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1
Cui, Guodong, Zheng Niu, Zhe Hu, Xueshi Feng, and Zehao Chen. "The Production Analysis and Exploitation Scheme Design of a Special Offshore Heavy Oil Reservoir—First Offshore Artificial Island with Thermal Recovery." Journal of Marine Science and Engineering 12, no. 7 (July 15, 2024): 1186. http://dx.doi.org/10.3390/jmse12071186.
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More and more offshore heavy oil resources are discovered and exploited as the focus of the oil and gas industry shifts from land to sea. However, unlike onshore heavy oil reservoirs, offshore heavy oil reservoirs not only have active edge and bottom water but also have different exploitation methods. In this paper, a typical special heavy oil reservoir in China was analyzed in detail, based on geology–reservoir–engineering integration technology. Firstly, it is identified as a self-sealing bottom water heavy oil reservoir by analyzing its geological characteristics and hydrocarbon accumulation mechanism. Secondly, the water cut is initially controlled by oil viscosity, but subsequently, by reservoir thickness through the analysis of oil and water production data. Thirdly, the bottom oil–water contact of the reservoir was re-corrected to build an accurate 3D geological model, based on the production history matching of a single well and the whole reservoir. Lastly, a scheme of thermal production coupled with cold production was proposed to exploit this special reservoir, and the parameters of steam, N2, and CO2 injection and production were optimized to predict oil production. This work can provide a valuable development model for the efficient exploitation of similar offshore special heavy oil reservoirs.
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Amer, Manar M., and Dahlia A. Al-Obaidi. "Methods Used to Estimate Reservoir Pressure Performance: A Review." Journal of Engineering 30, no. 06 (June 1, 2024): 83–107. http://dx.doi.org/10.31026/j.eng.2024.06.06.
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Reservoir pressure plays a significant role in all reservoir and production engineering studies. It is crucial to characterize petroleum reservoirs: by detecting fluid movement, computing oil in place, and calculating the recovery factor. Knowledge of reservoir pressure is essential for predicting future production rates, optimizing well performance, or planning enhanced oil recovery strategies. However, applying the methods to investigate reservoir pressure performance is challenging because reservoirs are large, complex systems with irregular geometries in subsurface formations with numerous uncertainties and limited information about the reservoir's structure and behavior. Furthermore, many computational techniques, both numerical and analytical, have been utilized to examine reservoir pressure performance. This paper summarizes the concepts and applications of traditional and novel ways to investigate reservoir pressure changes over time. It provides a comprehensive review that assists the reader in recognizing and distinguishing between various techniques for obtaining an accurate description of reservoir pressure behavior during production, such as the reservoir simulation method, material balance equation approach, time-lapse seismic data, and modern artificial intelligence methods. Thus, the central concept of these procedures and a list of the authors' research are discussed.
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Hoffman, Monty, and James Crafton. "Multiphase flow in oil and gas reservoirs." Mountain Geologist 54, no. 1 (January 2017): 5–14. http://dx.doi.org/10.31582/rmag.mg.54.1.5.
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The porous rocks that make up oil and gas reservoirs are composed of complex combinations of pores, pore throats, and fractures. Pore networks are groups of these void spaces that are connected by pathways that have the same fluid entry pressures. Any fluid movement in pore networks will be along the pathways that require the minimum energy expenditure. After emplacement of hydrocarbons in a reservoir, fluid saturations, capillary pressure, and energy are in equilibrium, a significant amount of the reservoir energy is stored at the interface between the fluids. Any mechanism that changes the pressure, volume, chemistry, or temperature of the fluids in the reservoir results in a state of energy non-equilibrium. Existing reservoir engineering equations do not address this non-equilibrium condition, but rather assume that all reservoirs are in equilibrium. The assumption of equilibrium results in incorrect descriptions of fluid flow in energy non-equilibrium reservoirs. This, coupled with the fact that drilling-induced permeability damage is common in these reservoirs, often results in incorrect conclusions regarding the potential producibility of the well. Relative permeability damage, damage that can change which fluids are produced from a hydrocarbon reservoir, can occur even in very permeable reservoirs. Use of dependent variables in reservoir analysis does not correctly describe the physics of fluid flow in the reservoir and will lead to potentially incorrect answers regarding producibility of the reservoir.
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Taggart, I. J., and H. A. Salisch. "FRACTAL GEOMETRY, RESERVOIR CHARACTERISATION AND OIL RECOVERY." APPEA Journal 31, no. 1 (1991): 377. http://dx.doi.org/10.1071/aj90030.
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Reservoir heterogeneity is a dominant factor in determining large-scale fluid flow behaviour in reservoirs. Engineering estimates of oil production rates need to acknowledge and incorporate the effect of such heterogeneities. This work examines the use of fractal-based scaling techniques aimed at characterising heterogeneous reservoirs for simulation purposes. Well log data provide suitable fine-scale information for estimating the fractal dimension of reservoirs as well as providing known end- point data for interwell property value interpolation. Fractal techniques allow this interpolation to be performed in a manner which reproduces the same correlation structure as that found in the original well logs. Conditional simulation in these property fields allows the interaction between reservoir heterogeneity and fluid flow to be studied on a range of scales up to the interwell spacing. Analysis of results allows the calculation of effective reservoir properties which characterise the reservoir in terms of large-scale performance.
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Pierpont, Rob, Kristoffer Birkeland, Alexandra Cely, Tao Yang, Li Chen, Vladislav Achourov, Soraya S. Betancourt, et al. "Enigmatic Reservoir Properties Deciphered Using Petroleum System Modeling and Reservoir Fluid Geodynamics." Petrophysics – The SPWLA Journal of Formation Evaluation and Reservoir Description 64, no. 1 (February 1, 2023): 6–17. http://dx.doi.org/10.30632/pjv64n1-2023a1.
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Two adjacent reservoirs in offshore oil fields have been evaluated using extensive data acquisition across multiple disciplines; several surprising observations were made. Differing levels of biodegradation were measured in the nearly adjacent reservoirs, yet related standard geochemical markers are contradictory. Unexpectedly, the more biodegraded oil had less asphaltene content, and this reservoir had some heavy end deposition in the core but upstructure, not at the oil-water contact (OWC) as would be expected, especially with biodegradation. Wax appears to be an issue in the nonbiodegraded oil. These many puzzling observations, along with unclear connectivity, gave rise to uncertainties about field development planning. Combined petroleum systems and reservoir fluid geodynamic considerations resolved the observations into a single, self-consistent geo-scenario, the co-evolution of reservoir rock and fluids in geologic time. A spill-fill sequence of trap filling with biodegradation helps explain differences in biodegradation and wax content. A subsequent, recent charge of condensate, stacked in one fault block and mixed in the target oil reservoir in the second fault block, explains conflicting metrics of biodegradation between C7 vs. C16 indices. Asphaltene instability and deposition at the upstructure contact between the condensate and black oil, and the motion of this contact during condensate charge, explain heavy end deposition in core. Moreover, this process accounts for asphaltene dilution and depletion in the corresponding oil. Downhole fluid analysis (DFA) asphaltene gradients and variations in geochemical markers with seismic imaging clarify likely connectivity in these reservoirs. The geo-scenario provides a benchmark of comparison for all types of reservoir data and readily projects into production concerns. The initial apparent puzzles of this oil field have been resolved with a robust understanding of the corresponding reservoirs and development strategies.
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Carpenter, Chris. "Study Reviews Technologies, Work Flows in Heavy Oil Reservoir Management." Journal of Petroleum Technology 75, no. 04 (April 1, 2023): 79–81. http://dx.doi.org/10.2118/0423-0079-jpt.
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_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 209328, “Heavy Oil Reservoir Management—Latest Technologies and Work Flows,” by Hakki Aydin, SPE, Middle East Technical University; Nirup Nagabandi, Incendium Technologies; and Cenk Temizel, SPE, Saudi Aramco, et al. The paper has not been peer reviewed. _ Successful heavy oil reservoir management practices are built on analyzing and accurately predicting reservoir behavior over time. Given the complex nature of heavy oil reservoirs, including geomechanical properties and fluid-flow behavior, a need exists to develop a repeatable technique that can account for these complexities within an acceptable margin of accuracy. The objective of the complete paper is to conduct a comprehensive review of recent technologies and work flows developed for heavy oil reservoir management that can be used as a single source of reference for the industry. Introduction Because of its comprehensive nature, much of the complete paper is dedicated to a review of the characteristics of heavy oil reservoirs and their exploitation, including thermal and nonthermal methods and the literature dedicated thereto. This synopsis will concentrate on the authors’ reviews of work flows to manage these reservoirs and field applications of the methodologies they review. Work Flow for Heavy Oil Reservoir Management Reservoir management is a multidisciplinary field involving detailed analysis of geosciences such as reservoir engineering, geological engineering, and petrophysics. Evaluation of geological information and fluid properties helps to understand the distribution of heavy oil in the reservoir. Understanding the characteristics of heavy oil reservoirs is essential for selecting the appropriate enhanced oil recovery (EOR) method. Reservoir-surveillance techniques play a critical role in understanding complex systems. Statistical approaches might be required to handle extensive data sets of production history and petrophysical data. The main goal of the reservoir management team in thermal EOR methods is to optimize parameters in steam-injection projects to maximize recovery rates from heavy oil reservoirs. The important parameters influencing the success of thermal projects include injection rates and pressures, preferential steam paths, well profiles, and reservoir depth. Previous work has presented a work flow for optimizing steamfloods in Oman. The work flow involves a review of production and injection history, petrophysical properties, and geological descriptions. Steam/oil ratio was used as a key performance indicator for steam management; it is defined as barrels of steam injected for 1 bbl of additional oil production. The steam breakthrough was monitored from the wellhead flowing temperature of the producer wells. A sudden increase in wellhead temperature is associated with a steam breakthrough. The permeability map of the reservoir helps to select appropriate injectors for a steamflood. High-permeability wells might lead to fingering, causing less recovery. Vertical conformance is desired to achieve oil sweep with steam. Observation wells are the controlling stations of steamflooding efficiency. It is critical to place the observation wells in heterogeneous reservoirs. Geophysical methods also are applied for surveillance of steam-injection projects. Real-time surveillance plays a critical role in the optimization of heavy oil reservoirs. The authors describe a modeling technique called Production Universe (PU) that enables operators to estimate oil and water production in real time. PU is effective at finding the offending well in case of sudden changes in field-level production. PU provides an automated daily production and deferment report that guides analysts to identify low-efficiency wells for remedial operations.
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Xia, Zhizeng, Xuewu Wang, Rui Xu, and Weiwei Ren. "Tight oil reservoir production characteristics developed by CO2 huff ‘n’ puff under well pattern conditions." Journal of Petroleum Exploration and Production Technology 12, no. 2 (January 9, 2022): 473–84. http://dx.doi.org/10.1007/s13202-021-01446-1.
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AbstractTight oil reservoirs have poor physical properties, and the problems including rapid oil rate decline and low oil recovery degree are quite common after volume fracturing. To obtain a general understanding of tight oil reservoir production improvement by CO2 huff ‘n’ puff, the high-pressure physical properties of typical tight oil samples are measured. Combining the typical reservoir parameters, the production characteristics of the tight oil reservoir developed by the CO2 huff ‘n’ puff are numerically studied on the basis of highly fitted experimental results. The results show that: (1) during the natural depletion stage, the oil production rate decreases rapidly and the oil recovery degree is low because of the decrease in oil displacement energy and the increase in fluid seepage resistance. (2) CO2 huff ‘n’ puff can improve the development effect of tight oil reservoirs by supplementing reservoir energy and improving oil mobility, but the development effect gradually worsens with increasing cycle number. (3) The earlier the CO2 injection timing is, the better the development effect of the tight reservoir is, but the less sufficient natural energy utilization is. When carrying out CO2 stimulation, full use should be made of the natural energy, and the appropriate injection timing should be determined by comprehensively considering the formation-saturation pressure difference and oil production rate. The research results are helpful for strengthening the understanding of the production characteristics of tight oil reservoirs developed by CO2 huff ‘n’ puff.
