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1
Bennett, B., A. Lager, D. K. Potter, J. O. Buckman, and S. R. Larter. "Petroleum geochemical proxies for reservoir engineering parameters." Journal of Petroleum Science and Engineering 58, no. 3-4 (September 2007): 355–66. http://dx.doi.org/10.1016/j.petrol.2006.06.009.
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Archer, J. "Principles of petroleum reservoir engineering, vol. 1." Journal of Petroleum Science and Engineering 13, no. 3-4 (November 1995): 259–60. http://dx.doi.org/10.1016/0920-4105(95)90008-x.
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Barends, F. B. J., and P. A. Fokker. "Principles of petroleum reservoir engineering, volume 1." Earth-Science Reviews 39, no. 1-2 (September 1995): 132. http://dx.doi.org/10.1016/0012-8252(95)90018-7.
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FOKKER, P. "Principles of petroleum reservoir engineering, volume 2." Earth-Science Reviews 40, no. 1-2 (April 1996): 169–70. http://dx.doi.org/10.1016/0012-8252(96)90067-7.
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Buryakovsky, Leonid A., and George V. Chilingar. "Petrophysical Simulation in Petroleum Geology and Reservoir Engineering." Energy Sources 27, no. 14 (October 2005): 1321–47. http://dx.doi.org/10.1080/009083190519537.
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Lawal, Kazeem A. "Applicability of heat-exchanger theory to estimate heat losses to surrounding formations in a thermal flood." Journal of Petroleum Exploration and Production Technology 10, no. 4 (November 2, 2019): 1565–74. http://dx.doi.org/10.1007/s13202-019-00792-5.
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Abstract Heat losses to cap and base rocks undermine the performance of a thermal flood. As a contribution to this subject, this paper investigates the applicability of the principles of heat exchanger to characterise heat losses between a petroleum reservoir and the adjacent geologic systems. The reservoir-boundary interface is conceptualised as a conductive wall through which the reservoir and adjacent formations exchange heat, but not mass. For a conduction-dominated process, the heat-transport equations are formulated and solved for both adiabatic and non-adiabatic conditions. Simulations performed on a field-scale example show that the rate of heating a petroleum reservoir is sensitive to the type of fluids saturating the adjoining geologic systems, as well as the characteristics of the cap and base rocks of the subject reservoir. Adiabatic and semi-infinite reservoir assumptions are found to be poor approximations for the examples presented. Validation of the proposed model against an existing model was satisfactory; however, remaining differences in performances are rationalised. Besides demonstrating the applicability of heat-exchanger theory to describe thermal losses in petroleum reservoirs, a novelty of this work is that it explicitly accounts for the effects of the reservoir-overburden and reservoir-underburden interfaces, as well as the characteristics of the fluid in the adjacent strata on reservoir heating. These and other findings should aid the design and management of thermal floods.
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Okotie, S., and N. O. Ogbarode. "EVALUATION OF AKPET GT9 GAS CONDENSATE RESERVOIR PERFORMANCE." Open Journal of Engineering Science (ISSN: 2734-2115) 1, no. 1 (March 10, 2020): 1–13. http://dx.doi.org/10.52417/ojes.v1i1.80.
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To effectively evaluate a gas condensate reservoir performance, the reservoir engineer must have a reasonable amount of knowledge about the reservoir to adequately analyze the reservoir performance and predict future production under various modes of operation. Due to the multiphase flow that exists in the reservoir, characterization of gas condensate reservoirs is often a difficult task with the variation of its overall composition in both space and time during production which complicates well deliverability analysis and the sizing of surface facilities. This study is primarily concern with the evaluation of a gas condensate reservoir performance of Akpet GT 9 Reservoir in the Niger Delta region of Nigeria with material balance analysis tool “MBal” without having to run numerical simulations. The result obtained with MBal on the analysis of Akpet GT 9 reservoir gave 23.934 Bscf of gas initially in place which compares favorably with the volume obtained from volumetric techniques. Results also shows that the most likely aquifer model is the Hurst–Van Everdingen - Dake radial aquifer and the reservoir is supported by a combined drive of water influx and fluid expansion.
Okotie, S. | Department of Petroleum Engineering, Federal University of Petroleum Resources (FUPRE), Effurun, Delta State, Nigeria.
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Gutierrez, M., R. W. Lewis, and I. Masters. "Petroleum Reservoir Simulation Coupling Fluid Flow and Geomechanics." SPE Reservoir Evaluation & Engineering 4, no. 03 (June 1, 2001): 164–72. http://dx.doi.org/10.2118/72095-pa.
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Summary This paper presents a discussion of the issues related to the interaction between rock deformation and multiphase fluid flow behavior in hydrocarbon reservoirs. Pore-pressure and temperature changes resulting from production and fluid injection can induce rock deformations, which should be accounted for in reservoir modeling. Deformation can affect the permeability and pore compressibility of the reservoir rock. In turn, the pore pressures will vary owing to changes in the pore volume. This paper presents the formulation of Biot's equations for multiphase fluid flow in deformable porous media. Based on this formulation, it is argued that rock deformation and multiphase fluid flow are fully coupled processes that should be accounted for simultaneously, and can only be decoupled for predefined simple loading conditions. In general, it is shown that reservoir simulators neglect or simplify important geomechanical aspects that can impact reservoir productivity. This is attributed to the fact that the only rock mechanical parameter involved in reservoir simulations is pore compressibility. This parameter is shown to be insufficient in representing aspects of rock behavior such as stress-path dependency and dilatancy, which require a full tensorial constitutive relation. Furthermore, the pore-pressure changes caused by the applied loads from nonpay rock and the influence of nonpay rock on reservoir deformability cannot be accounted for simply by adjusting the pore compressibility. Introduction In the last two decades, there has been a strong emphasis on the importance of geomechanics in several petroleum engineering activities such as drilling, borehole stability, hydraulic fracturing, and production-induced compaction and subsidence. In these areas, in-situ stresses and rock deformations, in addition to fluid-flow behavior, are key parameters. The interaction between geomechanics and multiphase fluid flow is widely recognized in hydraulic fracturing. For instance, Advani et al.1 and Settari et al.2 have shown the importance of fracture-induced in-situ stress changes and deformations on reservoir behavior and how hydraulic fracturing can be coupled with reservoir simulators. However, in other applications, geomechanics, if not entirely neglected, is still treated as a separate aspect from multiphase fluid flow. By treating the two fields as separate issues, the tendency for each field is to simplify and make approximate assumptions for the other field. This is expected because of the complexity of treating geomechanics and multiphase fluid flow as coupled processes. Recently, there has been a growing interest in the importance of geomechanics in reservoir simulation, particularly in the case of heavy oil or bituminous sand reservoirs,3,4 water injection in fractured and heterogeneous reservoirs,5–7 and compacting and subsiding fields.8,9 Several approaches have been proposed to implement geomechanical effects into reservoir simulation. The approaches differ on the elements of geomechanics that should be implemented and the degree to which these elements are coupled to multiphase fluid flow. The objective of this paper is to illustrate the importance of geomechanics on multiphase flow behavior in hydrocarbon reservoirs. An extension of Biot's theory10 for 3D consolidation in porous media to multiphase fluids, which was proposed by Lewis and Sukirman,11 will be reviewed and used to clarify the issues involved in coupling fluid flow and rock deformation in reservoir simulators. It will be shown that for reservoirs with relatively deformable rock, fluid flow and reservoir deformation are fully coupled processes, and that such coupled behaviors cannot be represented sufficiently by a pore-compressibility parameter alone, as is done in reservoir simulators. The finite-element implementation of the fully coupled equations and the application of the finite-element models to an example problem are presented to illustrate the importance of coupling rock deformation and fluid flow. Multiphase Fluid Flow in Deformable Porous Media Fig. 1 illustrates the main parameters involved in the flow of multiphase fluids in deformable porous media and how these parameters ideally interact. The main quantities required to predict fluid movement and productivity in a reservoir are the fluid pressures (and temperatures, in case of nonisothermal problems). Fluid pressures also partly carry the loads, which are transmitted by the surrounding rock (particularly the overburden) to the reservoir. A change in fluid pressure will change the effective stresses following Terzaghi's12 effective stress principle and cause the reservoir rock to deform (additional deformations are induced by temperature changes in nonisothermal problems). These interactions suggest two types of fluid flow and rock deformation coupling:Stress-permeability coupling, where the changes in pore structure caused by rock deformation affect permeability and fluid flow.Deformation-fluid pressure coupling, where the rock deformation affects fluid pressure and vice versa. The nature of these couplings, specifically the second type, are discussed in detail in the next section. Stress-Permeability Coupling This type of coupling is one where stress changes modify the pore structure and the permeability of the reservoir rock. A common approach is to assume that the permeability is dependent on porosity, as in the Carman-Kozeny relation commonly used in basin simulators. Because porosity is dependent on effective stresses, permeability is effectively stress-dependent. Another important effect, in addition to the change in the magnitude of permeability, is on the change in directionality of fluid flow. This is the case for rocks with anisotropic permeabilities, where the full permeability tensor can be modified by the deformation of the rock. Examples of stress-dependent reservoir modeling are given by Koutsabeloulis et al.6 and Gutierrez and Makurat.7 In both examples, the main aim of the coupling is to account for the effects of in-situ stress changes on fractured reservoir rock permeability, which in turn affect the fluid pressures and the stress field. The motivation for the model comes from the field studies done by Heffer et al.5 showing that there is a strong correlation between the orientation of the principal in-situ stresses with the directionality of flow in fractured reservoirs during water injection. There is also growing evidence that the earth's crust is generally in a metastable state, where most faults and fractures are critically stressed and are on the verge of further slip.13 This situation will broaden the range of cases with strong potential for coupling of fluid flow and deformation.
