Journal articles: 'Petroleum reservoirs'

1

Roberts, D. G. "Sandstone petroleum reservoirs." Marine and Petroleum Geology 9, no. 1 (February 1992): 110. http://dx.doi.org/10.1016/0264-8172(92)90013-5.

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Kulke, Holger. "Sandstone petroleum reservoirs." Sedimentary Geology 73, no. 3-4 (October 1991): 329–31. http://dx.doi.org/10.1016/0037-0738(91)90093-s.

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Liu, Q., H. Xu, Z. Lei, Z. Li, Y. Xiong, S. Li, B. Luo, and D. Chen. "Fault Mesh Petroleum Plays in the Donghetang Area, Tabei Uplift, Tarim Basin, Northwestern China, and Its Significance for Hydrocarbon Exploration." Russian Geology and Geophysics 62, no. 07 (July 1, 2021): 808–27. http://dx.doi.org/10.2113/rgg20183939.

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Abstract —The hydrocarbon formation mechanism and potential targets in clastic strata from the Tabei Uplift, Tarim Basin, are documented using the fault mesh petroleum plays theory, based on integrating seismic, well log, well core, and geochemical data. The reservoirs in the Donghetang area are typical allochthonous and far-source fault mesh petroleum plays. There are two sets of fault meshes in the study area: (1) the combination of the Donghe sandstone and Permian–Triassic strata and (2) the combination of the fourth and third formations in the Jurassic strata. The fault mesh petroleum play in the Jurassic is a secondary reservoir that originates from the Carboniferous Donghe sandstone reservoir adjustment based on source correlation. The fault mesh carrier systems show the fully connected, fault–unconformity–transient storage relay, fault–transient storage–unconformity relay, and transient storage–fault relay styles, according to the architecture of the fault mesh. Based on the characteristics of the fault mesh petroleum plays, the reservoirs are divided into three categories (upper-, inner-, and margin-transient storage styles) and 15 styles. Integrated analysis of the hydrocarbon generation and faulting time periods reveals that there were four periods of hydrocarbon charging, with the first three stages charging the reservoirs with oil and the last stage charging the reservoirs with gas. There are multiple stages of reservoir accumulation and adjustment in the fault mesh in the study area. These stages of fault mesh accumulation and adjustment are the main reason why the reservoir distribution multiple vertical units have different hydrocarbon properties. Fault-block and lithologic reservoirs related to the inner- and upper-transient storage styles are the main exploration targets in the clastic strata in the study area.

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Qin, Yaqiong, Zhaohui Ye, and Conghui Zhang. "Application of deep learning for division of petroleum reservoirs." MATEC Web of Conferences 246 (2018): 03004. http://dx.doi.org/10.1051/matecconf/201824603004.

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Traditional methods of dividing petroleum reservoirs are inefficient, and the accuracy of onehidden-layer BP neural network is not ideal when applied to dividing reservoirs. This paper proposes to use the deep learning models to solve the reservoir division problem. We apply multiple-hidden-layer BP neural network and convolutional neural network models, and adjust the network structures according to the characteristics of the reservoir problem. The results show that the deep learning models are better than onehidden- layer BP neural network, and the performance of the convolutional neural network is very close to the artificial work.

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Li, Dongmei, and Philip Hendry. "Microbial diversity in petroleum reservoirs." Microbiology Australia 29, no. 1 (2008): 25. http://dx.doi.org/10.1071/ma08025.

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Buried hydrocarbon deposits, such as liquid petroleum, represent an abundant source of reduced carbon for microbes. It is not surprising therefore that many organisms have adapted to an oily, anaerobic life deep underground, often at high temperatures and pressures, and that those organisms have had, and in some cases continue to have, an effect on the quality and recovery of the earth?s diminishing petroleum resources. There are three key microbial processes of interest to petroleum producers: reservoir souring, hydrocarbon degradation and microbially enhanced oil recovery (MEOR).

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Hasan, Agus. "Optimal Control of Petroleum Reservoirs." IFAC Proceedings Volumes 46, no. 26 (2013): 144–49. http://dx.doi.org/10.3182/20130925-3-fr-4043.00055.

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Selley, R. C. "Exploration for Carbonate Petroleum Reservoirs." Sedimentary Geology 43, no. 1-4 (April 1985): 310–11. http://dx.doi.org/10.1016/0037-0738(85)90065-x.

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Wang, L. Y., R. Y. Duan, J. F. Liu, S. Z. Yang, J. D. Gu, and B. Z. Mu. "Molecular analysis of the microbial community structures in water-flooding petroleum reservoirs with different temperatures." Biogeosciences 9, no. 11 (November 20, 2012): 4645–59. http://dx.doi.org/10.5194/bg-9-4645-2012.

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Abstract. Analyses of microbial communities from six water-flooding petroleum reservoirs at temperatures from 21 to 63 °C by 16S rRNA gene clone libraries indicates the presence of physiologically diverse and temperature-dependent microorganisms in these subterrestrial ecosystems. In samples originating from high-temperature petroleum reservoirs, most of the archaeal sequences belong to thermophiles affiliated with members of the genera Thermococcus, Methanothermobacter and the order Thermoplasmatales, whereas bacterial sequences predominantly belong to the phyla Firmicutes, Thermotogae and Thermodesulfobacteria. In contrast to high-temperature petroleum reservoirs, microorganisms belonging to the Proteobacteria, Methanobacteriales and Methanomicrobiales were the most encountered in samples collected from low-temperature petroleum reservoirs. Canonical correspondence analysis (CCA) revealed that temperature, mineralization, ionic type as well as volatile fatty acids showed correlation with the microbial community structures, in particular members of the Firmicutes and the genus Methanothermobacter showed positive correlation with temperature and the concentration of acetate. Overall, these data indicate the large occurrence of hydrogenotrophic methanogens in petroleum reservoirs and imply that acetate metabolism via syntrophic oxidation may represent the main methanogenic pathway in high-temperature petroleum reservoirs.