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Cheng, Hong. "The Enhanced Oil Recovery Effect of Nitrogen-Assisted Gravity Drainage in Karst Reservoirs with Different Genesis: A Case Study of the Tahe Oilfield." Processes 11, no. 8 (August 2, 2023): 2316. http://dx.doi.org/10.3390/pr11082316.
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For the Tahe Oilfield, there are multiple sets of karst reservoirs with different genesis developed in carbonate fracture-vuggy reservoirs and the varying karst reservoir type has a considerable influence on the distribution of residual oil. The complex characteristics of different karst reservoirs and the difficulty in producing the remaining oil in the middle and lower part of the reservoir greatly restrict the recovery effects. This work managed to comprehensively investigate the action mechanism of nitrogen-assisted gravity drainage (NAGD) on remaining oil in reservoirs with different karst genesis through modeling and experiments. Based on geological characteristics and modeling results, a reservoir-profile model considering reservoir type, fracture distribution, and the fracture–cave combination was established, the displacement experiments of main reservoirs such as the epikarst zone, underground river, and fault karst were carried out, and the oil–gas–water multiphase flow was visually analyzed. The remaining oil state before and after NAGD was studied, and the difference in recovery enhancement in different genetic karst reservoirs was quantitatively compared. The results show that NAGD was helpful in enhancing oil recovery (EOR) for reservoirs with different karst genesis. NAGD technique has the greatest increasing effect on the sweep efficiency of the fault-karst reservoir, followed by the epikarst zone reservoir, and the smallest in the underground river reservoir. The results of this research will facilitate an understanding of the EOR effect of karst-reservoir types on NAGD and provide theory and technical support for the high-efficiency development in varying karst reservoirs in the Tahe Oilfield.
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Li, Bing, and Lei Zhao. "Water Injection Proposal for Block 5 Oilfield to Increase Oil Reserves." Advanced Materials Research 1073-1076 (December 2014): 2316–20. http://dx.doi.org/10.4028/www.scientific.net/amr.1073-1076.2316.
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This article revises the low pressure reservoir Block 5 controlled by structure trap located in South China Sea and analyses the current situations of the reservoir including G&G and reservoir engineering. The results indicate that down-dip wells already located in the water which was original oil based on new study and now could be converted to injector to increase oil reserves. Finally according to the study, the same method can be used in the similar reservoirs.
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Zhang, Lei, and Guo Ming Liu. "Analysis Development Status of A12 Reservoir." Advanced Materials Research 650 (January 2013): 664–66. http://dx.doi.org/10.4028/www.scientific.net/amr.650.664.
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A12 oil and gas reservoirs in L Oilfield Carboniferous carbonate rocks of oil and gas bearing system, saturated with the gas cap and edge water and bottom water reservoir. The A12 oil and gas reservoir structure the relief of the dome-shaped anticline, oil, gas and water distribution controlled by structure, the gas interface -2785 meters above sea level, the oil-water interface altitude range -2940 ~-2980m, average-2960m. Average reservoir thickness of 23m, with a certain amount of dissolved gas drive and gas cap gas drive energy, but not very active edge and bottom water, gas cap drive index.
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Wang, Chao, Guang Fu, and Ying Jie Dong. "Fault Control on Hydrocarbon Accumulation in South Beier Sag." Advanced Materials Research 868 (December 2013): 202–6. http://dx.doi.org/10.4028/www.scientific.net/amr.868.202.
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In order to research the relationship between the fracture and reservoir in the south beier sag, using the method of integrating theory with practice, Through research fracture development and system partition and anatomy of the reservoir shows that the fracture on the formation of the reservoirs mainly the following two aspects, First,the fracture provides migration conditions for oil and gas namely 1 early extend fracture make 1st member of Nantun group surcerock and the south 2nd member of Nantun group reservoir side joint, which is beneficial to oil lateral migration; 2 the long-term development fracture for secondary reservoir formation provides favorable conducting channel; Second, Fracture provides shield condition for oil and gas accumulation, namely 1 reverse fault "back on" low uplift area native reservoir accumulation are controlled; 2 reverse fault - fan control assembled parts of the secondary hydrocarbon reservoirs.
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Turta, A. T., and A. K. Singhal. "Reservoir Engineering Aspects of Light-Oil Recovery by Air Injection." SPE Reservoir Evaluation & Engineering 4, no. 04 (August 1, 2001): 336–44. http://dx.doi.org/10.2118/72503-pa.
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Summary This paper addresses the reservoir engineering aspects of air injection as an enhanced oil recovery technique for light-oil reservoirs. In its most successful form, the process has been applied in deep, carbonate reservoirs. The development of this process in conjunction with an application of the in-situ combustion (ISC) process to light-oil reservoirs, as well as the main mechanisms pertaining to ISC and to gas miscible flooding, are analyzed. It is seen that various air-injection processes (AIP's) can be classified, depending on their spontaneous ignition potential and gas miscibility at reservoir conditions, into four different processes. Based on an in-depth literature review, the best reservoir conditions for application of each of these four processes are derived. The main differences in operational aspects (pollution, corrosion, safety) for these processes are also discussed. Design considerations for pilot testing of the technique are presented. The crucial point is location of the pilot on the structure, which is also a key element in its proper evaluation, and its subsequent development to a commercial-size operation. Finally, recommendations on laboratory work in support of design and evaluation of a field pilot are also presented. Introduction AIP's comprise those oil recovery processes that occur naturally when air is injected in an oil reservoir. The ISC process is one variation of air injection. Although the focus of this paper is not on ISC, the experience gained from ISC is used whenever relevant. ISC is an AIP, but the reverse is not true; some AIP's cannot be considered as ISC processes at all. Usually, the application of the ISC process is associated with the existence of a high peak temperature (350 to 600°C) or an ISC front that travels from injection to production wells. On the other hand, the application of an AIP does not necessarily assume the existence of a high peak temperature. In other words, application of ISC sometimes requires an ignition operation to initiate it (create the heat wave), while the application of an AIP does not. The ISC does not appear feasible in low-porosity matrix reservoirs; the porosity requirement is directly related to heat losses within the matrix. However, if the intent of air injection is merely pressure maintenance, the air injection should still be feasible, either as a miscible or an immiscible gas displacement process. Because the composition of air/flue gases, or a mixture of nitrogen with hydrocarbons in the vapor phase, is closer (from the miscibility point of view) to that of nitrogen, the miscibility of nitrogen can be a starting point in analyzing the feasibility of AIP's; this is illustrated in this paper. Generally, if the miscibility with nitrogen cannot be achieved, only an immiscible gas displacement needs to be evaluated. This paper analyzes the main reservoir engineering aspects of air-injection application through a new classification based on the main mechanisms of ISC and miscible flooding, as well as in light of limited experience gained from airflooding light and very light-oil reservoirs. Air-Injection-Based Oil-Recovery Processes Air-injection-based oil-recovery processes were evaluated based on the screening criteria for improved-oil-recovery (IOR) processes used in the software program PRIze™, a package that evaluates the IOR potential of oil reservoirs.1 Basically, the screening criteria for application of ISC, gas miscible flooding, and immiscible gasflooding were used. When air is injected into an oil reservoir, two simultaneous phenomena occur: displacement of oil and oxidation of oil. According to the efficiency of displacement and the intensity of oxidation, four main types of processes can occur.Immiscible Airflooding (IAF) with High Temperature Oxidation (HTO)IAF with Low Temperature Oxidation (LTO)Miscible Airflooding (MAF) with HTOMAF with LTO The last two processes are commonly known as high pressure air injection (HPAI) processes. Depending on the intensity of oxidation, either the LTO or the HTO reactions can dominate development of the process. Actually, when HTO takes place in immiscible airflooding, the classic ISC process is obtained, while if only LTO takes place, the process is called LTO-IAF (LTO combined with IAF). The LTO-IAF was unintentionally obtained while attempting ISC, either when the ignition operation was not successful or when it was successful, but the ISC front did not sustain itself. Therefore, this kind of process has been applied only for relatively viscous oils. So far, the LTO-IAF process has not proved to be an effective IOR process (as compared to the ISC process). As a matter of fact, it seems to be the least efficient one among the four possible combinations. Stoichiometrically, the volume of gases produced during an HTO process is roughly the same as that of air injected; hence, the oxidation reactions do not significantly impact pressure maintenance. For an LTO process, a part of oxygen is consumed without releasing carbon oxides, leading to a shrinkage of the injected gas volume. Consequently, benefits of pressurization are somewhat less for this process, and some over injection may be considered. Air injection can be used in both horizontal and vertical flooding. In a vertical flood, air is injected at the top of the structure (which may be a reef), and oil is produced from lower intervals, taking full advantage of gravity. This way, the volumetric sweep efficiency and displacement efficiency are aided by natural forces and are usually extremely efficient. In the hydrocarbon miscible flood, field experience has indicated incremental oil recovery using a vertical flood to be of the order of 30% original oil in place (OOIP), whereas for horizontal floods, the incremental oil recovery is typically 10% OOIP. A similar difference in the magnitude of oil recovery is expected for the application of air injection in these two modes. A typical horizontal immiscible gas injection can increase the ultimate oil recovery by up to 5 to 6% OOIP. For a vertical immiscible flood, this increment is expected to be much higher. In general, the IAF is expected to increase the ultimate oil recovery by at least as much as that obtained during immiscible flooding with such gases as nitrogen, flue gas, or hydrocarbon gas. For cases where a combination of extensive fracturing and unfavorable mobility ratio between air and oil causes severe channeling, horizontal gasflooding may not be a viable option. However, gas injection at the top of the reservoir with velocities of displacement lower than the critical velocity may still be feasible. It is expected that the oxygen contained in the injected air will not appear at the production well; rather, it will be consumed by reacting with the oil (oxygen uptake). Following gas breakthrough, the produced gas will consist mainly of nitrogen and hydrocarbon gases. This is true for most oil reservoirs, even in cases where air injection is accompanied by LTO, so long as heterogeneity is not too high.
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Lyu, Qixia, Weiming Wang, Qingchun Jiang, Haifeng Yang, Hai Deng, Jun Zhu, Qingguo Liu, and Tingting Li. "Basement Reservoirs in China: Distribution and Factors Controlling Hydrocarbon Accumulation." Minerals 13, no. 8 (August 9, 2023): 1052. http://dx.doi.org/10.3390/min13081052.
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The oil reserves of global basement reservoirs are 248 × 108 t and natural gas reserves are 2681 × 108 m3; they are crucial links in the future oil and natural gas exploration field and play an irreplaceable role in increasing oil and natural gas reserves and production. Based on research on the definition and classification of basement reservoirs, this study dissected three major basement reservoirs in China (i.e., the Dongping region located in the Qaidam Basin, the Bozhong 19-6 gas field located the Bohai Bay Basin, and the Central Uplift area of the Songliao Basin). The geological conditions and controlling factors of oil and natural gas accumulation in basement reservoirs in China are summarized. The results of this study are as follows: (1) Basement reservoirs can be classified into three distinct types, namely, the weathered carapace type, weathered inner type, and weathered composite type. They are characterized by a large burial depth, strong concealment, and huge reserves and are mostly distributed at the margins of continental plates and in zones with stratum intensive tectonic activity; (2) Basement reservoirs in different basins have different controlling factors. The basement reservoir in the Dongping region, located in the Qaidam Basin, has favorable geological conditions with laterally connected sources and reservoirs. In this reservoir, oil and natural gas have transferred along faults and unconformities to accumulate in uplifted areas, forming a weathered carapace-type basement reservoir controlled by structures. The Bozhong 19-6 gas field, which is situated in the Bohai Bay Basin, has favorable multiple hydrocarbon supplies of source rocks. Under the communication of faults and cracks, oil resources form a weathered inner type basement reservoir. In the Central Uplift area of the Songliao Basin, the basement reservoir exhibits a dual-sided hydrocarbon supply condition from the uplift. In this reservoir, oil and natural gas have transferred to traps through the fault and inner fracture system and have been properly preserved thanks to the extensive overlying cap rocks. It can be concluded that, after being attenuated by millions of years of weathering and leaching, basement rocks can form large-scale and medium-scale basement reservoirs with reserves of more than 100 million barrels in the presence of favorable geological conditions, such as a multi-directional hydrocarbon supply, a high brittle mineral content in the reservoirs, diverse reservoir spaces, and high-quality cap rocks.