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Ivanova, Tanyana Nikolaevna, Aleksandr Ivanovich Korshunov, and Vladimir Pavlovich Koretckiy. "Dual Completion Petroleum Production Engineering for Several Oil Formations." Management Systems in Production Engineering 26, no. 4 (December 1, 2018): 217–21. http://dx.doi.org/10.1515/mspe-2018-0035.
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Abstract Cost-efficient, enabling technologies for keeping and increasing the reservoir recovery rate of oil-formations with high water cut of produced fluids and exhausted resource are really essential. One of the easiest but short-term ways to increase oil production and incomes at development of oil deposits is cost of development and capital cost reduction. Therefore, optimal choice and proper feasibility study on the facilities for multilayer oil fields development, especially at the late stage of reservoir working, is a crucial issue for now-day oil industry. Currently, the main oil pools do not reach the design point of coefficient of oil recovery. The basic feature of the late stage of reservoir working is the progressing man-made impact on productive reservoir because of water injection increasing for maintaining reservoir pressure. Hence cost-efficient, enabling technologies for keeping and increasing the reservoir recovery rate of oil-formations with high water cut of produced fluids and exhausted resource are really essential. To address the above concerns the dual completion petroleum production engineering was proposed. The intensity of dual completion of formation with of different permeability is determined by rational choice of each of them. The neglect of this principle results a disproportionately rate of highly permeable formations development for the time. In effect the permeability of the formations or their flow rate is decreasing. The problem is aggravated by lack of awareness of mechanics of layers' mutual interference in producers and injectors. Dual completion experience in Russian has shown, that success and efficiency of the technology in many respects depend on engineering support. One of the sufficient criteria for the choice of operational objects should be maximal involvement of oil-saturated layers by oil displacement from seams over the economic life of well producing oil. If it is about getting high rate of oil recovery for irregular formations there is no alternative to dual completion and production. The recommended dual completion petroleum production technology enables development several formations by single well at the time. The dual completion petroleum production technology has been more important than ever because it is right not only for formations but for thin layers with undeveloped remaining reserves.
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Ladopoulos, E. G. "Non-linear singular integral representation for petroleum reservoir engineering." Acta Mechanica 220, no. 1-4 (April 1, 2011): 247–55. http://dx.doi.org/10.1007/s00707-011-0476-0.
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Juell, Aleksander, Curtis H. Whitson, and Mohammad Faizul Hoda. "Model-Based Integration and Optimization—Gas-Cycling Benchmark." SPE Journal 15, no. 02 (April 7, 2010): 646–57. http://dx.doi.org/10.2118/121252-pa.
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Summary A benchmark for computational integration of petroleum operations has been constructed. The benchmark consists of two gas/ condensate reservoirs producing to a common process facility. A fraction of the processed gas is distributed between the two reservoirs for gas injection. Total project economics is calculated from the produced streams and process-related costs. This benchmark may be used to compare different computational integration frameworks and optimization strategies. Even though this benchmark aims to integrate all parts of a petroleum operation, from upstream to downstream, certain simplifications are made. For example, pipe flow from reservoir to process facility is not included in the integrated model. The methods of model integration and optimization discussed in this paper are applicable to complex petroleum operations where it is difficult to quantify cause and effect without comprehensive model-based integration. A framework for integration of models describing petroleum operations has been developed. An example test problem is described and studied in detail. Substantial gains in full-field development may be achieved by optimizing over the entire production system. All models and data in the benchmark problem are made available so that different software platforms can study the effects of alternative integration methods and optimization solver strategy. The project itself can, and probably should, be extended by others to add more complexity (realism) to the reservoir, process, and economics modeling.
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Dusseault, Maurice B. "Geomechanical challenges in petroleum reservoir exploitation." KSCE Journal of Civil Engineering 15, no. 4 (April 2011): 669–78. http://dx.doi.org/10.1007/s12205-011-0007-5.
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Langaas, Kare, Knut I. Nilsen, and Svein M. Skjaeveland. "Tidal Pressure Response and Surveillance of Water Encroachment." SPE Reservoir Evaluation & Engineering 9, no. 04 (August 1, 2006): 335–44. http://dx.doi.org/10.2118/95763-pa.
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Summary A review of the tidal response in petroleum reservoirs is given. Tidal response is caused by periodic changes in overburden stress induced by the ocean tide; the "tidal efficiency factor" is derived by two different approaches and is in line with a recent well test in the Ormen Lange gas field. For small geomechanical pertubations like the tidal effect, we show that a simplified coupling of geomechanics and fluid flow is possible. The coupling is easy to implement in a standard reservoir simulator by introducing a porosity varying in phase with the tide. Simulations show very good agreement with the theory. The observation of the tidal response in petroleum reservoirs is an independent information provider [i.e., it provides information in addition to the (average) pressure and its derivative from a well test]. The implementation of the tidal effect in a normal reservoir simulator gives us the opportunity to study complex multiphase situations and to evaluate the potential of the tidal response as a reservoir-surveillance method. The case studies presented here focus on the possibility of observing water in the near-well region of a gas well. Introduction The main objective of this work is to investigate whether the tidal pressure response in petroleum reservoirs can be used for reservoir surveillance, in particular to detect saturation changes in the near-well region (e.g., to detect water encroachment toward a gas well). The literature seems sparse in this area. Also, our approach of simplified coupling of geomechanics and fluid flow for small geomechanical effects, and the possibility to implement this in a normal reservoir simulator, has not (to our knowledge) been discussed in the literature. Several authors have derived a tidal efficiency factor, but a review and comparison study seems to be missing.