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Yang, Guang-Chao, Lei Zhou, Serge Mbadinga, Ji-Dong Gu, and Bo-Zhong Mu. "Bioconversion Pathway of CO2 in the Presence of Ethanol by Methanogenic Enrichments from Production Water of a High-Temperature Petroleum Reservoir." Energies 12, no. 5 (March 9, 2019): 918. http://dx.doi.org/10.3390/en12050918.

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Transformation of CO2 in both carbon capture and storage (CCS) to biogenic methane in petroleum reservoirs is an attractive and promising strategy for not only mitigating the greenhouse impact but also facilitating energy recovery in order to meet societal needs for energy. Available sources of petroleum in the reservoirs reduction play an essential role in the biotransformation of CO2 stored in petroleum reservoirs into clean energy methane. Here, the feasibility and potential on the reduction of CO2 injected into methane as bioenergy by indigenous microorganisms residing in oilfields in the presence of the fermentative metabolite ethanol were assessed in high-temperature petroleum reservoir production water. The bio-methane production from CO2 was achieved in enrichment with ethanol as the hydrogen source by syntrophic cooperation between the fermentative bacterium Synergistetes and CO2-reducing Methanothermobacter via interspecies hydrogen transfer based upon analyses of molecular microbiology and stable carbon isotope labeling. The thermodynamic analysis shows that CO2-reducing methanogenesis and the methanogenic metabolism of ethanol are mutually beneficial at a low concentration of injected CO2 but inhibited by the high partial pressure of CO2. Our results offer a potentially valuable opportunity for clean bioenergy recovery from CCS in oilfields.

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10

Aguilera, Roberto. "Flow Units: From Conventional to Tight-Gas to Shale-Gas to Tight-Oil to Shale-Oil Reservoirs." SPE Reservoir Evaluation & Engineering 17, no. 02 (February 20, 2014): 190–208. http://dx.doi.org/10.2118/165360-pa.

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Summary Core data from various North American basins with the support of limited amounts of data from other basins around the world have shown in the past that process speed or delivery speed (the ratio of permeability to porosity) provides a continuum between conventional, tight-, and shale-gas reservoirs (Aguilera 2010a). This work shows that the previous observation can be extended to tight-oil and shale-oil reservoirs. The link between the various hydrocarbon fluids is provided by the word “petroleum” in the “total petroleum system (TPS),” which encompasses liquid and gas hydrocarbons found in conventional, tight, and shale reservoirs. Results of the present study lead to distinctive flow units for each type of reservoir that can be linked empirically to gas and oil rates and, under favorable conditions, to production decline. To make the work tractable, the bulk of the data used in this paper has been extracted from published geologic and petroleum-engineering literature. The paper introduces an unrestricted/transient/interlinear transition flow period in a triple-porosity model for evaluating the rate performance of multistage-hydraulically-fractured (MSHF) tight-oil reservoirs. Under ideal conditions, this flow period is recognized by a straight line with a slope of –1.0 on log-log coordinates. However, the slope can change (e.g., to –0.75), depending on reservoir characteristics, as shown with production data from the Cardium and Shaunavon formations in Canada. This interlinear flow period has not been reported previously in the literature because the standard assumption for MSHF reservoirs has been that of a pseudosteady-state transition between the linear flow periods. It is concluded that there is a significant practical potential in the use of process speed as part of the flow-unit characterization of unconventional petroleum reservoirs. There is also potential for the evaluation of production-decline rates by the use of the triple-porosity model presented in this study.

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Hao, Hui Zhi, and Li Juan Tan. "The Characteristic of Oil and Gas Accumulation and Main Factors of Reservoir Enrichment in SZ36-1 Region." Applied Mechanics and Materials 737 (March 2015): 859–62. http://dx.doi.org/10.4028/www.scientific.net/amm.737.859.

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The hydrocarbon reservoirs which have been found in SZ36-1 region are located in Liaoxi low uplift and dominated by structural traps. The principle source rock is the first and the third member of the Neogen Shahejie Formation and the main reservoir type is delta sand body which mainly located in the second member of Shahejie Formation. Oil reservoirs are mostly in normal pressure and are possess characteristic of late hydrocarbon accumulation. Hydrocarbon accumulation is mainly controlled by fault,reservoir-cap rock combination, and petroleum migration pathways. Lateral distribution of hydrocarbon reservoirs is mostly controlled by reservoir rocks, while the vertical distribution is controlled by fault.

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12

Semenets, S. N., S. S. Nasonova, Yu E. Vlasenko, and L. Yu Krivenkova. "Operational reliability management of petroleum reservoirs." Construction, materials science, mechanical engineering, no. 106 (November 27, 2018): 122–28. http://dx.doi.org/10.30838/p.cmm.2415.270818.122.241.

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13

Semenets, Serhii, Svitlana Nasonova, Viktor Olevskyi, and Denys Volchok. "Project reliability management of petroleum reservoirs." Strength of Materials and Theory of Structures, no. 103 (October 1, 2019): 165–76. http://dx.doi.org/10.32347/2410-2547.2019.103.165-176.

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14

England, W. A. "The organic geochemistry of petroleum reservoirs." Organic Geochemistry 16, no. 1-3 (January 1990): 415–25. http://dx.doi.org/10.1016/0146-6380(90)90058-8.

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15

Abderrahman, S. H., H. T. Yang, and A. S. Odeh. "Layered petroleum reservoirs with cross-flows." Applied Scientific Research 46, no. 2 (June 1989): 165–78. http://dx.doi.org/10.1007/bf00423093.

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16

Lee, C. S., M. C. Galloway, J. B. Willcox, A. M. G. Moore, A. R. Fraser, D. T. Heggie, A. P. Murray;, et al. "PETROLEUM POTENTIAL OF RAGAY GULF, SOUTHEAST LUZON, PHILIPPINES." APPEA Journal 34, no. 1 (1994): 707. http://dx.doi.org/10.1071/aj93052.