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Wang, Peng-Tao, Xi Wu, Gangke Ge, Xiaoyan Wang, Mao Xu, Feiyin Wang, Yang Zhang, Haifeng Wang, and Yan Zheng. "Evaluation of CO2 enhanced oil recovery and CO2 storage potential in oil reservoirs of petroliferous sedimentary basin, China." Science and Technology for Energy Transition 78 (2023): 3. http://dx.doi.org/10.2516/stet/2022022.
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Carbon Capture, Utilization, and Storage (CCUS) technology has emerged as the bottom-line technology for achieving carbon neutrality goals in China. The development of Carbon Dioxide Enhanced Oil Recovery (CO2-EOR) not only increases revenue for high-investment CCUS projects but also enables permanent CO2 storage in the oil reservoir. However, the basin is used as the research object to evaluate the CO2 storage potential of the oil reservoir. The evaluation results are inaccurate and unable to support the implementation of later CCUS projects. Here, more accurate oil reservoir data is employed as the evaluation object. It is the first time at the national level to screen oil reservoirs to distinguish between CO2 miscible and immiscible, and evaluate the potential of CO2-EOR and CO2 storage in the reservoir. The research results show a total of 2570 suitable oil reservoirs in 4386 candidate oil reservoirs nationwide. About 1.26 billion tons of additional crude oil can be produced by CO2-EOR technology. This includes approximately 580 million tons of additional oil from CO2 miscible flooding and 680 million tons from CO2 immiscible flooding. The study further refines the CO2 geological utilization data and provides a theoretical basis for CCUS project site selection in China.
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Ypma, J. G. J. "Analytical and Numerical Modeling of Immiscible Gravity-Stable Gas Injection Into Stratified Reservoirs." Society of Petroleum Engineers Journal 25, no. 04 (August 1, 1985): 554–64. http://dx.doi.org/10.2118/12158-pa.
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Abstract A two-dimensional (2D) analytical model is presented for gas/oil gravity drainage in a homogeneous, dipping reservoir. The sensitivity of gas/oil gravity drainage to key variables such as injection rate, oil relative permeability, and permeability anisotropy can be determined quickly with this model. Example calculations show that miscible-like recovery efficiencies are possible with immiscible gas injection into high-permeability dipping reservoirs with light oil. A procedure based on the analytical model has been developed to simulate immiscible gas injection into highly stratified reservoirs accurately. This simulation procedure allows a great deal of geological detail to be incorporated into reservoir models, because it permits relatively coarse grids. Application of the simulation procedure to a reservoir containing many discontinuous shales reveals that the presence of shales may favorably affect the recovery efficiency of an immiscible gas-injection process. Introduction Gas injection increasingly is being applied as a secondary or tertiary recovery process. High-permeability, light-oil reservoirs with a reasonable reservoir dip are particularly suitable candidates for gas injection. In these reservoirs, a gravity-stable injection scheme is often possible, leading to high sweep efficiencies. If the injection process is carried out at sufficiently high pressure, process is carried out at sufficiently high pressure, favorable phase behavior between reservoir fluid and injection gas can contribute significantly to the recovery of oil. Miscibility, however, is by no means always necessary to obtain high displacement efficiencies. Even in the case of an entirely immiscible displacement, a high displacement efficiency is possible if gravity drainage is the dominant production mechanism. Laboratory experiments have shown that, the residual oil saturation after gas invasion, is virtually zero in highly permeable sandstone cores containing connate water. The ultimate recovery of an immiscible process is then close to 100%. Whether oil saturations process is then close to 100%. Whether oil saturations in the gas-invaded zone will approach the residual value within the lifetime of a particular reservoir depends on the rate of gravity drainage for this reservoir. This problem, which is the main subject of this paper, has been studied by both analytical means and numerical simulation. In the following, first a 2D analytical model is introduced for gas/oil gravity drainage in a homogeneous, dipping reservoir. The model combines aspects from both one-dimensional (1D) vertical Buckley-Leverett drainage theory and Dietz' segregated flow theory for dipping reservoirs. Assumptions underlying the model have been verified by 2D cross-sectional simulations. Second, a procedure based on the analytical gravity-drainage procedure based on the analytical gravity-drainage model has been developed to simulate immiscible secondary gas injection into a highly stratified reservoir accurately. This is illustrated with an example of gas injection into a reservoir containing discontinuous shale layers. Analytical Model for Gravity Drainage Description of the Model. In this section, an approximate analytical model is formulated for immiscible, gravity-stable gas/oil displacement in a homogeneous, dipping layer. Fig. 1 shows a schematic cross section of the draining reservoir with some relevant flow characteristics. In this model, oil is assumed to be produced from downdip wells near the oil/water contact at a rate that ensures a gravity-stable displacement, while gas is injected in updip wells near the crest to fill the voidage. This causes the gas/oil contact (GOC) to move downward gradually. Behind the GOC some oil will be left, the amount of which depends on the oil relative permeability and on the tilt and rate of descent of the GOC. The gas-invaded region will continue to produce oil by after-drainage; this oil will collect at the bottom of the reservoir in a thin oil layer, which flows to the producers with the along-dip component of gravity as driving force. To make the essentially 2D model amenable to analytical calculation, the following assumptions are introduced.The model has infinite gas mobility.The model has negligible gas/oil capillary pressure. pressure.The GOC moves at a constant velocity, v GOC, x, and at a constant tilt angle, given by Dietz' theory for gravity-stable segregated flow in dipping reservoirs (evaluated for infinite gas mobility) as.............(1)with u max, x being the maximum along-dip gravity drainage ratei.e., in the direction of bulk fluid flow. This rate is defined as..............(2) SPEJ p. 554
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Chen, Lixin, Zhenxue Jiang, Chong Sun, Bingshan Ma, Zhou Su, Xiaoguo Wan, Jianfa Han, and Guanghui Wu. "An Overview of the Differential Carbonate Reservoir Characteristic and Exploitation Challenge in the Tarim Basin (NW China)." Energies 16, no. 15 (July 25, 2023): 5586. http://dx.doi.org/10.3390/en16155586.
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The largest marine carbonate oilfield and gas condensate field in China have been found in the Ordovician limestones in the central Tarim Basin. They are defined as large “layered” reef-shoal and karstic reservoirs. However, low and/or unstable oil/gas production has been a big challenge for effective exploitation in ultra-deep (>6000 m) reservoirs for more than 20 years. Together with the static and dynamic reservoir data, we have a review of the unconventional characteristics of the oil/gas fields in that: (1) the large area tight matrix reservoir (porosity less than 5%, permeability less than 0.2 mD) superimposed with localized fracture-cave reservoir (porosity > 5%, permeability > 2 mD); (2) complicated fluid distribution and unstable production without uniform oil/gas/water interface in an oil/gas field; (3) about 30% wells in fractured reservoirs support more than 80% production; (4) high production decline rate is over 20% per year with low recovery ratio. These data suggest that the “sweet spot” of the fractured reservoir rather than the matrix reservoir is the major drilling target for ultra-deep reservoir development. In the ultra-deep pre-Mesozoic reservoirs, further advances in horizontal drilling and large multiple fracturing techniques are needed for the economic exploitation of the matrix reservoirs, and seismic quantitative descriptions and horizontal drilling techniques across the fault zones are needed for oil/gas efficient development from the deeply fractured reservoirs.
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Lawal, Kazeem A., Asekhame U. Yadua, Mathilda I. Ovuru, Oluchukwu M. Okoh, Stella I. Eyitayo, Saka Matemilola, and Olugbenga Olamigoke. "Rapid screening of oil-rim reservoirs for development and management." Journal of Petroleum Exploration and Production Technology 10, no. 3 (December 2, 2019): 1155–68. http://dx.doi.org/10.1007/s13202-019-00810-6.
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AbstractAs an improvement over existing screening techniques, we introduce the relative mobile energy of primary gas-cap to the aquifer (Egw) as a new parameter for characterizing the performance of oil-rim reservoirs. Egw integrates key static and dynamic reservoir properties. To account for the time value of production, the framework allows maximizing the discounted recovery factor (DRF) of oil, gas or total hydrocarbon as the objective function. Employing detailed simulations of different well-defined oil-rim models, DRFs of oil, gas and total hydrocarbons have been correlated against Egw for common development concepts and well types. These correlations have resulted in a new screening technique for both green and brown oil-rim reservoirs. In addition to presenting simple generic charts for quick evaluation of oil-rim reservoirs, the main contributions of this work include the introduction of Egw as a new performance-characterizing parameter, and the flexibility to consider the DRF of any of oil, gas or total hydrocarbon as the basis for screening an oil-rim reservoir for development planning and field management. Using the example of a brown oil-rim reservoir, the applicability and robustness of the new screening technique are demonstrated.
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Kharrat, Riyaz, and Holger Ott. "A Comprehensive Review of Fracture Characterization and Its Impact on Oil Production in Naturally Fractured Reservoirs." Energies 16, no. 8 (April 13, 2023): 3437. http://dx.doi.org/10.3390/en16083437.
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Naturally fractured reservoirs are indescribable systems to characterize and difficult to produce and forecast. For the development of such reservoirs, the role of naturally forming fractures in the different development stages needs to be recognized, especially for the pressure maintenance and enhanced oil recovery stages. Recent development in the field of naturally carbonate fractured aimed at fracture characterization, fracture modeling, and fracture network impact of fracture networks on oil recovery were reviewed. Consequently, fracture identification and characterization played pivotal roles in understanding production mechanisms by integrating multiple geosciences sources and reservoir engineering data. In addition, a realistic fracture modeling approach, such as a hybrid, can provide a more accurate representation of the behavior of the fracture and, hence, a more realistic reservoir model for reservoir production and management. In this respect, the influence of different fracture types present in the reservoir, such as major, medium, minor, and hairline fractures networks, and their orientations were found to have different rules and impacts on oil production in the primary, secondary, and EOR stages. In addition, any simplification or homogenization of the fracture types might end in over or underestimating the oil recovery. Improved fracture network modeling requires numerous considerations, such as data collection, facture characterization, reservoir simulation, model calibration, and model updating based on newly acquired field data are essential for improved fracture network description. Hence, integrating multiple techniques and data sources is recommended for obtaining a reliable reservoir model for optimizing the primary and enhanced oil recovery methods.
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Jin, Xin, and Kang Zhang. "Study on enhancing oil recovery by CO2 injection in low permeability reservoir." Advances in Engineering Technology Research 9, no. 1 (December 27, 2023): 159. http://dx.doi.org/10.56028/aetr.9.1.159.2024.
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The distribution characteristics of remaining oil in low permeability reservoirs are aimed at the quantity and distribution of remaining oil in the reservoir at the present stage, so as to take measures to exploit these remaining oil under reasonable economic and technical conditions, so as to improve recovery. The technology of carbon dioxide hubbing and pumping is to inject a certain amount of carbon dioxide into the reservoir under a certain pressure, stew the well for a period of time to make the carbon dioxide spread in the formation and miscible with the formation crude oil, and then open the well for production. At present, there are many methods to study residual oil at home and abroad, mainly including reservoir engineering methods such as logging method, core analysis method, numerical simulation, and dynamic analysis method using monitoring data and dynamic and static data of reservoir. Study the macro and micro residual oil distribution accurately using CO2 huff and huff technology to increase production.
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Wang, Zhongnan, Keyu Liu, Chaoqian Zhang, Haijun Yan, Jing Yu, Biao Yu, Jianliang Liu, Tailiang Jiang, Weidong Dan, and Caizhi Hu. "Integral Effects of Porosity, Permeability, and Wettability on Oil–Water Displacement in Low-Permeability Sandstone Reservoirs—Insights from X-ray CT-Monitored Core Flooding Experiments." Processes 11, no. 9 (September 18, 2023): 2786. http://dx.doi.org/10.3390/pr11092786.