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Stevenson, M. D., M. Kagan, and W. V. Pinczewski. "Computational methods in petroleum reservoir simulation." Computers & Fluids 19, no. 1 (January 1991): 1–19. http://dx.doi.org/10.1016/0045-7930(91)90003-z.
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Guo, Tiankui, and Ming Chen. "Special Issue “Petroleum Engineering: Reservoir Fracturing Technology and Numerical Simulation”." Processes 11, no. 1 (January 11, 2023): 233. http://dx.doi.org/10.3390/pr11010233.
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Hydraulic fracturing is a technique that can provide space for oil and gas flow by pumping fracturing fluid into a reservoir to fracture rock and filling proppant to create fractures or fracture nets [...]
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Lieu, V. T., S. G. Miller, and S. Miller. "A Laboratory Study of Chemical Reactions With Reservoir Sand in the Recovery of Petroleum by Alkaline Flooding." Society of Petroleum Engineers Journal 25, no. 04 (August 1, 1985): 587–93. http://dx.doi.org/10.2118/12561-pa.
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Abstract This paper presents the results of a study of the chemical reactions between alkaline chemical solutions and petroleum reservoir sand material. Long Terms tudies were made of alkaline solution flow through reservoir sandpacks. Analyses were conducted to determine the chemical compositions of the effluents. The results obtained are related to the mineral content of the reservoirs and material. Individual chemical reactions of various minerals are discussed. It appears that there is an important initial combination of rapid reversible adsorption and chemical reactions followed by slower non-reversible chemicalreactions which later can assume great importance due to the long contact time which may prevail in flooding a petroleum reservoir. This long term alkaline consumption is critical, because successful alkaline flooding must provide sufficient alkalinity to survive the time it takes to traverse the reservoir from injection well to production well. Introduction Use of alkaline chemicals to enhance oil field recovery has aroused muchinterest in recent years. The subject has been seriously studied by severalworkers as prelude to actual field injection . At the present time, more than 40 field trials of alkaline flooding have been completed, are in progress, orare being planned.
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Schiozer, Denis José, Antonio Alberto de Souza dos Santos, Susana Margarida de Graça Santos, and João Carlos von Hohendorff Filho. "Model-based decision analysis applied to petroleum field development and management." Oil & Gas Science and Technology – Revue d’IFP Energies nouvelles 74 (2019): 46. http://dx.doi.org/10.2516/ogst/2019019.
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This work describes a new methodology for integrated decision analysis in the development and management of petroleum fields considering reservoir simulation, risk analysis, history matching, uncertainty reduction, representative models, and production strategy selection under uncertainty. Based on the concept of closed-loop reservoir management, we establish 12 steps to assist engineers in model updating and production optimization under uncertainty. The methodology is applied to UNISIM-I-D, a benchmark case based on the Namorado field in the Campos Basin, Brazil. The results show that the method is suitable for use in practical applications of complex reservoirs in different field stages (development and management). First, uncertainty is characterized in detail and then scenarios are generated using an efficient sampling technique, which reduces the number of evaluations and is suitable for use with numerical reservoir simulation. We then perform multi-objective history-matching procedures, integrating static data (geostatistical realizations generated using reservoir information) and dynamic data (well production and pressure) to reduce uncertainty and thus provide a set of matched models for production forecasts. We select a small set of Representative Models (RMs) for decision risk analysis, integrating reservoir, economic and other uncertainties to base decisions on risk-return techniques. We optimize the production strategies for (1) each individual RM to obtain different specialized solutions for field development and (2) all RMs simultaneously in a probabilistic procedure to obtain a robust strategy. While the second approach ensures the best performance under uncertainty, the first provides valuable insights for the expected value of information and flexibility analyses. Finally, we integrate reservoir and production systems to ensure realistic production forecasts. This methodology uses reservoir simulations, not proxy models, to reliably predict field performance. The proposed methodology is efficient, easy-to-use and compatible with real-time operations, even in complex cases where the computational time is restrictive.
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Yin, Shunde, Maurice B. Dusseault, and Leo Rothenburg. "Thermal reservoir modeling in petroleum geomechanics." International Journal for Numerical and Analytical Methods in Geomechanics 33, no. 4 (March 2009): 449–85. http://dx.doi.org/10.1002/nag.723.
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VUKELIC, M. A., and E. N. MIRANDA. "NEURAL NETWORKS IN PETROLEUM ENGINEERING: A CASE STUDY." International Journal of Neural Systems 07, no. 02 (May 1996): 187–94. http://dx.doi.org/10.1142/s0129065796000154.
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A multilayer neural network has been used for deciding which oil reservoir layer has to be perforated. Many network architectures were tested until we found those with the best generalization capability. The network performs better than human experts and its achievements are higher than the historical average in the test area. As in other applications of neural networks, the learning capability improves with more hidden neurons but the generalization does not.
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Piazza, Ralph, Alexandre Vieira, Luiz Alexandre Sacorague, Christopher Jones, Bin Dai, Megan Pearl, and Helen Aguiar. "Innovative Formation Tester Sampling Procedures for Carbon Dioxide and Other Reactive Components." Petrophysics – The SPWLA Journal of Formation Evaluation and Reservoir Description 62, no. 1 (February 1, 2021): 65–72. http://dx.doi.org/10.30632/pjv62n1-2021a4.
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Three questions must be answered to optimize any openhole sampling program. These questions are where to sample, when to sample, and how to sample. Samples must be acquired from the right locations in order to answer the critical questions posed by the asset evaluation and production teams. Samples must be obtained at the right time to minimize contamination while using valuable rig time efficiently. Samples must be taken in a manner that provides the laboratory with the most representative analysis of the subsurface reservoir fluid. Carbon dioxide is a corrosive acidic gas component often found in petroleum reservoirs. Special and relatively costly completion and production equipment is required to produce reservoir fluids containing carbon dioxide. Carbon dioxide must be scrubbed from petroleum before that petroleum is shipped. Carbon dioxide may cause flow assurance issues with regards to scale of inorganic and organic components, thereby requiring costly mitigation. An accurate estimate of carbon dioxide concentration in the reservoir fluid is required to make an accurate determination of the cost of CO2 remediation. New formation tester carbon dioxide analysis technology has allowed detailed examination of these questions due to a previously unobserved phenomenon with respect to formation tester sampling and carbon dioxide. Specifically, carbon dioxide may bind with caustic components of drilling-fluid filtrate in either a reversible manner or be consumed by caustic components in an irreversible manner. Observation of a reversible reaction has been used to validate the phenomena but also provides a cautionary warning that for different chemical reactions in which carbon dioxide may be consumed, openhole samples may significantly underestimate the amount of carbon dioxide in the reservoir fluid. New sampling procedures applicable to existing formation testing infrastructure mitigate this sampling issue by determining the correct carbon dioxide content in the reservoir fluid. The new sampling procedures are validated with the carbon dioxide monitoring technology but are not strictly dependent on it. In addition, the proposed sampling procedures are applicable to the measurement of all reactive petroleum components, such as hydrogen sulfide.
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Hao, Jian Ming, Wei Zhao, Jian Guo Zhang, and Zai Xing Jiang. "Application of New Hardware and Software Technology in the Oil and Gas Seismic Exploration and Development." Advanced Materials Research 734-737 (August 2013): 1144–49. http://dx.doi.org/10.4028/www.scientific.net/amr.734-737.1144.