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During March-May 1992, the Australian Geological Survey Organisation and the Philippine Department of Energy conducted a cooperative marine seismic and underway geochemical survey in four offshore Philippine basins which included Ragay Gulf. The project was funded and supported by the Australian International Development Assistance Bureau.The newly acquired and reprocessed seismic data from Ragay Gulf show a significant improvement in penetration and stratigraphic resolution. Seismic interpretation has revealed the existence of five sedimentary sub-basins with 2.5 – 6 seconds of Eocene to Recent sediments. Several potential traps have been evaluated for hydrocarbon reserves and new prospects are identified.No well has been drilled offshore in the Ragay Gulf. Onshore well log information and stratigraphy have assisted in the correlation and interpretation of offshore seismic data and allowed potential reservoirs to be recognised. The primary reservoir targets are the carbonate sequences of both Early and Late Miocene age. The widespread volcanoclastic sand may be an important secondary target, especially for gas reservoirs.Onshore and offshore geochemical data have confirmed the presence of mature source rocks from which generated hydrocarbons are currently migrating to the surface and, by inference, to reservoirs.A wide diversity of play types is recognised which could have been sourced from three separate source kitchens in the Bondoc, Ragay and Burlas Sub-basins. Specific entrapment possibilities are:Compressional fault-dependent traps (e.g. Anima Sola).Compressional anticlinal fault independent traps (e.g. Alibijaban and Palad).Late Miocene carbonate reefal buildups (e.g. Apud and Gorda).Early Miocene carbonate reservoirs in drape over highs (e.g. San Narciso and Bagulaya).

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17

Sun, Yu, Shi Zhong Ma, Bai Quan Yan, and Chen Chen. "Controlling Factors for Reservoirs Distribution of the Putaohua Oil Layer in the Saozhao Sag." Advanced Materials Research 616-618 (December 2012): 816–20. http://dx.doi.org/10.4028/www.scientific.net/amr.616-618.816.

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Types of found reservoirs and its distribution characteristics of Putaohua oil layer in the Sanzhao Sag were analyzed. The controlling factors of hydrocarbon distribution were investigated. Sanzhao Sag is Sag-wide oil-bearing, but its distribution of oil and water is extremely complicated. The reservoir types are mainly fault block reservoirs, low amplitude structure reservoirs, fault-lithologic reservoirs and lithologic reservoirs. The distribution of reservoirs is mainly controlled by three geological factors: first, long-term inherited nose-like structure is predominant direction of petroleum migration; it induced oil and gas migration at a critical period of hydrocarbon accumulation and formed oil-gas accumulation area. Second, fault across main-line of hydrocarbon migration and high angle skew plug off hydrocarbon, and its side adjacent to Sag is a large number of hydrocarbon accumulation areas. Third, multi-fault region can easily form a fault (-lithological) reservoir accumulation area in the slope of sag.

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Gutierrez, M., R. W. Lewis, and I. Masters. "Petroleum Reservoir Simulation Coupling Fluid Flow and Geomechanics." SPE Reservoir Evaluation & Engineering 4, no. 03 (June 1, 2001): 164–72. http://dx.doi.org/10.2118/72095-pa.

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Summary This paper presents a discussion of the issues related to the interaction between rock deformation and multiphase fluid flow behavior in hydrocarbon reservoirs. Pore-pressure and temperature changes resulting from production and fluid injection can induce rock deformations, which should be accounted for in reservoir modeling. Deformation can affect the permeability and pore compressibility of the reservoir rock. In turn, the pore pressures will vary owing to changes in the pore volume. This paper presents the formulation of Biot's equations for multiphase fluid flow in deformable porous media. Based on this formulation, it is argued that rock deformation and multiphase fluid flow are fully coupled processes that should be accounted for simultaneously, and can only be decoupled for predefined simple loading conditions. In general, it is shown that reservoir simulators neglect or simplify important geomechanical aspects that can impact reservoir productivity. This is attributed to the fact that the only rock mechanical parameter involved in reservoir simulations is pore compressibility. This parameter is shown to be insufficient in representing aspects of rock behavior such as stress-path dependency and dilatancy, which require a full tensorial constitutive relation. Furthermore, the pore-pressure changes caused by the applied loads from nonpay rock and the influence of nonpay rock on reservoir deformability cannot be accounted for simply by adjusting the pore compressibility. Introduction In the last two decades, there has been a strong emphasis on the importance of geomechanics in several petroleum engineering activities such as drilling, borehole stability, hydraulic fracturing, and production-induced compaction and subsidence. In these areas, in-situ stresses and rock deformations, in addition to fluid-flow behavior, are key parameters. The interaction between geomechanics and multiphase fluid flow is widely recognized in hydraulic fracturing. For instance, Advani et al.1 and Settari et al.2 have shown the importance of fracture-induced in-situ stress changes and deformations on reservoir behavior and how hydraulic fracturing can be coupled with reservoir simulators. However, in other applications, geomechanics, if not entirely neglected, is still treated as a separate aspect from multiphase fluid flow. By treating the two fields as separate issues, the tendency for each field is to simplify and make approximate assumptions for the other field. This is expected because of the complexity of treating geomechanics and multiphase fluid flow as coupled processes. Recently, there has been a growing interest in the importance of geomechanics in reservoir simulation, particularly in the case of heavy oil or bituminous sand reservoirs,3,4 water injection in fractured and heterogeneous reservoirs,5–7 and compacting and subsiding fields.8,9 Several approaches have been proposed to implement geomechanical effects into reservoir simulation. The approaches differ on the elements of geomechanics that should be implemented and the degree to which these elements are coupled to multiphase fluid flow. The objective of this paper is to illustrate the importance of geomechanics on multiphase flow behavior in hydrocarbon reservoirs. An extension of Biot's theory10 for 3D consolidation in porous media to multiphase fluids, which was proposed by Lewis and Sukirman,11 will be reviewed and used to clarify the issues involved in coupling fluid flow and rock deformation in reservoir simulators. It will be shown that for reservoirs with relatively deformable rock, fluid flow and reservoir deformation are fully coupled processes, and that such coupled behaviors cannot be represented sufficiently by a pore-compressibility parameter alone, as is done in reservoir simulators. The finite-element implementation of the fully coupled equations and the application of the finite-element models to an example problem are presented to illustrate the importance of coupling rock deformation and fluid flow. Multiphase Fluid Flow in Deformable Porous Media Fig. 1 illustrates the main parameters involved in the flow of multiphase fluids in deformable porous media and how these parameters ideally interact. The main quantities required to predict fluid movement and productivity in a reservoir are the fluid pressures (and temperatures, in case of nonisothermal problems). Fluid pressures also partly carry the loads, which are transmitted by the surrounding rock (particularly the overburden) to the reservoir. A change in fluid pressure will change the effective stresses following Terzaghi's12 effective stress principle and cause the reservoir rock to deform (additional deformations are induced by temperature changes in nonisothermal problems). These interactions suggest two types of fluid flow and rock deformation coupling:Stress-permeability coupling, where the changes in pore structure caused by rock deformation affect permeability and fluid flow.Deformation-fluid pressure coupling, where the rock deformation affects fluid pressure and vice versa. The nature of these couplings, specifically the second type, are discussed in detail in the next section. Stress-Permeability Coupling This type of coupling is one where stress changes modify the pore structure and the permeability of the reservoir rock. A common approach is to assume that the permeability is dependent on porosity, as in the Carman-Kozeny relation commonly used in basin simulators. Because porosity is dependent on effective stresses, permeability is effectively stress-dependent. Another important effect, in addition to the change in the magnitude of permeability, is on the change in directionality of fluid flow. This is the case for rocks with anisotropic permeabilities, where the full permeability tensor can be modified by the deformation of the rock. Examples of stress-dependent reservoir modeling are given by Koutsabeloulis et al.6 and Gutierrez and Makurat.7 In both examples, the main aim of the coupling is to account for the effects of in-situ stress changes on fractured reservoir rock permeability, which in turn affect the fluid pressures and the stress field. The motivation for the model comes from the field studies done by Heffer et al.5 showing that there is a strong correlation between the orientation of the principal in-situ stresses with the directionality of flow in fractured reservoirs during water injection. There is also growing evidence that the earth's crust is generally in a metastable state, where most faults and fractures are critically stressed and are on the verge of further slip.13 This situation will broaden the range of cases with strong potential for coupling of fluid flow and deformation.