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Porosity, permeability, and wettability are crucial factors that affect the oil–water displacement process in reservoirs. Under subsurface conditions, the integral effects of these factors are extremely difficult to document. In this paper, waterflooding experiments were carried out using a core flooding system monitored with X-ray dual-energy CT. The mesoscale, three-dimensional characteristics of water displacing oil were obtained in real time. The integral effects of porosity, permeability, and wettability on the waterflooding in the low-permeability sandstone reservoirs were investigated. It was found that if the reservoir rock is water-wet, then the residual oil saturation decreases gradually with increasing porosity and permeability, showing an increasing waterflooding efficiency. On the contrary, if the reservoir rock is oil-wet, the residual oil saturation gradually increases with improving porosity and permeability, showing a decreasing waterflooding efficiency. The porosity, permeability, and wettability characteristics of reservoirs should be comprehensively evaluated before adopting technical countermeasures of waterflooding or wettability modification during oilfield development. If the porosity and permeability of the reservoir are high, water-wet reservoirs can be directly developed with waterflooding. However, it is better to make wettability modifications first before the waterflooding for oil-wet reservoirs. If the porosity and permeability of the reservoir are poor, direct waterflooding development has a better effect on oil-wet reservoirs compared with the water-wet reservoirs.
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Potekhin, Denis V., Evgeny O. Shiryaev, and Sergey V. Galkin. "3D-MODELING TECHNOLOGY OF INITIAL OIL SATURATION IN TRANSITIONAL OIL-WATER ZONE BY COMPLEX OF CAPILLARIMETRY AND ELECTRIC LOGGING METHODS." Bulletin of the Tomsk Polytechnic University Geo Assets Engineering 334, no. 10 (October 31, 2023): 98–107. http://dx.doi.org/10.18799/24131830/2023/10/4116.
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Link for citation: Potekhin D.V., Shiryaev E.O., Galkin S.V. 3D-modeling technology of initial oil saturation in transitional oil-water zone by complex of capillarimetry and electric logging methods. Bulletin of the Tomsk Polytechnic University. Geo Аssets Engineering, 2023, vol. 334, no. 10, рр. 98-107. In Rus. The relevance. The 3D distribution of the initial oil saturation in the reservoir volume is one of the key elements of geological and technological modeling, largely determining the quality of subsequent development design solutions. The publication presents an analysis of the current state of the problem of studying the oil-water transition zone and the distribution of oil saturation. For terrigenous hydrophilic reservoirs, electric lateral logging quite reliably controls the fluid saturation of the void space of the oil part of the deposit, which suggests the possibility of its integration with widely used capillarimetry methods. Aim: to evaluate the possibility of reliably determining the oil saturation of terrigenous hydrophilic reservoirs by combining the data of electrical lateral logging, filtration-capacitance properties of reservoirs and capillarimetric core studies, to build a 3D model of the distribution of the initial oil saturation of reservoirs in oil deposits, taking into account the allocation of the oil-water transition zone. Object: oil-saturated reservoirs of the Visean oil deposits of the Perm region. Method: methods of multidimensional mathematical modeling in the development of a methodology for determining the initial oil saturation of reservoirs based on a complex of well logging and capillarimetric studies of the core, construction of 3D distribution of the initial oil saturation of the reservoir, taking into account the parameters of the oil-water transition zone. Results. The authors, based on the developed methodology for the deposit of the reservoir Bb of the Aspinskoe field, built a 3D model of the distribution of the initial oil saturation. For the studied reservoir, they carried out the analysis of distribution of zones of free saturation, undersaturation, transition zone and limiting oil saturation. The resulting 3D model can be used in geological and technological modeling of the development of an oil deposit.
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Yang, Yue, Xiang Fang Li, Ke Liu Wu, Jian Yang, Jun Tai Shi, and Jie Fan. "A Novel Deliverability Equation for Shallow Layer and Low Permeability Reservoirs with Horizontal Fracture." Advanced Materials Research 616-618 (December 2012): 1000–1007. http://dx.doi.org/10.4028/www.scientific.net/amr.616-618.1000.
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In order to predict the productivity of vertical well for shallow layer and low permeability reservoirs with horizontal fracture, based on the theory of horizontal fracture distribution and oil seepage in reservoir, establish the reservoir seepage physical model for shallow layer and low permeability reservoirs with horizontal fracture, and derive a novel deliverability equation, considering the effect of reservoir properties, fluid properties, horizontal fracture parameters and working systems. Furthermore, the equation was applied and performed sensitivity analysis to the productivity of a vertical well in Yanchang Chang 6 layer reservoir. Results show that vertical permeability, oil viscosity and the semiminor axis of horizontal fracture have more significant impact on well productivity. With real cases, it is demonstrated the established deliverability equation is simple and practical and meets the engineering accuracy requirements.
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Ayache, Simon V., Violaine Lamoureux-Var, Pauline Michel, and Christophe Preux. "Reservoir Simulation of Hydrogen Sulfide Production During a Steam-Assisted-Gravity-Drainage Process by Use of a New Sulfur-Based Compositional Kinetic Model." SPE Journal 22, no. 01 (August 3, 2016): 080–93. http://dx.doi.org/10.2118/174441-pa.
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Summary Steam injection is commonly used as a thermal enhanced-oil-recovery (EOR) method because of its efficiency for recovering hydrocarbons, especially from heavy-oil and bitumen reservoirs. Reservoir models simulating this process describe the thermal effect of the steam injection, but generally neglect the chemical reactions induced by the steam injection and occurring in the reservoir. In particular, these reactions can lead to the generation and production of the highly toxic and corrosive acid gas hydrogen sulfide (H2S). The overall objective of this paper is to quantitatively describe the chemical aquathermolysis reactions that occur in oil-sands reservoirs undergoing steam injections and to provide oil companies with a numerical model for reservoir simulators to forecast the H2S-production risks. For that purpose, a new sulfur-based compositional kinetic model has been developed to reproduce the aquathermolysis reactions in the context of reservoir modeling. It is derived from results gathered on an Athabasca oil sand from previous laboratory aquathermolysis experiments. In particular, the proposed reactions model accounts for the formation of H2S issued from sulfur-rich heavy oils or bitumen, and predicts the modification of the resulting oil saturate, aromatic, resin, and asphaltene (SARA) composition vs. time. One strength of this model is that it is easily calibrated against laboratory-scale experiments conducted on an oil-sand sample. Another strength is that its calibration is performed while respecting the constraints imposed by the experimental data and the theoretical principles. In addition, in this study no calibration was needed at reservoir scale against field-production data. In the paper, the model is first validated with laboratory-scale simulations. The thermokinetic modeling is then coupled with a 2D reservoir simulation of a generic steam-assisted gravity drainage (SAGD) process applied on a generic Athabasca oil-sand reservoir. This formulation allows investigating the H2S generation at reservoir scale and quantifying its production. The H2S- to bitumen-production ratio against time computed by the reservoir simulation is found to be consistent with production data from SAGD operations in Athabasca, endorsing the proposed methodology.
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Wang, Guozhi, Qing Lei, Zhu Huang, Gang Liu, Yuzhen Fu, Na Li, and Jinlong Liu. "Genetic Relationship between Mississippi Valley-Type Pb–Zn Mineralization and Hydrocarbon Accumulation in the Wusihe Deposits, Southwestern Margin of the Sichuan Basin, China." Minerals 12, no. 11 (November 16, 2022): 1447. http://dx.doi.org/10.3390/min12111447.
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The coexistence of numerous Mississippi Valley-type (MVT) Pb–Zn deposits and oil/gas reservoirs in the world suggests a close genetic relationship between mineralization and hydrocarbon accumulation. The Wusihe MVT Pb–Zn deposits are located along the southwestern margin of the Sichuan Basin. Based on the spatiotemporal relation between Pb–Zn deposits and paleo-oil/gas reservoirs, ore material sources, and processes of mineralization and hydrocarbon accumulation, a new genetic relationship between mineralization and hydrocarbon accumulation is suggested for these deposits. The Wusihe Pb–Zn deposits are hosted in the Ediacaran Dengying Formation dolostone, accompanied by a large amount of thermally cracked bitumen in the ore bodies. The Pb–Zn deposits and paleo-oil/gas reservoirs are distributed along the paleokarst interface; they overlap spatially, and the ore body occupies the upper part of the paleo-oil/gas reservoirs. Both the Pb–Zn ore and sphalerite are rich in thermally cracked bitumen, in which µm sized galena and sphalerite may be observed, and the contents of lead and zinc in the bitumen are higher than those required for Pb–Zn mineralization. The paleo-oil/gas reservoirs experienced paleo-oil reservoir formation, paleo-gas reservoir generation, and paleo-gas reservoir destruction. The generation time of the paleo-gas reservoirs is similar to the metallogenic time. The source rocks from the Cambrian Qiongzhusi Formation not only provided oil sources for paleo-oil reservoirs but also provided ore-forming metal elements for mineralization. Liquid oil with abundant ore-forming metals accumulated to form paleo-oil reservoirs with mature organic matter in source rocks. As paleo-oil reservoirs were buried, the oil underwent in situ thermal cracking to form overpressure paleo-gas reservoirs and a large amount of bitumen. Along with the thermal cracking of the oil, the metal elements decoupled from organic matter and H2S formed by thermochemical sulfate reduction (TSR) and minor decomposition of the organic matter dissolved in oilfield brine to form the ore fluid. The large-scale Pb–Zn mineralization is mainly related to the destruction of the overpressured paleo-gas reservoir; the sudden pressure relief caused the ore fluid around the gas–water interface to migrate upward into the paleo-gas reservoirs and induced extensive metal sulfide precipitation in the ore fluid, resulting in special spatiotemporal associated or paragenetic relations of galena, sphalerite, and bitumen.
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Zhao, Shuangfeng, Wen Chen, Zhenhong Wang, Ting Li, Hongxing Wei, and Yu Ye. "Fluid geochemistry of the Jurassic Ahe Formation and implications for reservoir formation in the Dibei area, Tarim Basin, northwest China." Energy Exploration & Exploitation 36, no. 4 (February 22, 2018): 801–19. http://dx.doi.org/10.1177/0144598718759560.
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The condensate gas reservoirs of the Jurassic Ahe Formation in the Dibei area of the Tarim Basin, northwest China are typical tight sandstone gas reservoirs and contain abundant resources. However, the hydrocarbon sources and reservoir accumulation mechanism remain debated. Here the distribution and geochemistry of fluids in the Ahe gas reservoirs are used to investigate the formation of the hydrocarbon reservoirs, including the history of hydrocarbon generation, trap development, and reservoir evolution. Carbon isotopic analyses show that the oil and natural gas of the Ahe Formation originated from different sources. The natural gas was derived from Jurassic coal measure source rocks, whereas the oil has mixed sources of Lower Triassic lacustrine source rocks and minor amounts of coal-derived oil from Jurassic coal measure source rocks. The geochemistry of light hydrocarbon components and n-alkanes shows that the early accumulated oil was later altered by infilling gas due to gas washing. Consequently, n-alkanes in the oil are scarce, whereas naphthenic and aromatic hydrocarbons with the same carbon numbers are relatively abundant. The fluids in the Ahe Formation gas reservoirs have an unusual distribution, where oil is distributed above gas and water is locally produced from the middle of some gas reservoirs. The geochemical characteristics of the fluids show that this anomalous distribution was closely related to the dynamic accumulation of oil and gas. The period of reservoir densification occurred between the two stages of oil and gas accumulation, which led to the early accumulated oil and part of the residual formation water being trapped in the tight reservoir. After later gas filling into the reservoir, the fluids could not undergo gravity differentiation, which accounts for the anomalous distribution of fluids in the Ahe Formation.