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Seismic exploration of petroleum is a kind of high technology which integrated hardware and software. The improvement of software engineering has produced an active influence on seismic exploration. The recent advance mainly expressed on acquisition, processing and interpretation of high frequency three dimensional seismic data. Application of new algorithm and super integrate large-scale software can improve the accuracy and efficiency of the petroleum discovery. Development seismic is new frontier of seismic application. Its a new branch of learning which makes full description and dynamic detection during petroleum exploration. It need use manners of oil and gas reservoir observation and information processing technique, combining with the data of drilling, geology and reservoir engineering etc. This can also take related hardware and software technological advances and development.
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Cheng, Hanlie, Peng Ma, Guofeng Dong, Shun Zhang, Jianfei Wei, and Qiang Qin. "Characteristics of Carboniferous Volcanic Reservoirs in Beisantai Oilfield, Junggar Basin." Mathematical Problems in Engineering 2022 (April 25, 2022): 1–10. http://dx.doi.org/10.1155/2022/7800630.
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In recent years, petroleum exploration in the Carboniferous volcanic rock reservoirs in the Junggar Basin has been the focus of important petroleum energy development in western China. The lithologic identification of volcanic rock reservoirs seriously restricts the accuracy of reservoir prediction and affects the success rate of oil exploration. Different types of volcanic rocks have different petrological characteristics and mineral assemblages, especially affected by the depositional environment. The volcanic rocks in different regions have their own uniqueness. This paper takes the Carboniferous volcanic reservoirs in Xiquan block, Beisantai Oilfield, Junggar Basin as the research target. Through a large number of core observations, casting slices, scanning electron microscopy, and X-ray diffraction methods, the Carboniferous volcanic rocks are analyzed. The petrology, pore characteristics, physical properties, and diagenetic evolution history of the reservoir are analyzed. The study shows that the volcanic facies in the Xiquan block can be divided into explosive facies, overflow facies, and volcanic sedimentary facies, among which the explosive facies is subdivided into empty subfacies (volcanic breccia-breccia tuff combination) and thermal base wave subfacies (tuff). The lithology of the reservoir is pyroclastic rock and volcanic lava, belonging to medium-porous and ultralow permeability reservoirs, and the storage space can be divided into three types: primary pores, secondary pores, and fractures. The lithology of key exploration is breccia tuff, followed by breccia tuff and volcanic breccia.
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Cheng, Hanlie, Peng Ma, Guofeng Dong, Shun Zhang, Jianfei Wei, and Qiang Qin. "Characteristics of Carboniferous Volcanic Reservoirs in Beisantai Oilfield, Junggar Basin." Mathematical Problems in Engineering 2022 (April 25, 2022): 1–10. http://dx.doi.org/10.1155/2022/7800630.
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In recent years, petroleum exploration in the Carboniferous volcanic rock reservoirs in the Junggar Basin has been the focus of important petroleum energy development in western China. The lithologic identification of volcanic rock reservoirs seriously restricts the accuracy of reservoir prediction and affects the success rate of oil exploration. Different types of volcanic rocks have different petrological characteristics and mineral assemblages, especially affected by the depositional environment. The volcanic rocks in different regions have their own uniqueness. This paper takes the Carboniferous volcanic reservoirs in Xiquan block, Beisantai Oilfield, Junggar Basin as the research target. Through a large number of core observations, casting slices, scanning electron microscopy, and X-ray diffraction methods, the Carboniferous volcanic rocks are analyzed. The petrology, pore characteristics, physical properties, and diagenetic evolution history of the reservoir are analyzed. The study shows that the volcanic facies in the Xiquan block can be divided into explosive facies, overflow facies, and volcanic sedimentary facies, among which the explosive facies is subdivided into empty subfacies (volcanic breccia-breccia tuff combination) and thermal base wave subfacies (tuff). The lithology of the reservoir is pyroclastic rock and volcanic lava, belonging to medium-porous and ultralow permeability reservoirs, and the storage space can be divided into three types: primary pores, secondary pores, and fractures. The lithology of key exploration is breccia tuff, followed by breccia tuff and volcanic breccia.
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Aguilera, Roberto. "Flow Units: From Conventional to Tight-Gas to Shale-Gas to Tight-Oil to Shale-Oil Reservoirs." SPE Reservoir Evaluation & Engineering 17, no. 02 (February 20, 2014): 190–208. http://dx.doi.org/10.2118/165360-pa.
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Summary Core data from various North American basins with the support of limited amounts of data from other basins around the world have shown in the past that process speed or delivery speed (the ratio of permeability to porosity) provides a continuum between conventional, tight-, and shale-gas reservoirs (Aguilera 2010a). This work shows that the previous observation can be extended to tight-oil and shale-oil reservoirs. The link between the various hydrocarbon fluids is provided by the word “petroleum” in the “total petroleum system (TPS),” which encompasses liquid and gas hydrocarbons found in conventional, tight, and shale reservoirs. Results of the present study lead to distinctive flow units for each type of reservoir that can be linked empirically to gas and oil rates and, under favorable conditions, to production decline. To make the work tractable, the bulk of the data used in this paper has been extracted from published geologic and petroleum-engineering literature. The paper introduces an unrestricted/transient/interlinear transition flow period in a triple-porosity model for evaluating the rate performance of multistage-hydraulically-fractured (MSHF) tight-oil reservoirs. Under ideal conditions, this flow period is recognized by a straight line with a slope of –1.0 on log-log coordinates. However, the slope can change (e.g., to –0.75), depending on reservoir characteristics, as shown with production data from the Cardium and Shaunavon formations in Canada. This interlinear flow period has not been reported previously in the literature because the standard assumption for MSHF reservoirs has been that of a pseudosteady-state transition between the linear flow periods. It is concluded that there is a significant practical potential in the use of process speed as part of the flow-unit characterization of unconventional petroleum reservoirs. There is also potential for the evaluation of production-decline rates by the use of the triple-porosity model presented in this study.
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Worthington, Paul Francis. "Petrophysical Type Curves for Identifying the Electrical Character of Petroleum Reservoirs." SPE Reservoir Evaluation & Engineering 10, no. 06 (December 1, 2007): 711–29. http://dx.doi.org/10.2118/96718-pa.
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Summary A user-friendly type chart has been constructed as an aid to the evaluation of water saturation from well logs. It provides a basis for the inter-reservoir comparison of electrical character in terms of adherence to, or departures from, Archie conditions in the presence of significant shaliness and/or low formation-water salinity. Therefore, it constitutes an analog facility. The deliverables include reservoir classification to guide well-log analysis, a protocol for optimizing the acquisition of special core data in support of log analysis, and reservoir characterization in terms of an (analog) porosity exponent and saturation exponent. The type chart describes a continuum of electrical behavior for both water and hydrocarbon zones. This is important because some reservoir rocks can conform to Archie conditions in the fully water-saturated state, but show pronounced departures from Archie conditions in the partially water-saturated state. In this respect, the chart is an extension of earlier approaches that were restricted to the water zone. This extension is achieved by adopting a generalized geometric factor—the ratio of water conductivity to formation conductivity—regardless of the degree of hydrocarbon saturation. The type chart relates a normalized form of this geometric factor to formation-water conductivity, a "shale" conductivity term, and (irreducible) water saturation. The chart has been validated using core data from comprehensively studied reservoirs. A workflow details the application of the type chart to core and/or log data. The analog role of the chart is illustrated for reservoir units that show different levels of non-Archie effects. The application of the method should take rock types, scale effects, the degree of core sampling, and net reservoir criteria into account. The principal benefit is a reduced uncertainty in the choice of a procedure for the petrophysical evaluation of water saturation, especially at an early stage in the appraisal/development process, when adequate characterizing data may not be available. Introduction One of the ever-present problems in petrophysics is how to carry out a meaningful evaluation of well logs in situations where characterizing information from quality-assured core analysis is either unavailable or is insufficient to satisfactorily support the log interpretation. This problem is especially pertinent at an early stage in the life of a field, when reservoir data are relatively sparse. Data shortfalls could be mitigated if there was a means of identifying petrophysical analogs of reservoir character, so that the broader experience of the hydrocarbon industry could be utilized in constructing reservoir models and thence be brought to bear on current appraisal and development decisions. Here, a principal requirement calls for type charts of petrophysical character, on which data from different reservoirs can be plotted and compared, as a basis for aligning approaches to future data acquisition and interpretation. This need manifests itself strongly in the petrophysical evaluation of water saturation, a process that traditionally uses the electrical properties of a reservoir rock to deliver key building blocks for an integrated reservoir model. The solution to this problem calls for an analog facility through which the electrical character of a subject reservoir can be compared with others that have been more comprehensively studied. In this way, the degree of confidence in log-derived water saturation might be reinforced. At the limit, the log analyst needs a reference basis for recourse to capillary pressure data in cases where the well-log evaluation of water saturation turns out to be prohibitively uncertain.