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Saadatinejad, M. R., and H. Hassani. "Application of wavelet transform for evaluation of hydrocarbon reservoirs: example from Iranian oil fields in the north of the Persian Gulf." Nonlinear Processes in Geophysics 20, no. 2 (April 8, 2013): 231–38. http://dx.doi.org/10.5194/npg-20-231-2013.

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Abstract. The Persian Gulf and its surrounding area are some of the biggest basins and have a very important role in producing huge amounts of hydrocarbon, and this potential was evaluated in order to explore the target for geoscientists and petroleum engineers. Wavelet transform is a useful and applicable technique to reveal frequency contents of various signals in different branches of science and especially in petroleum studies. We applied two major capacities of continuous mode of wavelet transform in seismic investigations. These investigations were operated to detect reservoir geological structures and some anomalies related to hydrocarbon to develop and explore new petroleum reservoirs in at least 4 oilfields in the southwest of Iran. It had been observed that continuous wavelet transform results show some discontinuities in the location of faults and are able to display them more clearly than other seismic methods. Moreover, continuous wavelet transform, utilizing Morlet wavelet, displays low-frequency shadows on 4 different iso-frequency vertical sections to identify reservoirs containing gas. By comparing these different figures, the presence of low-frequency shadows under the reservoir could be seen and we can relate these variations from anomalies at different frequencies as an indicator of the presence of hydrocarbons in the target reservoir.

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Langaas, Kare, Knut I. Nilsen, and Svein M. Skjaeveland. "Tidal Pressure Response and Surveillance of Water Encroachment." SPE Reservoir Evaluation & Engineering 9, no. 04 (August 1, 2006): 335–44. http://dx.doi.org/10.2118/95763-pa.

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Summary A review of the tidal response in petroleum reservoirs is given. Tidal response is caused by periodic changes in overburden stress induced by the ocean tide; the "tidal efficiency factor" is derived by two different approaches and is in line with a recent well test in the Ormen Lange gas field. For small geomechanical pertubations like the tidal effect, we show that a simplified coupling of geomechanics and fluid flow is possible. The coupling is easy to implement in a standard reservoir simulator by introducing a porosity varying in phase with the tide. Simulations show very good agreement with the theory. The observation of the tidal response in petroleum reservoirs is an independent information provider [i.e., it provides information in addition to the (average) pressure and its derivative from a well test]. The implementation of the tidal effect in a normal reservoir simulator gives us the opportunity to study complex multiphase situations and to evaluate the potential of the tidal response as a reservoir-surveillance method. The case studies presented here focus on the possibility of observing water in the near-well region of a gas well. Introduction The main objective of this work is to investigate whether the tidal pressure response in petroleum reservoirs can be used for reservoir surveillance, in particular to detect saturation changes in the near-well region (e.g., to detect water encroachment toward a gas well). The literature seems sparse in this area. Also, our approach of simplified coupling of geomechanics and fluid flow for small geomechanical effects, and the possibility to implement this in a normal reservoir simulator, has not (to our knowledge) been discussed in the literature. Several authors have derived a tidal efficiency factor, but a review and comparison study seems to be missing.

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Juell, Aleksander, Curtis H. Whitson, and Mohammad Faizul Hoda. "Model-Based Integration and Optimization—Gas-Cycling Benchmark." SPE Journal 15, no. 02 (April 7, 2010): 646–57. http://dx.doi.org/10.2118/121252-pa.

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Summary A benchmark for computational integration of petroleum operations has been constructed. The benchmark consists of two gas/ condensate reservoirs producing to a common process facility. A fraction of the processed gas is distributed between the two reservoirs for gas injection. Total project economics is calculated from the produced streams and process-related costs. This benchmark may be used to compare different computational integration frameworks and optimization strategies. Even though this benchmark aims to integrate all parts of a petroleum operation, from upstream to downstream, certain simplifications are made. For example, pipe flow from reservoir to process facility is not included in the integrated model. The methods of model integration and optimization discussed in this paper are applicable to complex petroleum operations where it is difficult to quantify cause and effect without comprehensive model-based integration. A framework for integration of models describing petroleum operations has been developed. An example test problem is described and studied in detail. Substantial gains in full-field development may be achieved by optimizing over the entire production system. All models and data in the benchmark problem are made available so that different software platforms can study the effects of alternative integration methods and optimization solver strategy. The project itself can, and probably should, be extended by others to add more complexity (realism) to the reservoir, process, and economics modeling.