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Srajan, Vajpayee, and Bhalala Vandan. "A comparative study of thermal enhanced oil recovery method." i-manager's Journal on Material Science 10, no. 4 (2023): 43. http://dx.doi.org/10.26634/jms.10.4.19302.
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The world's petroleum consumption is projected to increase steadily, with most of the oil discovered worldwide remaining unrecovered. Thermal Enhanced Oil Recovery (TEOR) techniques have been found to be effective in increasing the oil recovery from mature reservoirs. This paper compares the two most commonly used TEOR methods, In- Situ Combustion (ISC) and hot fluid injection, in the Sudanese Oil Field, Orion Field. The reservoir properties, operating conditions, production performance, technical challenges, and opportunities, including depth limitations, conventional completion problems, and reservoir heterogeneity, were analyzed for each method. Economic feasibility and environmental impacts are also discussed, including factors such as capital and operating costs, oil recovery rates, and carbon emissions. This study offers valuable insights into the practical aspects of implementing TEOR projects in the Sudanese oil field and can inform decision-making in the oil and gas industry, particularly in reservoir engineering, production optimization, and environmental management.
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Shokoya, O. S., S. A. (Raj) Mehta, R. G. Moore, B. B. Maini, M. Pooladi-Darvish, and A. Chakma. "The Mechanism of Flue Gas Injection for Enhanced Light Oil Recovery." Journal of Energy Resources Technology 126, no. 2 (June 1, 2004): 119–24. http://dx.doi.org/10.1115/1.1725170.
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Flue gas injection into light oil reservoirs could be a cost-effective gas displacement method for enhanced oil recovery, especially in low porosity and low permeability reservoirs. The flue gas could be generated in situ as obtained from the spontaneous ignition of oil when air is injected into a high temperature reservoir, or injected directly into the reservoir from some surface source. When operating at high pressures commonly found in deep light oil reservoirs, the flue gas may become miscible or near–miscible with the reservoir oil, thereby displacing it more efficiently than an immiscible gas flood. Some successful high pressure air injection (HPAI) projects have been reported in low permeability and low porosity light oil reservoirs. Spontaneous oil ignition was reported in some of these projects, at least from laboratory experiments; however, the mechanism by which the generated flue gas displaces the oil has not been discussed in clear terms in the literature. An experimental investigation was carried out to study the mechanism by which flue gases displace light oil at a reservoir temperature of 116°C and typical reservoir pressures ranging from 27.63 MPa to 46.06 MPa. The results showed that the flue gases displaced the oil in a forward contacting process resembling a combined vaporizing and condensing multi-contact gas drive mechanism. The flue gases also became near-miscible with the oil at elevated pressures, an indication that high pressure flue gas (or air) injection is a cost-effective process for enhanced recovery of light oils, compared to rich gas or water injection, with the potential of sequestering carbon dioxide, a greenhouse gas.
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Xu, Jianping, Yuanda Yuan, Qing Xie, and Xuegang Wei. "Research on the application of molecular simulation technology in enhanced oil-gas recovery engineering." E3S Web of Conferences 233 (2021): 01124. http://dx.doi.org/10.1051/e3sconf/202123301124.
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In recent years, molecular simulations have received extensive attention in the study of reservoir fluid and rock properties, interactions, and related phenomena at the atomistic scale. For example, in molecular dynamics simulation, interesting properties are taken out of the time evolution analysis of atomic positions and velocities by numerical solution of Newtonian equations for all atomic motion in the system. These technologies assists conducting “computer experiments” that might instead of be impossible, very costly, or even extremely perilous to carry out. Whether it is from the primary oil recovery to the tertiary oil recovery or from laboratory experiment to field test, it is difficult to clarify the oil displacement flow mechanism of underground reservoirs. Computer molecular simulation reveals the seepage mechanism of a certain oil displacement at the microscopic scale, and enriches the specific oil displacement flow theory system. And the molecular design and effect prediction of a certain oil-displacing agent were studied, and its role in the reservoir was simulated, and the most suitable oil-displacing agent and the best molecular structure of the most suitable oil-displacing agent were obtained. To give a theoretical basic for the development of oilfield flooding technology and enhanced oil/gas recovery. This paper presents an overview of molecular simulation techniques and its applications to explore enhanced oil/gas recovery engineering research, which will provide useful instructions for characterizing the reservoir fluid and rock and their behaviors in various oil-gas reserves, and it greatly contribute to perform optimal operation and better design of production plants.
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Cheng, Yong, Yuzhao Hu, Saihua Xu, and Di Wang. "TSR Action and Genesis Mechanism of Antimony Deposit: Evidence from Aromatic Hydrocarbon Geochemistry of Bitumen from Paleo-Oil Reservoir in Qinglong Ore Field, Southwestern Guizhou Depression, China." Minerals 12, no. 10 (October 17, 2022): 1306. http://dx.doi.org/10.3390/min12101306.
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In Qinglong ore field, the paleo-oil reservoir is found to be associated with antimony deposits, and they have a close genetic relationship. In this study, the aromatics geochemistry of paleo-oil reservoir bitumen was studied to further discuss the thermochemical sulfate reduction (TSR) reaction and the mechanism of antimony mineralization. A total of 124 aromatic compounds were identified by gas chromatography–mass spectrometry (GC–MS) analysis in bitumen samples, including abundant phenanthrene series, dibenzothiophene series, fluoranthene series, chrysene series, and a small number of fluorene series, naphthalene series, dibenzofuran series, biphenyl series, and triaromatic steroid series. Aromatic parameters such as trimethylnaphthalene index (TMNr), methylphenanthrene index (MPI), methylphenanthrene distribution fraction (MPDF, F1, and F2), methyldibenzothiophene parameter (MDR), C28TAS-20S/(20R + 20S), and benzofluoranthene/benzo[e]pyrene indicate that the Qinglong paleo-oil reservoir is in over maturity level. The abundance of phenanthrene and chrysene aromatic compounds and a small amount of naphthalene series, benzofluoranthene, fluoranthene, pyrene, anthracene, retene, perylene, and biphenyl suggest that the organic matter source of the paleo-oil reservoir was mainly low aquatic organisms, mixed with a small amount of higher plant. They detected a certain number of compounds, such as retene, triaromatic steroid series, and perylene, the ternary diagram of DBF–DBT–F and binary plot of Pr/Ph–DBT/P, DBT/(F + DBT)–DBF/(F + DBF), and Pr/Ph–DBT/DBF reveal that the source rock of the paleo-oil reservoir was formed in the marine environment of weak oxidation and weak reduction. The comprehensive analysis shows that the Qinglong paleo-oil reservoir originated from Devonian source rocks, just like other paleo-oil reservoirs and natural gas reservoirs in the Nanpanjiang basin. Abundant dibenzothiophene series were detected, indicating that the paleo-oil reservoir underwent a certain degree of TSR reaction. We believe that the gas reservoir formed by the evolution of the oil reservoir in the ore field participated in antimony mineralization; that is, hydrocarbon organic matter acted as a reducing agent and transformed SO42− in oilfield brine into H2S through TSR, providing reduced sulfur and creating environmental conditions for mineralization.
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Bao, Xiangsheng, Zhanhu Cai, Qingzhen Wang, Junfeng Yu, and Yecheng Li. "The Influence of Interference Layer on the Prediction of Seismic Information of Channel Sedimentary Reservoir." Shock and Vibration 2022 (January 28, 2022): 1–16. http://dx.doi.org/10.1155/2022/6609836.
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Channel sedimentary reservoirs are the main oil and gas accumulation sites at home and abroad. With the deepening of oil and gas exploration, channel-related oil and gas reservoirs with obvious seismic characteristics have been mostly discovered, and the rest are basically oil and gas reservoirs with unobvious seismic characteristics and difficult to be discovered. The difficulty and risk of discovering these oil and gas reservoirs are on the increase. In order to reduce the exploration risk, it is necessary to form a more reliable time window control theory with a better seismic interpretation technique for channel reservoir reliability. In this paper, 2D forward modeling was used to study the influence of the upper and lower interference layers on the imaging of channel reservoir. When the lithological composition is relatively stable, the degree of interference of the interference layer is closely related to the seismic wavelet, and it is especially susceptible to the main frequency of the seismic wavelet. The lower the main frequency of seismic wavelet, the greater the degree of interference of interference layers on the imaging of channel reservoir, and vice versa. Further analysis on the characteristics of the Ricker wavelet was made and showed that the influence of the upper and lower interference layers on the imaging information of the channel reservoir is concentrated in half apparent major period. Then, considering the dynamic change of distance between the interference layers and the top and bottom interfaces of channel reservoir, the influence of interference layers on the imaging of channel reservoir was studied through 1D forward modeling. The interference area was divided into maximum interference area and main interference area depending on the degree of influence. On this basis, the time window control theory of channel reservoir prediction was clarified. The seismic information which reflects the channel reservoir reliably can be obtained by avoiding the maximum interference area, especially the main interference area.
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Al-Mahasneh, Mehaysen, Hussam Elddin Al-Khasawneh, Kamel Al-Zboon, Marwan Al-Mahasneh, and Ali Aljarrah. "Water Influx Impact on Oil Production in Hamzeh Oil Reservoir in Northeastern Jordan: Case Study." Energies 16, no. 5 (February 22, 2023): 2126. http://dx.doi.org/10.3390/en16052126.
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This paper was conducted to delimit the water influx in the Hamzeh oil reservoir, located in northeastern Jordan approximately 150 km east of Amman. Petroleum reservoirs are frequently encompassed by water aquifers that back up the reservoir pressure through water inflow. When the pressure declines in a petroleum reservoir, the water aquifer responds by providing an influx of water. Gradually, the damage is reduced and then eliminated, and more oil is produced from the reservoir. The material balance equation (MBE) is used as the fundamental method for this study, predicting reservoir performance for a period of 11 years. The results for this study prove that the reservoir has a water drive mechanism and that the original oil in place (OOIP) was 24,958,290 m3. The projected oil recovery factor ranges from 10.9 to 25 percent for the Hummar and Shueib formations, respectively, depending on the areal efficiency assumed in the calculations. The water influx for the 11-year period was predicted by an MBE, an unsteady-state model, and the results of the performance reservoir.
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Wang, Jingyi, and Ian Gates. "Identifying Reservoir Features via iSOR Response Behaviour." Energies 14, no. 2 (January 14, 2021): 427. http://dx.doi.org/10.3390/en14020427.
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To extract viscous bitumen from oil sands reservoirs, steam is injected into the formation to lower the bitumen’s viscosity enabling sufficient mobility for its production to the surface. Steam-assisted gravity drainage (SAGD) is the preferred process for Athabasca oil sands reservoirs but its performance suffers in heterogeneous reservoirs leading to an elevated steam-to-oil ratio (SOR) above that which would be observed in a clean oil sands reservoir. This implies that the SOR could be used as a signature to understand the nature of heterogeneities or other features in reservoirs. In the research reported here, the use of the SOR as a signal to provide information on the heterogeneity of the reservoir is explored. The analysis conducted on prototypical reservoirs reveals that the instantaneous SOR (iSOR) can be used to identify reservoir features. The results show that the iSOR profile exhibits specific signatures that can be used to identify when the steam chamber reaches the top of the formation, a lean zone, a top gas zone, and shale layers.
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Zhu, Weiyao, Cunjia Zou, Jiulong Wang, Wenchao Liu, and Jiqiang Wang. "A new three-dimensional effective water-flooding unit model for potential tapping of remained oil in the reservoirs with rhythmic conditions." Journal of Petroleum Exploration and Production Technology 11, no. 3 (March 2021): 1375–91. http://dx.doi.org/10.1007/s13202-020-01068-z.