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Oboh, Innocent O., Anietie N. Okon, and Hocaha F. Enyi. "DEVELOPMENT OF PRODUCTION RATE DECLINE-BASED SOFTWARE FOR RESERVOIR PERFORMANCE PREDICTION." International Journal of Research -GRANTHAALAYAH 7, no. 6 (June 30, 2019): 49–55. http://dx.doi.org/10.29121/granthaalayah.v7.i6.2019.749.
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The need for predicting the performance of hydrocarbon reservoirs has led to the development of a number of software in the Petroleum industry. Lots of these available software handled virtually all tasks in reservoir engineering ranging from estimation, forecasting, history matching, among others. That notwithstanding, improvements on these software are still been made and newer versions are released to meet users’ requirements. In this work, software “ULTIMATE” was developed based on production rate decline analysis to predict reservoir performance. Also, the developed software “ULTIMATE” handles Inflow Performance Relationship (IPR) prediction. The developed software prediction based on data obtained from two wells were compared with another software MBAL 10.5 developed by petroleum Experts Limited. The results of the comparison indicated that the developed ULTIMATE software predictions were very close to the MBAL 10.5 predictions. Additionally, the incorporated parallel algorithm in the ULTIMATE software enables it to analyze more wells and with more speed than the other software (MBAL 10.5). Therefore, the developed ULTIMATE software can be use as quick tool for predicting reservoir performance based on production rate decline analysis. Furthermore, the developed software would be improved to handle reservoir performance predictions based on Materials Balance Equation (MBE), and other production rate-related predictions like coning parameters estimation.
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Lima, Raquel Oliveira, Leonardo José do Nascimento Guimarães, and Leonardo Cabral Pereira. "Evaluating geomechanical effects related to the production of a Brazilian reservoir." Journal of Petroleum Exploration and Production Technology 11, no. 6 (June 2021): 2661–78. http://dx.doi.org/10.1007/s13202-021-01190-6.
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AbstractThis paper presents a coupled finite element approach for modeling geomechanical effects induced by production/injection processes in petroleum reservoirs. The module developed employs coupled- reservoir analysis using CMG IMEX® as the flow simulator and a finite element program in MATLAB® as the stress–strain simulator, in a two-way explicit partial coupling scheme. The flow and mechanical problems are coupled by the change of effective stress due to the change in pore pressure and by varying stress-dependent reservoir properties, such as pore compressibility, absolute permeability, and porosity. The coupling procedure was applied to the Namorado Field (Campos Basin, Brazil) to quantify the impact of the rock deformation on fluid recovery. Based on the cases studied, the coupled analyses predicted higher oil recovery than the conventional reservoir simulations. The results showed that the reservoir deformation can affect its performance and must be taken into account in reservoir-engineering studies depending on production strategy and reservoir stiffness. Besides, the geomechanical calculations were performed only in the coupling timesteps, reducing the computational effort and making this coupling method feasible on a field scale.
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Kuk, Edyta, Jerzy Stopa, Michał Kuk, Damian Janiga, and Paweł Wojnarowski. "Petroleum Reservoir Control Optimization with the Use of the Auto-Adaptive Decision Trees." Energies 14, no. 18 (September 10, 2021): 5702. http://dx.doi.org/10.3390/en14185702.
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The global increase in energy demand and the decreasing number of newly discovered hydrocarbon reservoirs caused by the relatively low oil price means that it is crucial to exploit existing reservoirs as efficiently as possible. Optimization of the reservoir control may increase the technical and economic efficiency of the production. In this paper, a novel algorithm that automatically determines the intelligent control maximizing the NPV of a given production process was developed. The idea is to build an auto-adaptive parameterized decision tree that replaces the arbitrarily selected limit values for the selected attributes of the decision tree with parameters. To select the optimal values of the decision tree parameters, an AI-based optimization tool called SMAC (Sequential Model-based Algorithm Configuration) was used. In each iteration, the generated control sequence is introduced into the reservoir simulator to compute the NVP, which is then utilized by the SMAC tool to vary the limit values to generate a better control sequence, which leads to an improved NPV. A new tool connecting the parameterized decision tree with the reservoir simulator and the optimization tool was developed. Its application on a simulation model of a real reservoir for which the CCS-EOR process was considered allowed oil production to be increased by 3.5% during the CO2-EOR phase, reducing the amount of carbon dioxide injected at that time by 16%. Hence, the created tool allowed revenue to be increased by 49%.
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Behrenbruch, P. "MANAGEMENT OF UNCERTAINTY AND RISK IN OFFSHORE PETROLEUM DEVELOPMENT." APPEA Journal 42, no. 1 (2002): 113. http://dx.doi.org/10.1071/aj01007.
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Uncertainty in petroleum development projects is most often associated with petroleum reserves. It is the limited amount of subsurface data typically available during the time of development planning that creates this situation. Risks are associated not only with reservoir uncertainty but also with wells and production facilities. Risks for offshore projects, as compared to those onshore, are further compounded by very large capital expenditures and less flexibility in catering for subsurface surprises, or remedial action in case of engineering blunders.These concepts are illustrated using case histories of successful and failed projects. Lessons learned from these and other projects are then summarised and processes for uncertainty and risk management are outlined. Risk and uncertainty cover a wide range of issues, and relate to geoscience, reservoir engineering, well technology, facilities engineering, operations, and project planning and evaluation.
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Mazo, A. B., and K. A. Potashev. "Upscaling relative phase permeability for superelement modeling of petroleum reservoir engineering." Mathematical Models and Computer Simulations 9, no. 5 (September 2017): 570–79. http://dx.doi.org/10.1134/s207004821705009x.
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Almeida, Alcino Resende, and Renato MacHado Cotta. "Integral transform methodology for convection-diffusion problems in petroleum reservoir engineering." International Journal of Heat and Mass Transfer 38, no. 18 (December 1995): 3359–67. http://dx.doi.org/10.1016/0017-9310(95)00101-e.
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Li, Chunquan, Honghan Chen, and Huimin Liu. "Fluid Inclusion Constrained Multiple Petroleum Chargings in the Lithologic Reservoirs of the Late Eocene Shahejie Formation in the Minfeng Sag, Bohai Bay Basin, East China." Energies 15, no. 10 (May 17, 2022): 3682. http://dx.doi.org/10.3390/en15103682.