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Lopez Jimenez, Bruno A., and Roberto Aguilera. "Flow Units in Shale Condensate Reservoirs." SPE Reservoir Evaluation & Engineering 19, no. 03 (April 13, 2016): 450–65. http://dx.doi.org/10.2118/178619-pa.

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Summary Recent work has shown that flow units characterized by process or delivery speed (the ratio of permeability to porosity) provide a continuum between conventional, tight-gas, shale-gas, tight-oil, and shale-oil reservoirs (Aguilera 2014). The link between the various hydrocarbon fluids is provided by the word “petroleum” in “Total Petroleum System” (TPS), which encompasses liquid and gas hydrocarbons found in conventional, tight, and shale reservoirs. The work also shows that, other things being equal, the smaller pores lead to smaller production rates. There is, however, a positive side to smaller pores that, under favorable conditions, can lead to larger economic benefits from organic-rich shale reservoirs. This occurs in the case of condensate fluids that behave as dry gas in the smaller pores of organic-rich shale reservoirs. Flow of this dry gas diminishes the amount of liquids that are released and lost permanently in a shale reservoir. Conversely, this dry gas can lead to larger recovery of liquids in the surface from a given shale reservoir and consequently more attractive economics. This study shows how the smaller pores and their associated dry gas can be recognized with the use of process speed (flow units) and modified Pickett plots. Data from the Niobrara and Eagle Ford shales are used to demonstrate these crossplots. It is concluded that there is significant practical potential in the use of process speed as part of the flow-unit characterization of shale condensate reservoirs. This, in turn, can help in locating sweet spots for improved liquid production. The main contribution of this work is the association of flow units and different scales of pore apertures for improving recovery of liquids from shale reservoirs.

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Semenets, S. N., S. S. Nasonova, Yu E. Vlasenko, and L. Yu Krivenkova. "Calculation models of reliability of petroleum reservoirs." Bulletin of Prydniprovs’ka State Academy of Civil Engineering and Architecture, no. 1 (August 26, 2018): 60–67. http://dx.doi.org/10.30838/j.bpsacea.2312.170118.52.40.

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Hasan, Agus, and Bjarne Foss. "Optimal switching time control of petroleum reservoirs." Journal of Petroleum Science and Engineering 131 (July 2015): 131–37. http://dx.doi.org/10.1016/j.petrol.2015.04.027.

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Najafi, M. N., M. Ghaedi, and Saman Moghimi-Araghi. "Water propagation in two-dimensional petroleum reservoirs." Physica A: Statistical Mechanics and its Applications 445 (March 2016): 102–11. http://dx.doi.org/10.1016/j.physa.2015.10.100.

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Tsallis, Constantino, Evaldo M. F. Curado, Maria do Socorro de Souza, Vera L. Elias, Claudio Bettini, Maximiano S. Scuta, and Rodolfo Beer. "Generalized Archie law — application to petroleum reservoirs." Physica A: Statistical Mechanics and its Applications 191, no. 1-4 (December 1992): 277–83. http://dx.doi.org/10.1016/0378-4371(92)90538-2.

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Ohen, Henry A., and Faruk Civan. "Simulation of Formation Damage in Petroleum Reservoirs." SPE Advanced Technology Series 1, no. 01 (April 1, 1993): 27–35. http://dx.doi.org/10.2118/19420-pa.

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Nazina, Tamara, Diyana Sokolova, Denis Grouzdev, Ekaterina Semenova, Tamara Babich, Salimat Bidzhieva, Dmitriy Serdukov, et al. "The Potential Application of Microorganisms for Sustainable Petroleum Recovery from Heavy Oil Reservoirs." Sustainability 12, no. 1 (December 18, 2019): 15. http://dx.doi.org/10.3390/su12010015.

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A microbial enhanced oil recovery (MEOR) technique was tested at low-temperature heavy oil reservoirs (Russia). The bioaugmentation approach used is based on the introduction of hydrocarbon-oxidizing bacteria into the oilfield in combination with an injection of oxygen as a H2O2 solution in order to initiate the first stage of hydrocarbon oxidation and of (NH4)2HPO4 as a source of biogenic elements. Before the pilot trials, the microorganisms of petroleum reservoirs were investigated by high-throughput sequencing, as well as by culture-base and radioisotope techniques. Molecular studies revealed the differences in microbial composition of the carbonate and terrigenous oil reservoirs and the communities of injection and formation water. Aerobic bacteria Rhodococcus erythropolis HO-KS22 and Gordonia amicalis 6-1 isolated from oilfields oxidized oil and produced biosurfactants. Fermentative enrichment and pure cultures produced considerable amounts of low fatty acids and alcohols from sacchariferous substrates. In core-flooding tests, 43.0–53.5% of additional heavy oil was displaced by aerobic bacteria, producing biosurfactants, and 13.4–45.5% of oil was displaced by fermentative bacteria, producing low fatty acids, alcohols, and gas. A total of 1250 t additional oil was recovered as a result of the application of an MEOR technique at the Cheremukhovskoe heavy oil reservoir and Vostochno-Anzirskoe reservoir with light conventional oil.

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Troup, Alison, and Behnam Talebi. "Adavale Basin petroleum plays." APPEA Journal 59, no. 2 (2019): 958. http://dx.doi.org/10.1071/aj18083.