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AbstractAfter long-term water injection development, most of the oilfields in China have entered the stage of high-water cut, which has reached up to 90%. Due to the strong heterogeneity of the reservoir, more than 50% of the oil remains underground in most oilfields. Therefore, how to predict the distribution and content of remaining oil quickly and accurately in heterogeneous reservoir has become the key of EOR. In this paper, a new effective water-flooding unit model is established based on a three-dimensional flow function, which can characterize the influence of vertical heterogeneity on flow and the streamline distribution. In addition, two shape functions are defined in the model to characterize the oil–water two-phase flow characteristics in an injection-production unit. The results show that the streamline in the lower part of the positive rhythm reservoir is denser, which leads to the formation of dominant seepage channel with ease. However, for the reverse rhythm reservoir, dominant seepage channel forms in the upper part of the reservoir. Besides, for the two types of reservoirs, the greater the permeability difference is, the faster the water cut increases. Furthermore, under the same rhythm condition, the positive rhythm reservoir reaches 90% water cut half a year earlier than the anti-rhythm reservoir. This study provides new insight and guidance for the development of remaining oil in rhythmic reservoirs.
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Kamal, Ibtisam, Namam M. Salih, and Dmitriy A. Martyushev. "Correlations between Petroleum Reservoir Fluid Properties and Amount of Evolved and Dissolved Natural Gas: Case Study of Transgressive–Regressive-Sequence Sedimentary Rocks." Journal of Marine Science and Engineering 11, no. 10 (September 28, 2023): 1891. http://dx.doi.org/10.3390/jmse11101891.
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It is well recognized that PVT data are essential in oil and gas production facilities as well as in the determination of the reservoir fluid composition in reservoir engineering calculations. In the current work, the studied borehole is located in Tawke oilfield in the High Folded Zone. The structural geology and lithological facies of rocks are studied and found to comprise fine crystalline dolomite and anhydrite interbedded with claystone and dolomite. In addition, the practical PVT data of black oil from Tawke oilfield, Zakho, from reservoirs to transgressive–regressive cycles, are studied. The PVT data are investigated to derive the empirical models that rule and correlate the properties of the reservoir fluids in terms of the amount of natural gas (methane, ethane, and propane) dissolved in reservoir fluids and evolving from the wells. The characteristics of the reservoir fluid, including °API, viscosity at reservoir pressure and bubble-point pressure, reservoir pressure and temperature, gas–oil ratio (GOR), coefficient of compressibility at reservoir pressure, gross heating value, and sample depth, are correlated. The lithological part reveals that the carbonate and some clastic rock facies are conducive to enhancing natural gas adsorption. The reservoir fluid properties show adverse effects on the amount of natural gas constituents evolving from the wells, while it shows positive effects on the dissolved reservoir fluids. The estimated empirical correlations can help indicate the quantity of natural gas that is dissolved in reservoir fluids and liberated from the wells depending on the characteristics of the reservoir. In addition, they can be used in numerical simulators to predict oil well performance.
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Jiang, Nan, Zilu Zhang, Guohui Qu, Jiqiang Zhi, and Rongzhou Zhang. "Distribution Characteristics of Micro Remaining Oil of Class III Reservoirs after Fracture Flooding in Daqing Oilfield." Energies 15, no. 9 (May 6, 2022): 3385. http://dx.doi.org/10.3390/en15093385.
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The class III reservoir in the Daqing Oilfield has poor sand body development, poor reservoir physical properties, and poor effects of measures. Its water drive recovery degree is low and the remaining reserves are large. It is the key target oil layer of the Daqing Oilfield. Due to the sedimentary characteristics and reservoir physical properties of class III reservoirs, conventional EOR technology (chemical flooding) and conventional stimulation and injection measures (fracturing) have poor potential tapping effects on class III reservoirs. According to the special reservoir conditions and development characteristics of the class III reservoir in the Daqing Oilfield, fracture-flooding technology is innovatively proposed, which greatly improves the recovery of remaining oil in class III reservoirs. The rapid injection of hydraulic surface activators into the formation and displacement of the remaining oil in class III reservoirs through rock core flooding experiments were simulated in this paper. The nuclear magnetic resonance (NMR), confocal scanning laser, and computed tomography (CT)-scanning technologies were applied to study the remaining oil distribution after fracture flooding. The results show that: (1) After fracture flooding, the peak value of the T2 spectrum curve of NMR shifts to the left and the degree of middle and small pore space production increases obviously. (2) Confocal scanning laser study shows that the remaining oil in thin membranous and clustered forms on pore surfaces is highly utilized. (3) CT scan study shows that the remaining oil in membranous and clustered forms is effectively utilized after fracture flooding. In summary, fracture-flooding technology can improve the washing efficiency and sweep volume of class III reservoirs, thus enhancing the recovery efficiency of class III reservoirs.
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Sripal, Edison, David Grant, and Lesley James. "Application of SEM Imaging and MLA Mapping Method as a Tool for Wettability Restoration in Reservoir Core Samples for SCAL Experiments." Minerals 11, no. 3 (March 10, 2021): 285. http://dx.doi.org/10.3390/min11030285.
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In reservoir engineering, special core analysis experiments (SCAL) are performed in the lab to evaluate the production capabilities of an oil reservoir. A critical component of SCAL experiments is core wettability restoration to its original wettability, i.e., oil wet condition. Typically, aging is performed by saturating the core with oil and aging at reservoir temperature where time is the variable in question dictating whether the resulting restored core is strongly or weakly oil-wet. In the lab, core wettability is often experimentally validated using contact angle measurements or USBM (United States Bureau of Mines) wettability tests, which are often time consuming, expensive and prone to error. In this study we developed a novel method by using Scanning Electron Microscope (SEM) and mineral liberation analysis (MLA) imaging (at low vacuum conditions) to determine the wettability of rocks saturated with reservoir fluids such as oil and brine. For this work a systematic approach was applied with comparing the SEM-MLA method against conventional methods to quantify the degree of uncertainty linked to a) wettability estimation and b) the aging time. We have used a comprehensive suite of core samples such as Berea, Silurian Dolomite and Chalk to represent the bulk of oil reservoirs in the world.
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Tang, Ying, Ruifei Wang, and Shuai Yin. "Comprehensive Study on Microscopic Pore Structure and Displacement Mechanism of Tight Sandstone Reservoirs: A Case Study of the Chang 3 Member in the Weibei Oilfield, Ordos Basin, China." Energies 17, no. 2 (January 11, 2024): 370. http://dx.doi.org/10.3390/en17020370.
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With the continuous growth in global energy demand, research and development of unconventional oil and gas reservoirs have become crucial in the field of energy. This study focuses on the Chang 3 reservoir of the Yanchang Formation in the Ordos Basin, Weibei Oilfield, China. This reservoir is a typical tight sandstone reservoir, and its microscopic pore structure and displacement mechanism are essential for the efficient development of tight oil. However, the reservoir faces challenges such as complex microscopic pore structures and unclear displacement mechanisms, which hinder the efficient development of tight oil. In light of these challenges, through various studies including core observation, high-pressure mercury injection tests, water flooding experiments, oil-water two-phase relative permeability measurements, and stress sensitivity experiments, it was found that the Chang 3 reservoir exhibits strong microscopic heterogeneity. The pore-throat distribution characteristics mainly present two types: single peak and double peak, with the double peak type being predominant. The reservoir was classified and evaluated based on these characteristics. The improved injection ratio and properties enhance oil displacement efficiency, but an increase in irreducible water saturation has a negative impact on efficiency. The stress sensitivity of the reservoir fluctuates between weak and strong, with permeability being sensitive to net confining pressure. It is recommended to pay particular attention to the stress-sensitivity characteristics during reservoir development. The research results provide a scientific basis for the optimized development of tight oil reservoirs in this region, promote the sustainable development of unconventional oil and gas resources, and have significant theoretical and practical implications.
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Zhang, Jing Jun, Cheng Zhi Liu, Yong Liang Yang, and Si Hai Yu. "Volcanic Oil and Gas Reservoir Characteristics and Comprehensive Evaluation in Oulituozi Area." Advanced Materials Research 671-674 (March 2013): 328–32. http://dx.doi.org/10.4028/www.scientific.net/amr.671-674.328.
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Based on the core, thin section, scanning electron microscopy, well logging and the physical properties of reservoir, according to the research on the volcanic reservoirs characteristics of the E2-3S3 Formation in Oulituozi area, obtaining the following points: Basalt, trachyte and tuff are mainly lithology, overflow facies are main lithofacies, secondly explosive facies and volcanic sedimentary facies; Secondary reservoir spaces are often superimposed on the original reservoir spaces, and pore, hole and slit together form the effective reservoir spaces; The reservoir property show that the trachyte are the best, secondly the basalt and tuff; Reservoir lithology, lithofacies, thickness, fracture development, physical and electrical properties and other reservoir parameters are the main evaluation criteria to conduct the reservoir comprehensive evaluation.
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Maju-Oyovwikowhe, E. G., and A. D. Osayande. "Hydrocarbon evaluation and distribution in Well-X and Well-Y in the Niger Delta Basin: Findings and validation through porosity comparison." Scientia Africana 22, no. 1 (June 14, 2023): 255–78. http://dx.doi.org/10.4314/sa.v22i1.22.
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The aim of this study is to integrate well logs and core data to identify reservoir characteristics and determine the reservoir's petrophysical properties in order to improve the understanding of the reservoir and provide valuable information for reservoir management. Wells X and Y of the ‘SCOJAS’ Field in the Niger Delta Basin of Nigeria were analyzed using Gamma ray logs, Resistivity logs, Sonic, Neutron and Density Logs. The obtained results were compared with core data from the wells to verify their accuracy. Porosity values for Wells X and Y fall within the range typically observed in sedimentary rocks, with Well Y having higher values. Hydrocarbons were detected in all reservoirs except reservoir zone 1b in both Well-X (12 reservoirs) and Well-Y (7 reservoirs). In Well- X, oil was identified in 5 reservoir zones while in Well-Y, oil was present in 2 reservoir zones. The remaining zones in both wells contained gas. To validate the results further, a comparison was made with the porosity of selected fields in the Niger Delta Basin and the general porosity of the Basin. Well X has a porosity range of 2.7% to 20.8%, which is generally lower than the reported porosity range Well Y has a porosity range of 19.90% to 24.38%, which falls at the upper end of the reported porosity range. Comparing previous works and data from other fields provides important validation for the findings of the study, which is crucial in the oil and gas industry for making informed decisions about exploration and production.
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Meisingset, K. K. "Uncertainties in Reservoir Fluid Description for Reservoir Modeling." SPE Reservoir Evaluation & Engineering 2, no. 05 (October 1, 1999): 431–35. http://dx.doi.org/10.2118/57886-pa.