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The fluid inclusion technique was utilized to reveal the petroleum charging events in the lithologic reservoirs embraced in the Late Eocene Shahejie Formation of the Minfeng sag, Bohai Bay Basin, East China. Petrography, fluorescence microspectrometry, and microthermometry were systematically carried out on 15 double-polished thin sections handled from reservoir core samples of the third Member of the Shahejie Formation. The results show that three generations of petroleum inclusions with fluorescence colors of yellow, yellowish green and bright blue were entrapped along the healed fractures in detrital quartz grains of these samples. The fluorescence features of petroleum inclusions illustrate that inclusion oils have different maturities and were products of source rocks at different stages. In addition, the trapping time of petroleum inclusions was determined by combining the homogenization temperatures of their coeval aqueous inclusions with thermal-burial histories. By integrating the petrographic occurrence, characteristics of petroleum inclusions, and the maturity and the trapping time of the studied inclusion oils, it is jointly constrained that the lithologic reservoirs of the Late Eocene Shahejie Formation in the Minfeng sag underwent three petroleum chargings, which occurred during 37.8~25 Ma, 11.7~3.5 Ma and 1.4~0.1 Ma, respectively. The petroleum from each charging period migrated from the center of the sag to the edge, and the lower the maturity of the migrating petroleum, the longer the migration duration.
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Kuk, Edyta, Michał Kuk, Damian Janiga, Paweł Wojnarowski, and Jerzy Stopa. "Smart Optimization of Proactive Control of Petroleum Reservoir." ENTRENOVA - ENTerprise REsearch InNOVAtion 7, no. 1 (December 8, 2021): 304–13. http://dx.doi.org/10.54820/asqf9458.
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Artificial Intelligence plays an increasingly important role in many industrial applications as it has great potential for solving complex engineering problems. One of such applications is the optimization of petroleum reservoirs production. It is crucial to produce hydrocarbons efficiently as their geological resources are limited. From an economic point of view, optimization of hydrocarbon well control is an important factor as it affects the whole market. The solution proposed in this paper is based on state-of-the-art artificial intelligence methods, optimal control, and decision tree theory. The proposed idea is to apply a novel temporal clustering algorithm utilizing an autoencoder for temporal dimensionality reduction and a temporal clustering layer for cluster assignment, to cluster wells into groups depending on the production situation that occurs in the vicinity of the well, which allows reacting proactively. Then the optimal control of wells belonging to specific groups is determined using an auto-adaptive decision tree whose parameters are optimized using a novel sequential model-based algorithm configuration method. Optimization of petroleum reservoirs production translates directly into several economic benefits: reduction in operation costs, increase in the production effectiveness and increase in overall income without any extra expenditure as only control is changed.
This work is licensed under a Creative Commons Attribution-NonCommercial 4.0 International License.
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Chilingarian, George V. "Introduction to petroleum reservoir analysis and laboratory workbook." Journal of Petroleum Science and Engineering 3, no. 4 (January 1990): 361. http://dx.doi.org/10.1016/0920-4105(90)90055-8.
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Mokhatab, Saeid. "Advanced Petroleum Reservoir Simulations: A Knowledge-Based Approach." Petroleum Science and Technology 29, no. 4 (January 2011): 435. http://dx.doi.org/10.1080/10916466.2011.527815.
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Gillott, J. E. "Some clay-related problems in engineering geology in North America." Clay Minerals 21, no. 3 (September 1986): 261–78. http://dx.doi.org/10.1180/claymin.1986.021.3.02.
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AbstractClay minerals are almost ubiquitous in soil and rock and are among the most reactive silicates. They affect the engineering behaviour of soil and rock both as materials of construction and as foundation materials. In the petroleum industry, clay affects the permeability of reservoir formations, it is a common cap-rock, and it is also a constituent of the fluids used in drilling operations. Engineering behaviour almost always involves clay-water interaction and in turn this depends on the nature of water and solutions and on the composition and microstructure of the clay. The importance of clay to specific problems from each of these areas is discussed. In foundation engineering its role in soil-moisture interaction is illustrated by reference to problems resulting from the geological history of some North American soils and from engineering activities. In building materials, reference is made to its effect on concrete durability in aggregate-related problems. The importance of clay in petroleum engineering refers to authigenic clays in reservoir rocks, to clay behaviour in the Alberta oil sands and to the use of clay minerals as a geothermal thermometer.
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Otumudia, Ephraim, Hossein Hamidi, Prashant Jadhawar, and Kejian Wu. "The Utilization of Ultrasound for Improving Oil Recovery and Formation Damage Remediation in Petroleum Reservoirs: Review of Most Recent Researches." Energies 15, no. 13 (July 5, 2022): 4906. http://dx.doi.org/10.3390/en15134906.
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The ultrasound method is a low-cost, environmentally safe technology that may be utilized in the petroleum industry to boost oil recovery from the underground reservoir via enhanced oil recovery or well stimulation campaigns. The method uses a downhole instrument to propagate waves into the formation, enhancing oil recovery and/or removing formation damage around the wellbore that has caused oil flow constraints. Ultrasonic technology has piqued the interest of the petroleum industry, and as a result, research efforts are ongoing to fill up the gaps in its application. This paper discusses the most recent research on the investigation of ultrasound’s applicability in underground petroleum reservoirs for improved oil recovery and formation damage remediation. New study areas and scopes were identified, and future investigations were proposed.
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Tohidi, B., K. K. Østergaard, A. Danesh, A. C. Todd, and R. W. Burgass. "Structure-H gas hydrates in petroleum reservoir fluids." Canadian Journal of Chemical Engineering 79, no. 3 (June 2001): 384–91. http://dx.doi.org/10.1002/cjce.5450790311.
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El-Bagoury, Mohamed. "Integrated petrophysical study to validate water saturation from well logs in Bahariya Shaley Sand Reservoirs, case study from Abu Gharadig Basin, Egypt." Journal of Petroleum Exploration and Production Technology 10, no. 8 (August 18, 2020): 3139–55. http://dx.doi.org/10.1007/s13202-020-00969-3.
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Abstract Water saturation is a key parameter in evaluating oil and gas reservoirs and calculating OIIP and GIIP for petroleum fields. The late Cretaceous Bahariya reservoir contains variable amounts of clay minerals. Bore hole logs are affected with those clay minerals particularly the density and resistivity logs. Several methods are acknowledged to determine the true water saturation from well logs in shaley sand reservoirs. Each method assumes a sort of corrections to amount of shale distributed in the reservoir. The scope of this petrophysical study is to integrate core analysis and bore hole logs to investigate the characteristics of water saturation in the Bahariya reservoirs. Comparison between most of the significant shaley sand methods is presented in this research. Reservoir lithology and mineralogy are explained by Elan-model while bore hole images are used for fine-tuning the electrofacies. Siltstone, shaley sand and clean sandstones are the main electrofacies that is characterizing the Bahariya reservoir rocks. For accurate saturation results, some core samples have been used for validating the log-derived water saturation. Dean stark and cation exchange capacity experiments are integrated with bore hole logs to calculate the error in water saturation for each method for best calibration. The successful integration between logs and core measurements led to convenient log evaluation and accurate understanding for the Bahariya reservoir in the prospective part of Abu Gharadig basin.
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Carpenter, Chris. "Artificial Neural Network Models and Predicts Reservoir Parameters." Journal of Petroleum Technology 73, no. 01 (January 1, 2021): 44–45. http://dx.doi.org/10.2118/0121-0044-jpt.