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The Devonian Adavale Basin system is an under-explored, frontier petroleum basin in south-west Queensland. It has a confirmed petroleum system with production from the Gilmore gas field. The age, marine depositional environments and high carbonate content suggest the basin may have unconventional petroleum potential, and there has been renewed interest from industry in evaluating the basin. In support of this, the Queensland Department of Natural Resources, Mines and Energy has examined the source rock properties of the Bury Limestone and Log Creek Formation and has commissioned an update to the SEEBASE® interpretation of the region. Gas- to oil-mature source rocks are found in deep marine shales of the Log Creek Formation, with secondary potential in the shelfal Bury Limestone. The main known reservoir within the Adavale Basin is the Lissoy Sandstone, though sandstones found in other units may also have tight reservoir potential. These petroleum systems elements form several plays, including conventional clastic structural targets, carbonate plays, including possible reef targets, and salt plays associated with doming from the Boree Salt. Potential unconventional targets include tight sandstone, shale and limestone, with recent analysis of an organic-rich marl from the Bury Limestone indicating good retention properties. The overlying Cooper, Galilee and Eromanga basins also contain potential reservoirs for hydrocarbons generated in the Adavale Basin and Warrabin Trough.

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Troup, Alison, Melanie Fitzell, Sally Edwards, Owen Dixon, and Gopalakrishnan Suraj. "Unconventional petroleum resource evaluation in Queensland." APPEA Journal 53, no. 2 (2013): 471. http://dx.doi.org/10.1071/aj12082.

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The search for unconventional petroleum resources requires a shift in the way the petroleum potential of sedimentary basins is assessed. Gas in source rocks and tight reservoirs has largely been ignored in preference for traditional conventional gas plays. Recent developments in technology now allow for the extraction of gas trapped in low-permeability reservoirs. Assessments of the unconventional petroleum potential of basins, including estimates of the potential resource are required to guide future exploration. The Geological Survey of Queensland is collaborating with Geoscience Australia (GA) and other state agencies to undertake regional assessments of several basins with potential for unconventional petroleum resources in Queensland. The United States Geological Survey methodology for assessment of continuous petroleum resources is being adopted to estimate total undiscovered oil and gas resources. Assessments are being undertaken to evaluate the potential of key formations as shale oil and gas and tight-gas plays. The assessments focus on mapping key attributes including depth, thickness, maturity, total organic carbon (TOC), porosity, gas content, reservoir pressure, mineralogy and regional facies patterns using data from stratigraphic bores and petroleum wells to determine play fairways or areas of greatest potential. More detailed formation evaluation is being undertaken for a regional framework of wells using conventional log suites and mudlogs to calculate porosity, TOC, maturity, oil and gas saturations, and gas composition. HyLoggerTM data is being used to determine its validity to estimate bulk mineralogy (clay-carbonate-quartz) compared with traditional x-ray diffraction methods. These methods are being applied to key formations with unconventional potential in the Georgina and Eromanga basins in Queensland.

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Shi, Bao Hong, Juan Wang, and Yan Zhang. "Analysis on Basic Conditions and Main Control Factors of Accumulation in Eastern Area of Yishan Slope of Ordos Basin." Advanced Materials Research 524-527 (May 2012): 10–15. http://dx.doi.org/10.4028/www.scientific.net/amr.524-527.10.

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The group of reservoir and cap-rock in Chang4+5 and Chang6 has good basic conditions of accumulation in eastern area of Yishan Slope of Ordos Basin, because it located up the high quality sources rocks (Chang7) and had a lot of hydrocarbon migrated from western areas. The reservoirs were the sand bodies formed in the distributary channels of delta plain and subaqueous distributary channels of delta front. The cap-rocks were the mudstones and compacted siltites formed in the floodplain and interdistributary areas.They composed lithologic traps. The types of petroleum reservoirs belong to lithologic hydrocarbon reservoir. The distribution of oil layers controlled by depositional microfacies and the excellent quality group of reservoir and cap-rock and migration conditions.

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Wang, L. Y., R. Y. Duan, J. F. Liu, S. Z. Yang, J. D. Gu, and B. Z. Mu. "Molecular analysis of the microbial community structures in water-flooding petroleum reservoirs with different temperatures." Biogeosciences Discussions 9, no. 4 (April 27, 2012): 5177–203. http://dx.doi.org/10.5194/bgd-9-5177-2012.

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Abstract. Temperature is one of the most important environmental factors regulating the activity and determining the composition of the microbial community. Analysis of microbial communities from six water-flooding petroleum reservoirs at temperatures from 20 to 63 °C by 16S rRNA gene clone libraries indicates the presence of physiologically diverse and temperature-dependent microorganisms in these subterrestrial ecosystems. In high-temperature petroleum reservoirs, most of the archaeal sequences belong to the thermophilic archaea including the genera Thermococcus, Methanothermobacter and Thermoplasmatales, most of the bacterial sequences belong to the phyla Firmicutes, Thermotogae and Thermodesulfobacteria; in low-temperature petroleum reservoirs, most of the archaeal sequences are affiliated with the genera Methanobacterium, Methanoculleus and Methanocalculus, most of the bacterial sequences to the phyla Proteobacteria, Bacteroidetes and Actinobacteria. Canonical correspondence analysis (CCA) revealed that temperature, mineralization, ionic type as well as volatile fatty acids showed correlation with the microbial community structures. These organisms may be adapted to the environmental conditions of these petroleum reservoirs over geologic time by metabolizing buried organic matter from the original deep subsurface environment and became the common inhabitants in subsurface environments.

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Worthington, Paul Francis. "Petrophysical Type Curves for Identifying the Electrical Character of Petroleum Reservoirs." SPE Reservoir Evaluation & Engineering 10, no. 06 (December 1, 2007): 711–29. http://dx.doi.org/10.2118/96718-pa.