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Summary The objective of the present paper is to communicate the basic knowledge needed for estimating the uncertainty in reservoir fluid parameters for prospects, discoveries, and producing oil and gas/condensate fields. Uncertainties associated with laboratory analysis, fluid sampling, process description, and variations over the reservoirs are discussed, based on experience from the North Sea. Introduction Reliable prediction of the oil and gas production is essential for the optimization of development plans for offshore oil and gas reservoirs. Because large investments have to be made early in the life of the fields, the uncertainty in the in-place volumes and production profiles may have a direct impact on important economical decisions. The uncertainties in the description of reservoir fluid composition and properties contribute to the total uncertainty in the reservoir description, and are of special importance for the optimization of the processing capacities of oil and gas, as well as for planning the transport and marketing of the products from the field. Rules of thumb for estimating the uncertainties in the reservoir fluid description, based on field experience, may therefore be of significant value for the petroleum industry. The discussion in the present paper is based on experience from the fields and discoveries where Statoil is an operator or partner, including almost all fields on the Norwegian Continental Shelf,1,2 and all types of reservoir oils and gas condensates except heavy oils with stock-tank oil densities above 940 kg/m3 (below 20° API). Fluid Parameters in the Reservoir Model The following parameters are used to describe the reservoir fluid in a "black oil" reservoir simulation model:densities at standard conditions of stabilized oil, condensate, gas, and water;viscosity (?O) oil formation volume factor (B O) and gas-oil ratio (RS) of reservoir oil;viscosity (?G) gas formation volume factor (B G) and condensate/gas ratio (RSG) of reservoir gas;viscosity (?W) formation volume factor (BW) and compressibility of formation water; andsaturation pressures: bubblepoint for reservoir oil, dew point for reservoir gas. The actual input is usually slightly more complex, with saturation pressure given as a function of depth, with RS and R SG defined as a function of saturation pressure, and with oil and gas viscosities and formation volume factors given as a function of reservoir pressure for a range of saturation pressure values. However, minor changes in saturation pressure versus depth are usually neglected, and the oil dissolved in the reservoir gas can also be neglected (RSG=0) when the solubility is small. Uncertainties in the modeling of other fluid parameters (interfacial tension may for instance be of importance, because of its effect on the capillary pressure), or compositional effects like revaporization of oil into injection gas, are not discussed here. Uncertainties in viscosity, formation volume factor and compressibility of formation water, and density of gas at standard conditions, are judged to be of minor importance for the total uncertainties in the reservoir model. The uncertainty in the salinity of the formation water is discussed here instead, because it is used for calculations of water resistivity for log interpretation, and therefore, affects the estimates of initial water saturation in the reservoir. In a compositional reservoir simulation model, the composition of reservoir oil and gas (with, typically, 4 to 10 pseudocomponents) is given as a function of depth, while phase equilibria and fluid properties are calculated by use of an equation of state. However, the uncertainties in the fluid description can be described in approximately the same way as for a "black oil" model. Quantified uncertainty ranges in the present paper are coarse estimates, aiming at covering 80% of the probability range for each parameter (estimated value plus/minus an uncertainty estimate defining the range between the 10% and 90% probability values3). Prospect Evaluation Assessments of the uncertainties in the reservoir description, as a basis for economic evaluation, are made in all phases of exploration and production. Of course, the complexity in the fluid description increases strongly from prospect evaluation through the exploration phase and further into the production phase, but the main fluid parameters in the reservoir model are the same. The prediction of fluid parameters in the prospect evaluation phase, before the first well has been drilled, is based on reservoir fluid data from discoveries near by, information about source rocks and migration, and empirical correlations. The uncertainties vary strongly from prospect to prospect. The probability as a function of volume for the presence of reservoir oil and gas is usually the most important fluid parameter. The probability for predicting the correct hydrocarbon phase varies from 50% (equal probability for reservoir oil and gas) to 90% (in regions where either oil or gas reservoirs are strongly dominating, or when the reservoir fluid can be expected to be the same as in another discovery near by). For formation volume factors, gas/liquid ratios, viscosities, and densities, an estimate for the most probable value as well as for a high and low possible value is commonly given. The range between the high and low value is often designed to include 80% of the probability range for the parameter, but accurate uncertainty estimates can seldom be made. The ratio of the high and low value is, typically, 1.5 to 50 for R SG 1.1 to 1.5 for B G 1.1 to 2.5 for ?G 1.2 to 3 for RS 1.1 to 2 for BO 1.5 to 5 for (?O and 1.03 to 1.1 for densities of stabilized oil and condensate. From Discovery to Production After a discovery has been made, the fluid description is based on laboratory analyses of reservoir fluid samples from drill-stem tests, production tests, and wireline sampling (RFT, FMT, MDT) in exploration and production wells. Pressure gradients in the reservoirs from measurements during wireline and drill-stem tests, analysis of residual hydrocarbons in core material from various depths, measurements of gas/oil ratio during drill-stem and production tests, and measurements of product streams from the field, give important supplementary information.
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Yin, Rongwang, Qingyu Li, Peichao Li, and Detang Lu. "A Novel Method for Matching Reservoir Parameters Based on Particle Swarm Optimization and Support Vector Machine." Mathematical Problems in Engineering 2020 (April 29, 2020): 1–10. http://dx.doi.org/10.1155/2020/7542792.
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When the reservoir physical properties are distributed very dispersedly, the matching precision of these reservoir parameters is not good. We propose a novel method for matching the reservoir physical properties based on particle swarm optimization (PSO) and support vector machine (SVM) algorithm. First, the data structure characteristics of the reservoir physical properties are analyzed. Then, the particle swarm differential perturbation evolution algorithm is used to cluster and characterize the reservoir physical properties. Finally, by using the SVM algorithm for feature reorganization and the least squares matching of the extracted reservoir physical properties, the feature quantity of the reservoir physical properties can be accurately mined and the pressure matching precision is improved. The experimental results show that employing the proposed method to analyze and sample the data characteristics of the physical properties of the reservoir is better. The extracted parameters can effectively reflect the physical characteristics of oil reservoirs. The proposed method has potential applications in guiding the exploration and development of oil reservoirs.
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Kaufman, R. L., C. S. Kabir, B. Abdul-Rahman, R. Quttainah, H. Dashti, J. M. Pederson, and M. S. Moon. "Characterizing the Greater Burgan Field With Geochemical and Other Field Data." SPE Reservoir Evaluation & Engineering 3, no. 02 (April 1, 2000): 118–26. http://dx.doi.org/10.2118/62516-pa.
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Summary This paper describes recent results from an ongoing geochemical study of the supergiant Greater Burgan field, Kuwait. Oil occurs in a number of vertically separated reservoirs including the Jurassic Marrat reservoir and Cretaceous-Minagish, -Third Burgan, -Fourth Burgan, -Mauddud, and -Wara reservoirs. The Third and Fourth Burgan sands are the most important producing reservoirs. Over 100 oils representing all major producing reservoirs have been analyzed using oil fingerprinting as the principal method, but also supported by gravity, sulfur, and pressure-volume-temperature (PVT) measurements. From a reservoir management perspective, an important feature of the field is the approximately 1,200-ft-long hydrocarbon column which extends across the Burgan and Wara reservoirs. Oil composition varies with depth in this thick oil column. For example, oil gravity varies in a nonlinear fashion from about 10°API near the oil/water contact to about 39°API at the shallowest Wara reservoir. This gravity-depth relationship makes identification of reservoir compartments solely from fluid property data difficult. Including oil geochemistry in the traditional mix of PVT and production logging data improves the understanding of compartmentalization and fluid flow in the reservoir, both in a vertical and lateral sense. The composition of reservoir fluids is controlled by a number of geological and physical processes. We attempted to identify unique sets of geochemical parameters that were sensitive to specific oil alteration processes. One set of geochemical properties correlated strongly with gravity and is, therefore, related to the gravity-segregation process. A second set of parameters showed essentially no correlation with gravity or depth but established unique oil fingerprints for most of the major producing reservoirs and identified a number of different oil groups within the Burgan and Wara reservoirs. We interpret the presence of these oil groups to indicate reservoir compartments owing to laterally continuous shales and faults which act as seals on a geologic time frame. More tentative is the identification of production time frame barriers from the fluid composition data. The oil fingerprint data have been used to distinguish oils from the major producing reservoirs and evaluate hydrocarbon continuity within the reservoirs. Introduction This article describes a geochemical study of oils from the Greater Burgan field, Kuwait. During this study, we examined the compositional variation of oils within the field to evaluate reservoir continuity. This study is part of a larger project to describe the producing characteristics of the major reservoirs in the Burgan field en route to applying the best practices in the overall reservoir management program. In Phase I of this study,1 approximately 60 oils from the Burgan, Magwa, and Ahmadi areas of the Greater Burgan field were analyzed using oil fingerprinting. The objective was to determine if oils from the Wara, Third Burgan, and Fourth Burgan reservoirs had unique oil fingerprints and to evaluate oil mixing because of wellbore communications. In Phase II, a larger suite of wells was sampled to broaden the coverage of the field, both areally and stratigraphically, as shown in Fig. 1. Even though a considerably larger number of wells were sampled in Phase II, the sampling density still remains rather coarse in this supergiant field, spanning 320 sq mile. A variety of different techniques are available for reservoir geochemistry studies.2 The principle method used in this study is whole-oil gas chromatography; sometimes referred to as oil fingerprinting. This method has been described before3 and is, therefore, summarized only briefly here. Oil samples were collected at the wellhead, at atmospheric conditions, and analyzed using capillary gas chromatography. A standard of about 200 calibrated peak heights was developed and from this about 30 standard peak height ratios were calculated. These ratios were selected based on their ability to separate the oils into uniquely different groups. Two different multivariate statistical techniques were used to analyze the chromatography data: cluster analysis and principal components analysis. Both techniques were used to identify groups of similar oils based on the peak height ratios. Petroleum is a very complex natural product whose composition is controlled by various geologic processes which occur both before and after fluid accumulation. In our geochemical studies of the Burgan field, we have used the composition of the produced oil to study the hydrocarbon connectivity of different reservoirs. Some measurements, such as oil gravity, gas/oil ratio and bubblepoint data, characterize the bulk properties of the fluid. Other measurements, such as the hydrocarbon fingerprint, are based on the molecular composition of the fluid. Both types of data are necessary to completely characterize a petroleum reservoir, but the molecular composition data are frequently a more sensitive measure of the reservoir connectivity. Where available, both types of data have been used in this study of the Burgan field. The identification of reservoir compartments, both vertical and lateral, is a necessary component of efficient reservoir appraisal and management. Reservoirs are compartmentalized when barriers to fluid flow are present which prevent fluid communication between different parts of the reservoir. Smalley and Hale have discussed the need for early identification of reservoir compartments well in advance of dynamic production measurements.4 Some barriers are effective on a geologic time scale and frequently result in separate oil pools with unique oil/water contacts and initial pressure gradients. Other barriers may become effective on a production time frame. These are typically identified only after the field is put on production. Reservoir fluid composition data have most frequently been interpreted as indicators of geologic time-frame compartments, but it may provide an early indication of production time-frame compartments in some cases. The Greater Burgan Field The Greater Burgan oil field lies within the Arabian basin in the state of Kuwait. General reviews of the geology and producing history of the field are described by Brennan,5 Kirby et al.,6 and Carman.7 The field is subdivided into the Burgan, Magwa, and Ahmadi sectors based on the presence of three structural domes as shown in Fig. 1. The boundary between the northern Magwa/Ahmadi and the Burgan sectors is the Central Graben fault complex, as shown in Fig. 2.
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Baker, Hussain Ali, Dunia Abdulsaheb Al-Shamma'a, and Emad Abdulhussain Fakher. "New Correlation for Predicting Undersaturated Oil Compressibility for Mishrif Reservoir in the Southern Iraqi Oil Fields." Journal of Engineering 19, no. 9 (June 5, 2023): 1158–68. http://dx.doi.org/10.31026/j.eng.2013.09.09.
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Reservoir fluids properties are very important in reservoir engineering computations such as material balance calculations, well testing analyses, reserve estimates, and numerical reservoir simulations. Isothermal oil compressibility is required in fluid flow problems, extension of fluid properties from values at the bubble point pressure to higher pressures of interest and in material balance calculations (Ramey, Spivey, and McCain). Isothermal oil compressibility is a measure of the fractional change in volume as pressure is changed at constant temperature (McCain). The most accurate method for determining the Isothermal oil compressibility is a laboratory PVT analysis; however, the evaluation of exploratory wells often require an estimate of the fluid behavior prior to obtaining a representative reservoir sample. Also, experimental data is often unavailable.Empirical correlations are often used for these purposes.This paper developed a new mathematical model for calculating undersaturated oil compressibility using 129 experimentally obtained data points from the PVT analyses of 52 bottom hole fluid samples from Mishrif reservoirs in the southern Iraqi oil fields. The new undersaturated oil compressibility correlation developed using Statistical Analysis System (SAS) by applying nonlinear multiple regression method. It was found that the new correlation estimates undersaturated oil compressibility of Mishrif reservoir crudes in the southern Iraqi oil fields much better than the published ones. The average absolute relative error for the developed correlation is 7.16%.
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Khuzin, R. R., R. N. Bakhtizin, V. E. Andreev, L. S. Kuleshova, V. V. Mukhametshin, and Sh Kh Sultanov. "Oil recovery enhancement by reservoir hydraulic compression technique employment." SOCAR Proceedings, SI1 (June 30, 2021): 98–108. http://dx.doi.org/10.5510/ogp2021si100522.