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This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 19854, “Modeling and Prediction of Resistivity, Capillary Pressure, and Relative Permeability Using Artificial Neural Network,” by Mustafa Ba alawi, SPE, King Fahd University of Petroleum and Minerals; Salem Gharbi, SPE, Saudi Aramco; and Mohamed Mahmoud, King Fahd University of Petroleum and Minerals, prepared for the 2020 International Petroleum Technology Conference, Dhahran, Saudi Arabia, 13–15 January. The paper has not been peer reviewed. Copyright 2020 International Petroleum Technology Conference. Reproduced by permission. Capillary pressure and relative permeability are essential measurements that affect multiphase fluid flow in porous media directly. The processes of measuring these parameters, however, are both time-consuming and expensive. Artificial-intelligence methods have achieved promising results in modeling extremely complicated phenomena in the industry. In the complete paper, the authors generate a model by using an artificial-neural-network (ANN) technique to predict both capillary pressure and relative permeability from resistivity. Capillary Pressure and Resistivity Capillary pressure and resistivity are two of the most significant parameters governing fluid flow in oil and gas reservoirs. Capillary pressure, the pressure difference over the interface of two different immiscible fluids, traditionally is measured in the laboratory. The difficulty of its calculation is related to the challenges of maintaining reservoir conditions and the complexity of dealing with low-permeability and strong heterogeneous samples. Moreover, unless the core materials are both available and representative, a restricted number of core plugs will lead to inadequate reservoir description. On the other hand, resistivity can be obtained by either lab-oratory analysis or through typical and routine well-logging tools in real time. Both parameters have similar attributes, given their dependence on wetting-phase saturation. Despite many studies in the literature that are reviewed in the complete paper, improvement of capillary pressure and resistivity modeling remains an open research area. Artificial Intelligence in Petroleum Engineering In addition to labor and expense concerns, conventional methods to measure resistivity, capillary pressure, and relative permeability depend primarily, with the exception of resistivity from well logs, on the availability of core samples of the desired reservoir. The literature provides several attempts to model these parameters in order to avoid many of the requirements of measurement. However, the performance of many of these models is restricted by assumptions and constraints that require further processing. For example, the accuracy of prediction of capillary pressure from resistivity is highly dependent on the tested core permeability, which requires measuring it as well to achieve the full potentiality of the model.
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van Wijk, Jolante, Noah Hobbs, Peter Rose, Michael Mella, Gary Axen, and Evan Gragg. "Analysis of Geologic CO2 Migration Pathways in Farnsworth Field, NW Anadarko Basin." Energies 14, no. 22 (November 22, 2021): 7818. http://dx.doi.org/10.3390/en14227818.
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This study reports on analyses of natural, geologic CO2 migration paths in Farnsworth Oil Field, northern Texas, where CO2 was injected into the Pennsylvanian Morrow B reservoir as part of enhanced oil recovery and carbon sequestration efforts. We interpret 2D and 3D seismic reflection datasets of the study site, which is located on the western flank of the Anadarko basin, and compare our seismic interpretations with results from a tracer study. Petroleum system models are developed to understand the petroleum system and petroleum- and CO2-migration pathways. We find no evidence of seismically resolvable faults in Farnsworth Field, but interpret a karst structure, erosional structures, and incised valleys. These interpretations are compared with results of a Morrow B well-to-well tracer study that suggests that inter-well flow is up-dip or lateral. Southeastward fluid flow is inhibited by dip direction, thinning, and draping of the Morrow B reservoir over a deeper, eroded formation. Petroleum system models predict a deep basin-ward increase in temperature and maturation of the source rocks. In the northwestern Anadarko Basin, petroleum migration was generally up-dip with local exceptions; the Morrow B sandstone was likely charged by formations both below and overlying the reservoir rock. Based on this analysis, we conclude that CO2 escape in Farnsworth Field via geologic pathways such as tectonic faults is unlikely. Abandoned or aged wellbores remain a risk for CO2 escape from the reservoir formation and deserve further monitoring and research.
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Purbey, Rupali, Harshwardhan Parijat, Divya Agarwal, Devarati Mitra, Rakhi Agarwal, Rakesh Kumar Pandey, and Anil Kumar Dahiya. "Machine learning and data mining assisted petroleum reservoir engineering: a comprehensive review." International Journal of Oil, Gas and Coal Technology 30, no. 4 (2022): 359. http://dx.doi.org/10.1504/ijogct.2022.124412.
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Pandey, Rakesh Kumar, Anil Kumar Dahiya, Rakhi Agarwal, Devarati Mitra, Rupali Purbey, Harshwardhan Parijat, and Divya Agarwal. "Machine learning and data mining assisted petroleum reservoir engineering: a comprehensive review." International Journal of Oil, Gas and Coal Technology 1, no. 1 (2021): 1. http://dx.doi.org/10.1504/ijogct.2021.10043807.
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Li, Chen, and Michael J. King. "Integration of Pressure Transient Data into Reservoir Models Using the Fast Marching Method." SPE Journal 25, no. 04 (March 29, 2020): 1557–77. http://dx.doi.org/10.2118/180148-pa.
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Summary Calibration of reservoir model properties by integration of well-test data remains an important research topic. Well-test data have been recognized as an effective tool to describe transient flow behavior in petroleum reservoirs. It is also closely related to the drainage volume of the well and the pressure-front propagation in the subsurface. Traditional analytic means of estimating reservoir permeability relies on an interpretation of the diagnostic plot of the well pressure and production data, which usually leads to a bulk average estimation of the reservoir permeability. When more detailed characterization is needed, a forward model that is sensitive to the reservoir heterogeneity needs to be established, and a numerical inversion technique is required. We use the concept of the diffusive time of flight (DTOF) to formulate an asymptotic solution of the diffusivity equation that describes transient flow behavior in heterogeneous petroleum reservoirs. The DTOF is obtained from the solution of the Eikonal equation using the fast marching method (FMM). It can be used as a spatial coordinate that reduces the 3D diffusivity equation to an equivalent 1D formulation. We investigate the drainage-volume evolution as a function of time in terms of the DTOF. The drainage volume might be directly related to the well-test derivative, which can be used in an inversion calculation to calibrate reservoir model parameters. The analytic sensitivity coefficients of the well-test derivative with respect to reservoir permeability are derived and incorporated into an objective function to perform model calibration. The key to formulating the sensitivity coefficients is to use the functional derivative of the Eikonal equation to derive the analytic sensitivity of the DTOF to reservoir permeability. Its solution is implemented by tracking the characteristic trajectory of the local Eikonal solver within the FMM. The major advantage of calculating the sensitivity coefficients using the FMM is its significant computational efficiency during the iterative inversion process. This inverse-modeling approach is tested on a 2D synthetic heterogeneous reservoir model and then applied to the 3D Brugge Field, where a single well with constant flow rate is simulated. The well-test derivative is shown to be inversely proportional to the drainage volume and is treated as the objective function for inversion. With an additional constraint to honor the prior model, our inverse-modeling approach will adjust the reservoir model to obtain permeability as a function of distance from the well within the drainage volume. It provides a modification of reservoir permeability both within and beyond the depth of investigation (DOI).
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Qassamipour, Mehdi, Elnaz Khodapanah, and Seyyed Alireza Tabatabaei-Nezhad. "An integrated procedure for reservoir connectivity study between neighboring fields." Journal of Petroleum Exploration and Production Technology 10, no. 8 (August 29, 2020): 3179–90. http://dx.doi.org/10.1007/s13202-020-00995-1.