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Summary A user-friendly type chart has been constructed as an aid to the evaluation of water saturation from well logs. It provides a basis for the inter-reservoir comparison of electrical character in terms of adherence to, or departures from, Archie conditions in the presence of significant shaliness and/or low formation-water salinity. Therefore, it constitutes an analog facility. The deliverables include reservoir classification to guide well-log analysis, a protocol for optimizing the acquisition of special core data in support of log analysis, and reservoir characterization in terms of an (analog) porosity exponent and saturation exponent. The type chart describes a continuum of electrical behavior for both water and hydrocarbon zones. This is important because some reservoir rocks can conform to Archie conditions in the fully water-saturated state, but show pronounced departures from Archie conditions in the partially water-saturated state. In this respect, the chart is an extension of earlier approaches that were restricted to the water zone. This extension is achieved by adopting a generalized geometric factor—the ratio of water conductivity to formation conductivity—regardless of the degree of hydrocarbon saturation. The type chart relates a normalized form of this geometric factor to formation-water conductivity, a "shale" conductivity term, and (irreducible) water saturation. The chart has been validated using core data from comprehensively studied reservoirs. A workflow details the application of the type chart to core and/or log data. The analog role of the chart is illustrated for reservoir units that show different levels of non-Archie effects. The application of the method should take rock types, scale effects, the degree of core sampling, and net reservoir criteria into account. The principal benefit is a reduced uncertainty in the choice of a procedure for the petrophysical evaluation of water saturation, especially at an early stage in the appraisal/development process, when adequate characterizing data may not be available. Introduction One of the ever-present problems in petrophysics is how to carry out a meaningful evaluation of well logs in situations where characterizing information from quality-assured core analysis is either unavailable or is insufficient to satisfactorily support the log interpretation. This problem is especially pertinent at an early stage in the life of a field, when reservoir data are relatively sparse. Data shortfalls could be mitigated if there was a means of identifying petrophysical analogs of reservoir character, so that the broader experience of the hydrocarbon industry could be utilized in constructing reservoir models and thence be brought to bear on current appraisal and development decisions. Here, a principal requirement calls for type charts of petrophysical character, on which data from different reservoirs can be plotted and compared, as a basis for aligning approaches to future data acquisition and interpretation. This need manifests itself strongly in the petrophysical evaluation of water saturation, a process that traditionally uses the electrical properties of a reservoir rock to deliver key building blocks for an integrated reservoir model. The solution to this problem calls for an analog facility through which the electrical character of a subject reservoir can be compared with others that have been more comprehensively studied. In this way, the degree of confidence in log-derived water saturation might be reinforced. At the limit, the log analyst needs a reference basis for recourse to capillary pressure data in cases where the well-log evaluation of water saturation turns out to be prohibitively uncertain.

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Worden, Richard H., and Emma C. Heasley. "Effects of petroleum emplacement on cementation in carbonate reservoirs." Bulletin de la Société Géologique de France 171, no. 6 (November 1, 2000): 607–20. http://dx.doi.org/10.2113/171.6.607.

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Abstract Carbonate diagenesis can theoretically either be enhanced or retarded by petroleum emplacement depending on: the oil-water wettability of the rocks, the CO 2 -content of the migrated petroleum, and the presence of oxidised sulphur or iron compounds in the rocks. A detailed case study of Jurassic oolites from a UK oil field showed first that petroleum emplacement retarded diagenesis in the oil leg and thus helped preserve permeability, but second showed that entrained CO 2 caused cementation and pore-system modification in the water leg.

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Jackson, J., I. P. Sweet, and T. G. Powell. "STUDIES ON PETROLEUM GEOLOGY AND GEOCHEMISTRY, MIDDLE PROTEROZOIC, McARTHUR BASIN NORTHERN AUSTRALIA I: PETROLEUM POTENTIAL." APPEA Journal 28, no. 1 (1988): 283. http://dx.doi.org/10.1071/aj87022.

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Mature, rich, potential source beds and adjacent potential reservoir beds exist in the Middle Proterozoic sequence (1400-1800 Ma) of the McArthur Basin. The McArthur and Nathan Groups consist mainly of evaporitic and stromatolitic cherty dolostones interbedded with dolomitic siltstone and shale. They were deposited in interfingering marginal marine, lacustrine and fluvial environments. Lacustrine dolomitic siltstones form potential source beds, while potential reservoirs include vuggy brecciated carbonates associated with penecontemporaneous faulting and rare coarse-grained clastics. In contrast, the younger Roper Group consists of quartz arenite, siltstone and shale that occur in more uniform facies deposited in a stable marine setting. Both source and reservoir units are laterally extensive (over 200 km).Five potential source rocks at various stages of maturity have been discovered. Two of these source rocks, the lacustrine Barney Creek Formation in the McArthur Group and the marine Velkerri Formation in the Roper Group, compare favourably in thickness and potential with rich demonstrated source rocks in major oil-producing provinces. There is abundant evidence of migration of hydrocarbons at many stratigraphic levels. The geology and reservoir characteristics of the sediments in combination with the distribution of potential source beds, timing of hydrocarbon generation, evidence for migration and chances of preservation have been used to rank the prospectivity of the various stratigraphic units in different parts of the basin.

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Warnecki, Marcin, Mirosław Wojnicki, Jerzy Kuśnierczyk, and Sławomir Szuflita. "Analizy PVT jako skuteczne narzędzie w rękach inżyniera naftowego. Pobór wgłębnych próbek płynów złożowych do badań PVT." Nafta-Gaz 76, no. 11 (November 2020): 784–93. http://dx.doi.org/10.18668/ng.2020.11.03.

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The most important aspect of laboratory analysis is undoubtedly to acquire data of the highest quality. The worldwide trend of drilling into deeper reservoirs characterised by the high temperature and high pressure (HTHP) conditions makes the newly discovered reservoirs challenging because of bearing fluids with an unprecedented diversity of phase behaviour and variability of phase parameters over time. Due to the high temperature of the deep horizons constituting the reservoir rock, many individual components of the reservoir fluids are located in a region close to their critical temperatures, i.e. gas condensate (retrograde condensation region) or volatile oil. In particular, gas condensate reservoirs are challenging to analyse. They are highly prone to the errors resulting from phase behaviour testing when using samples that are incompatible with the original reservoir in-situ fluid that saturates the reservoir rock pores. Taking the representative samples of reservoir fluid is an essential requirement to obtain reliable data that can characterise such phase-variable multicomponent reservoirs. The primary purpose of hydrocarbon fluid analysis in case of new discoveries is to determine the type of reservoir fluid system. It should also be borne in mind that without a sufficiently long production process from several intervals and/or several wells, it can be challenging to classify the fluid with confidence, especially at the initial analysis stage. The paper presents issues related to sampling of the reservoir fluid (such as crude oil and natural gas) for the physical property and phase behaviour analyses (PVT), usually accompanied by chemical analyses. The importance of representativeness of the samples in performing reliable tests that have a significant impact on the hydrocarbon production was discussed. The data obtained from the PVT laboratory are widely used in economic reports concerning local, regional or finally national hydrocarbon reserves. Other applications of the PVT data include coordination of reservoir exploitation methods related to a particular fluid composition, as well as input to design requirements for the surface facilities development, and selection of the suitable technology for hydrocarbon fluid treatment prior to introduction to the market. Various techniques of downhole sampling were mentioned and characterised with an explanation of their applicability. The criteria for selection of a proper method were also presented.