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Industrial experiment works (IEW) were carried out to study the mechanism of filtration and reservoir properties changes (FRP) in the process of wells swabbing. Based on the hydrodynamic studies, the results of the works are analyzed. A method for oil production enhancing by reservoirs hydraulic compression has been worked out. In the process of well swabbing the barograms were recorded, pressure recovery curves were taken with the determination of hydraulic conductivity and piezoconductivity values, potential productivity coefficients, well flow rate, reservoir pressure before and after exposure. The interpretation of hydrodynamic studies was carried out by the deterministic analysis with subsequent modeling of the situation. The reservoir, opened by the perforation interval, is of complex structure, as a result of which the liquid was absorbed by the interlayer located above the area with newly formed microcracks. Keywords: hard-to-recover reserves; swabbing; carbonate reservoirs; filtration reservoir properties; pressure recovery curve.
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Hoang, Long, Thang Viet Trinh, Truong Hung Trieu, Quy Minh Nguyen, Ngoc Quy Pham, Hien Huy Doan, and Linh Hoang. "Study and apply the advanced analysis algorithm to screen the optimal enhanced oil recovery solution for oil and gas fields in Viet Nam." Journal of Mining and Earth Sciences 62, no. 3a (July 10, 2021): 17–29. http://dx.doi.org/10.46326/jmes.2021.62(3a).03.
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Applying the methods of enhanced oil recovery (EOR) for oil and gas fields has always many risks of economic and technology because EOR projects are influenced by many characteristic factors of the reservoir such as structure of reservoir, reservoir formation, geological properties, parameters of reservoir engineering, production technology to EOR application. Some EOR methods have been successfully applied in the world, but when these methods conduct in specific reservoir with different geological characteristics, tight production conditions have resulted in failures and ineffective economic, even caused dreadful aftermath to be handled in operations. Researches, evaluations and EOR applications in Vietnam are limited and only carried out on a laboratory scale. Therefore, the ability to be applied the EOR modern technology with a large scale or full field still faces many difficulties and the feasibility of projects is not high enough. The authors have been analysed all EOR projects successfully that applied many oil and gas fields in the world and then building EOR database. Based on EOR database, a study has been conducted on statistical analysis to build EOR screening criteria for reservoir parameters from past to now. The study also combined in-depth analysis algorithms such as Fuzzy, K - mean, PCA Artificial Intelligence to screen the optimal EOR method for sandstone reservoirs of Cuu Long Basin.
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Xi, Kelai, Yingchang Cao, Keyu Liu, and Rukai Zhu. "Factors influencing oil saturation and exploration fairways in the lower cretaceous Quantou Formation tight sandstones, Southern Songliao Basin, China." Energy Exploration & Exploitation 36, no. 5 (January 2, 2018): 1061–85. http://dx.doi.org/10.1177/0144598717751181.
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Favorable exploration fairway prediction becomes crucial for efficient exploration and development of tight sandstone oil plays due to their relatively poor reservoir quality and strong heterogeneous oil saturation. In order to better understand the factors influencing oil saturation and favorable exploration fairway distribution, petrographic investigation, reservoir properties testing, X-ray diffraction analysis, oil saturation measurement, pressure-controlled mercury injection, and rate-controlled mercury injection were performed on a suite of tight reservoir from the fourth member of the Lower Cretaceous Quantou Formation (K1q4) in the southern Songliao Basin, China. The sandstone reservoirs are characterized by poor reservoir properties and low oil saturations. Reservoir properties between laboratory pressure conditions and in situ conditions are approximately the same, and oil saturations are not controlled by porosity and permeability obviously. Pores are mainly micro-scale, and throats are mainly nano-scale, forming micro- to nano-scale pore–throat system with effective connected pore–throat mainly less than 40%. Oil emplacement mainly occurs through the throats with average radius larger than 0.25 µm under original geological condition. Moreover, the samples with higher oil saturation show more scattered pore and throat distributions, but centered pore–throat radius ratio distribution. Pore–throat volume ratio about 2.3–3.0 is best for oil emplacement, forming high oil saturation. Quartz overgrowth, carbonate cements, and authigenic clays are the major diagenetic minerals. The reservoirs containing about 4–5% carbonate cements are most preferable for oil accumulation, and oil saturation increases with increasing of chlorite as well. The flow zone indicator is a reasonable parameter to predict favorable exploration targets in tight sandstone reservoirs. The reservoirs with flow zone indicator values larger than 0.05 can be regarded as favorable exploration targets in the K1q4 tight sandstones. According to the planar isoline of average flow zone indicator value, the favorable exploration targets mainly distribute in the delta plain distributary channel and deltaic front subaqueous distributary channel.
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Hoang, Long, Minh Quy Nguyen, Truong Giang Pham, Vu Anh Phan, Thi Thu Huong Le, Thi Viet Nga Cu, Thanh Phuong Tran, Duc Huy Dinh, and The Hung Le. "Research on evaluating, selecting and manufacturing the VPI SP chemical product for conducting field test to enhance oil recovery coefficient of oil fields in Cuu Long basin, offshore Vietnam." Petrovietnam Journal 11 (November 9, 2021): 45–54. http://dx.doi.org/10.47800/pvj.2021.11-02.
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The Vietnam Petroleum Institute (VPI) is implementing a multi-task national level project entitled “Research, evaluate, select and develop a pilot programme for industrial application of solutions to improve oil recovery coefficient for clastic oil bearing reservoirs of oil fields in the Cuu Long basin, on the continental shelf of Vietnam”. Specifically, detailed evaluation studies have been carried out from geological characteristics, reservoir engineering, production to EOR mechanism to develop technical criteria for the process of manufacturing and evaluating the efficiency of the chemical system to optimise the laboratory scale, propose the production and injection scenarios to optimize the development plan as well as evaluate the efficiency of increasing oil recovery coefficient on the reservoir simulation model; conduct production at pilot scale and implement industrial application testing on the field scale for clastic oil bearing reservoir, Cuu Long basin.
The article presents the results of research, evaluation, selection and successful manufacture of a VPI SP chemical system based on the combined mechanism of anionic - non-ionic surfactants and polymers to ensure satisfying the harsh technical requirements of oil fields in Vietnam such as resistance to high temperature, high pressure, high mineralisation, very low surface tension, optimal micro-emulsion, low adsorption onto reservoir rocks, reducing residual oil saturation in the reservoir. Results of the evaluation of increased efficiency of oil recovery on actual samples of Miocene reservoir showed an increase of over 21%. The VPI SP chemical system has been included in the plan of industrial-scale testing by Vietsovpetro in Bach Ho and other producing fields in the clastic sections of the Cuu Long basin.
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Ke, Wenqi, Wei Luo, Shiyu Miao, Wen Chen, and Yaodong Hou. "A Transient Productivity Prediction Model for Horizontal Wells Coupled with Oil and Gas Two-Phase Seepage and Wellbore Flow." Processes 11, no. 7 (July 5, 2023): 2012. http://dx.doi.org/10.3390/pr11072012.
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Capacity prediction is the basis for the optimization of oil and gas well production work systems and parameter optimization design. Horizontal wells are becoming increasingly popular for oil and gas extraction. However, the seepage law of reservoirs produced with horizontal wells is more complicated than that of reservoirs produced with vertical wells, especially when the bottom hole flowing pressure or formation pressure is less than the saturation pressure of crude oil in the reservoir. Oil and gas two-phase seepage can occur in a part or all areas of the wellbore and reservoir. Because the oil and gas two-phase seepage characteristics of reservoir oil well production will be reduced—possibly greatly reduced—the formation seepage law is complex. Thus, it is very important to better predict the horizontal well capacity. To address this, a method and process of establishing a transient calculation model of two-phase flow in horizontal wells are introduced in detail from three aspects: fluid physical properties, reservoir oil and gas two-phase seepage, and the coupling model of the inflow performance and flow in the wellbore. The model is found to be reliable through verification with production data from five wells in two oilfields. The established model simplifies the reservoir model, does not involve very complex meshing, and only simulates one well. Therefore, the calculation speed will be faster than that of other reservoir numerical simulation methods under the same conditions.
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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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Siripatrachai, Nithiwat, Turgay Ertekin, and Russell T. Johns. "Compositional Simulation of Hydraulically Fractured Tight Formation Considering the Effect of Capillary Pressure on Phase Behavior." SPE Journal 22, no. 04 (March 6, 2017): 1046–63. http://dx.doi.org/10.2118/179660-pa.
Full textAbstract:
Summary Compositional reservoir simulation plays a vital role in the development of conventional and unconventional reservoirs. Two major building blocks of compositional simulation are phase-behavior and fluid-transport computations. The oil and gas reserves and flow of reservoir fluids are strongly dependent on phase behavior. In conventional reservoirs, capillary pressure is relatively small and is typically ignored in phase-behavior calculations. The approach is accepted as the norm to perform phase-equilibria calculation to estimate the oil and gas in place and fluid properties. However, large capillary pressure values are encountered in tight formations, such as shales, and therefore, its effects should not be ignored in phase-equilibria calculations. Many parameters and uncertainties contribute to the accuracy of the estimation and simulation results. In this research, the focus is on the effect of capillary pressure, and neglecting the effects of capillary pressure on phase behavior can lead to an inaccurate estimation of original oil in place (OOIP) and original gas in place (OGIP) as well as recovery performance because of the inherent assumption of equal phase pressures in the phase-equilibria calculation. Understanding of the effect of capillary pressure on phase behavior in tight reservoirs is by no means complete, especially by use of compositional simulation for hydraulically fractured reservoirs. In this paper, we develop a new compositional reservoir simulator capable of modeling discrete fractures and incorporating the effect of capillary pressure on phase behavior. Large-scale natural and hydraulic fractures in tight rocks and shales are modeled with a technique called the embedded-discrete-fracture model (EDFM), where fractures are modeled explicitly without use of local-grid refinement (LGR) or an unstructured grid. Flow of hydrocarbons occurs simultaneously within similar and different porosity types. Capillary pressure is considered in both flow and flash calculations, where simulations also include variable pore size as a function of gas saturation to accurately reflect temporal changes in each gridblock during the simulation. We examine the effect of capillary pressure on the OOIP and cumulative oil production for different initial reservoir pressures (above and below the bubblepoint pressure) on Bakken and Eagle Ford fluids. The importance of capillary pressure on both flow and flash calculations from hydraulically fractured horizontal wells during primary depletion in fractured tight reservoirs by use of two fluid compositions is demonstrated. Phase-behavior calculations show that bubblepoint pressure is suppressed, allowing the production to remain in the single-phase region for a longer period of time and also altering phase compositions and fluid properties, such as density and viscosity of equilibrium liquid and vapor. The results show that bubblepoint suppression is larger in the Eagle Ford shale than for Bakken. On the basis of the reservoir fluid and model used for the Bakken and Eagle Ford formations, when capillary pressure is included in the flash, we found an increase in OOIP up to 4.1% for the Bakken crude corresponding to an initial reservoir pressure of 2,000 psia and 46.33% for the Eagle Ford crude corresponding to an initial pressure of 900 psia. Depending on the initial reservoir pressure, cumulative primary oil production after 1 year increases because of the capillary pressure by approximately 9.0 to 38.2% for an initial reservoir-pressure range from 2,000 to 3,500 psia for Bakken oil and 7.2 to 154% for an initial reservoir-pressure range from 1,500 to 3,500 psia for Eagle Ford oil. The recovery increase caused by capillary pressure becomes more significant when reservoir pressure is far less than bubblepoint pressure. The simulation results with hydraulically fractured wells give similar recovery differences. For the two different reservoir settings in this study, at initial reservoir pressure of 5,500 psia, cumulative oil production after 1 year is 3.5 to 5.2% greater when capillary pressure is considered in phase-behavior calculations for Bakken. As initial reservoir pressure is lowered to 2,500 psia, the increase caused by capillary pressure is up to 28.1% for Bakken oil for the case studied. Similarly, at initial reservoir pressure of 2,000 psia, the increase caused by capillary pressure is 21.8% for Eagle Ford oil.