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Abstract Reservoir connectivity has a considerable effect on reservoir characterization, plans for field developments and production forecasts. Reducing the uncertainties about the lateral and vertical extension of different pay zones is the main step in developing and managing the reservoirs. Nearly all the proposed methodologies for the verification of reservoir connectivity are limited to the study of the communication of different compartments in one field. In the presented paper, first a comprehensive procedure is proposed to study the reservoir connectivity between nearby fields. The steps in this procedure are not necessarily hierarchy, but all the considerations in each step are studied to cover all the uncertainties that affect the reservoir communication. This procedure mainly comprises the study of reservoir extension, pressure communication in the hydrocarbon column, fluid similarity, top seal efficiency and faults sealing. Then, to apply this procedure for proving the communication between nearby fields, a case study of Ilam Formation in southwest of Iran is presented. The results confirm the lateral connectivity of the three pre-explored distinctive oil fields in Ilam Formation. The established connectivity leads to an increase in the pre-estimated oil-in-place volumes. This incorporated case study demonstrates how different data including geophysics, structural and petroleum geology, production and reservoir engineering are integrated to prove the communication of Ilam reservoir between these fields. This manifested technique is a powerful road map for other cases worldwide and is extremely recommended to be performed before developing those fields that are suspicious to lateral connectivity.
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Khalaf, Mohammed H., and G. Ali Mansoori. "Asphaltenes aggregation during petroleum reservoir air and nitrogen flooding." Journal of Petroleum Science and Engineering 173 (February 2019): 1121–29. http://dx.doi.org/10.1016/j.petrol.2018.10.037.
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Bashir, Yasir, Muhammad Amir Faisal, Ajay Biswas, Amir abbas Babasafari, Syed Haroon Ali, Qazi Sohail Imran, Numair Ahmed Siddiqui, and Muhsan Ehsan. "Seismic expression of miocene carbonate platform and reservoir characterization through geophysical approach: application in central Luconia, offshore Malaysia." Journal of Petroleum Exploration and Production Technology 11, no. 4 (April 2021): 1533–44. http://dx.doi.org/10.1007/s13202-021-01132-2.
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AbstractA substantial proportion of proven oil and gas reserves of the world is contained in the carbonate reservoir. It is estimated that about 60% of the world’s oil and 40% of gas reserves are confined in carbonate reservoirs. Exploration and development of hydrocarbons in carbonate reservoirs are much more challenging due to poor seismic imaging and reservoir heterogeneity caused by diagenetic changes. Evaluation of carbonate reservoirs has been a high priority for researchers and geoscientists working in the petroleum industry mainly due to the challenges presented by these highly heterogeneous reservoir rocks. It is essential for geoscientists, petrophysicists, and engineers to work together from initial phases of exploration and delineation of the pool through mature stages of production, to extract as much information as possible to produce maximum hydrocarbons from the field for the commercial viability of the project. In the absence of the well-log data, the properties are inferred from the inversion of seismic data alone. In oil and gas exploration and production industries, seismic inversion is proven as a tool for tracing the subsurface reservoir facies and their fluid contents. In this paper, seismic inversion demonstrates the understanding of lithology and includes the full band of frequency in our initial model to incorporate the detailed study about the basin for prospect evaluation. 3D seismic data along with the geological & petrophysical information and electrologs acquired from drilled wells are used for interpretation and inversion of seismic data to understand the reservoir geometry and facies variation including the distribution of intervening tight layers within the Miocene carbonate reservoir in the study area of Central Luconia. The out-come of the seismic post-stack inversion technique shows a better subsurface lithofacies and fluid distribution for delineation and detailed study of the reservoir.
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Liu, Xiaoping, Zhijun Jin, Guoping Bai, Jie Liu, Ming Guan, Qinghua Pan, and Ting Li. "A comparative study of salient petroleum features of the Proterozoic–Lower Paleozoic succession in major petroliferous basins in the world." Energy Exploration & Exploitation 35, no. 1 (December 11, 2016): 54–74. http://dx.doi.org/10.1177/0144598716680308.
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The Proterozoic–Lower Paleozoic marine facies successions are developed in more than 20 basins with low exploration degree in the world. Some large-scale carbonate oil and gas fields have been found in the oldest succession in the Tarim Basin, Ordos Basin, Sichuan Basin, Permian Basin, Williston Basin, Michigan Basin, East Siberia Basin, and the Oman Basin. In order to reveal the hydrocarbon enrichment roles in the oldest succession, basin formation and evolution, hydrocarbon accumulation elements, and processes in the eight major basins are studied comparatively. The Williston Basin and Michigan Basin remained as stable cratonic basins after formation in the early Paleozoic, while the others developed into superimposed basins undergone multistage tectonic movements. The eight basins were mainly carbonate deposits in the Proterozoic–early Paleozoic having different sizes, frequent uplift, and subsidence leading to several regional unconformities. The main source rock is shale with total organic carbon content of generally greater than 1% and type I/II organic matters. Various types of reservoirs, such as karst reservoir, dolomite reservoir, reef-beach body reservoirs are developed. The reservoir spaces are mainly intergranular pore, intercrystalline pore, dissolved pore, and fracture. The reservoirs are highly heterogeneous with physical property changing greatly and consist mainly of gypsum-salt and shale cap rocks. The trap types can be divided into structural, stratigraphic, lithological, and complex types. The oil and gas reservoir types are classified according to trap types where the structural reservoirs are mostly developed. Many sets of source rocks are developed in these basins and experienced multistage hydrocarbon generation and expulsion processes. In different basins, the hydrocarbon accumulation processes are different and can be classified into two types, one is the process through multistage hydrocarbon accumulation with multistage adjustment and the other is the process through early hydrocarbon accumulation and late preservation.
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Ahmadi, Mohammad Ali. "Connectionist approach estimates gas–oil relative permeability in petroleum reservoirs: Application to reservoir simulation." Fuel 140 (January 2015): 429–39. http://dx.doi.org/10.1016/j.fuel.2014.09.058.
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Zhou, Lihong, Yong Li, Fengming Jin, Lixin Fu, Xiugang Pu, Lou Da, Hongjun Li, Haitao Liu, and Weikai Xu. "Tight Sandstone Reservoir Formation Mechanism of Upper Paleozoic Buried Hills in the Huanghua Depression, Bohai Bay Basin, Eastern China." Minerals 11, no. 12 (December 3, 2021): 1368. http://dx.doi.org/10.3390/min11121368.
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Carboniferous-Permian petroleum resources in the Huanghua Depression of the Bohai Bay Basin, a super petroleum basin, are important exploration successor targets. The reservoir sedimentary environment of coal measures in the Upper Paleozoic buried hills is variable, and the structural evolution process is complicated, which restricts the optimization of targeting sections. Using the analysis and testing results of logging, thin section, porosity, mercury injection, hydrochemistry, and basin simulation, this study revealed the formation mechanism differences of tight sandstones in the Upper Paleozoic period in different buried hills. The results show that the sandstones are mainly feldspathic sandstone, lithic arkose, feldspathic lithic sandstone, and feldspathic lithic quartz sandstone. The quartz content varies between 25% and 70%, averaging 41%. Feldspar and debris are generally high, averaging 31% and 28%, respectively. Secondary dissolution pores are the main reservoir spaces, with 45% of the tested samples showing porosity of 5–10%, and 15% being lower than 5%. The pore radium is generally lower than 100 nm, and the sandstones are determined as small pore with fine throat and medium pore with fine throat sandstones by mercury saturation results. Frequent changing sedimentary environments and complex diagenetic transformation processes both contribute to the reservoir property differences. The former determines the original pore space, and the latter determines whether they can be used as effective reservoirs by controlling the diagenetic sequences. Combining tectonic movement background and different fluid history, the different formation mechanisms of high-porosity reservoirs are recognized, which are atmospheric leaching dominated (Koucun buried hills), atmospheric water and organic acid co-controlled (Wangguantun and Wumaying buried hills), and organic acid dominated (Nandagang buried hills) influences. The results can be beneficial for tight gas exploration and development in coal measures inside clastic buried hills in the Bohai Bay Basin.