that will be depleted by the operating well stock, and the remaining reserves. The reserves of each category can be effective / ineffective, contact, and low-permeable (subject to the Federal Laws defining preferential taxation). The authors proposed two algorithms for estimating recoverable reserves - for an existing operating well stock and for planned wells. Analytical approaches to building production profiles of vertical, directional, and horizontal wells, incl. hydraulically fractured wells, have been considered and programmed. The material balance equation and the Darcy law serve as a physical basis for the model runs. The prediction runs performed for wells sum up the reserves category results. The value of the developed algorithms for building production profiles, defining reserves categories, and making an integrated economic assessment is the uniformity of approaches to the assessment of heterogeneous deposits that allows to compare the results of model runs and to perform target-based ranking. The authors see the potential of this technology as an additional tool for the effective management of the Company's reserves portfolio and justification of setting up pilot projects for hard-to-recover reserves.
- North America (0.48)
- Europe > Russia (0.48)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (0.91)
- Reservoir Description and Dynamics > Reservoir Simulation (0.87)
- Reservoir Description and Dynamics > Reserves Evaluation (0.74)
- Well Completion > Hydraulic Fracturing (0.55)