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Chapman, R. E. "GEOLOGICAL REASONING FOR THE PETROLEUM SOURCE ROCKS OF KNOWN FIELDS." APPEA Journal 26, no. 1 (1986): 132. http://dx.doi.org/10.1071/aj85014.

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Geological reasoning for the petroleum source-migration-accumulation relationships centres around petroleum composition and its variability, water composition and its variability, and stratigraphy. For example, a field with several pools of petroleum of different compositions is likely to have been sourced from several distinct source rocks that are stratigraphically associated with the reservoir rocks. If water compositions are also variable, the conclusion is reinforced. A field with several pools of petroleum of similar quality was sourced either from similar source rocks that are stratigraphically associated with the reservoirs, or from a single source that is removed from the accumulations. There are also considerations of wax content, environment of deposition of the reservoir sequence, sand/shale ratios, and faulting.Geological reasoning does not always lead to the same conclusions as geochemical reasoning. Such cases are particularly important for petroleum geology because they should lead us to a better understanding of the source-migration-accumulation relationships. Some of the remaining giant oil accumulations of the world may be in areas that would be discarded on geochemical evidence. Most of the crude oil remaining to be discovered will be in relatively few giant fields, so misunderstanding could jeopardize our future supplies.

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Zhang, LiKuan, Xiaorong Luo, Mingze Ye, Baoshou Zhang, Hongxing Wei, Binfeng Cao, Xiaotong Xu, Zhida Liu, Yuhong Lei, and Chao Li. "Small-Scale Diagenetic Heterogeneity Effects on Reservoir Quality of Deep Sandstones: A Case Study from the Lower Jurassic Ahe Formation, Eastern Kuqa Depression." Geofluids 2021 (March 24, 2021): 1–25. http://dx.doi.org/10.1155/2021/6626652.

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The Lower Jurassic Ahe Formation is an important exploration target for deep clastic reservoirs in the eastern Kuqa Depression. The Ahe Formation sandstones show heterogeneous porosity and permeability petrophysical properties. These properties have been poorly understood, limiting forecast of petroleum accumulations and making it difficult to develop the reservoirs. Based on cores, thin sections, SEM, and fluid inclusions, this study examined sandstone composition and texture and diagenetic heterogeneity at the core scale. The aim was to understand the influence of variations in detrital composition and texture on diagenetic and reservoir quality evolution. The Ahe Formation sandstones are dominantly fine- to coarse-grained litharenites, with minor feldspathic litharenites. In fining-up sand beds, detrital grain size determines the degree of mechanical compaction and, consequently, the abundance of porosity through ductile grains and muddy matrix. Local complete calcite cementation is a noticeable exception to this general trend. Three sandstone petrofacies have been defined based on texture and framework composition, detrital matrix, diagenesis, and pore types: (1) ductile-lean sandstone, (2) ductile-rich sandstone, and (3) tightly calcite-cemented sandstone. Different petrofacies experienced contrasting diagenetic and porosity evolution pathways. Ductile-lean sandstones underwent lower degree of compaction relative to ductile-rich sandstones during the eodiagenesis stage, and extensive grain dissolution occurred. The petrofacies remained relatively porous and permeable before early oil arrival. With continued burial, the porosity and permeability in the sandstones were further reduced by cementation. The petrofacies still had moderate porosity and permeability and were substantially charged when late petroleum migrated into the reservoirs. Thus, ductile-lean sandstones constitute effective reservoir rocks in deep reservoirs. By translating petrofacies to signatures of well logs, the effective properties of the reservoir rocks can be forecasted at the well scale.

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He, Zhiliang, Qian Ding, Yujin Wo, Juntao Zhang, Ming Fan, and Xiaojuan Yue. "Experiment of Carbonate Dissolution: Implication for High Quality Carbonate Reservoir Formation in Deep and Ultradeep Basins." Geofluids 2017 (2017): 1–8. http://dx.doi.org/10.1155/2017/8439259.

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As the most frontiers in petroleum geology, the study of dissolution-based rock formation in deep carbonate reservoirs provides insight into pore development mechanism of petroleum reservoir space, while predicting reservoir distribution in deep-ultradeep layers. In this study, we conducted dissolution-precipitation experiments simulating surface to deep burial environments (open and semiopen systems). The effects of temperature, pressure, and dissolved ions on carbonate dissolution-precipitation were investigated under high temperature and pressure (~200°C; ~70 Mpa) with a series of petrographic and geochemical analytical methods. The results showed that the window-shape dissolution curve appeared in 75~150°C in the open system and 120~175°C in the semiopen system. Furthermore, the dissolution weight loss of carbonate rocks in the open system was higher than that of semiopen system, making it more favorable for gaining porosity. The type of fluid and rock largely determines the reservoir quality. In the open system, the dissolution weight loss of calcite was higher than that of dolomite with 0.3% CO2as the reaction fluid. In the semiopen system, the weight loss from dolomitic limestone prevailed with 0.3% CO2as the reaction fluid. Our study could provide theoretical basis for the prediction of high quality carbonate reservoirs in deep and ultradeep layers.

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Wilt, Michael, Clifford Schenkel, Tom Daley, John Peterson, Ernest Majer, A. S. Murer, R. M. Johnston, and Louis Klonsky. "Mapping Steam and Water Flow in Petroleum Reservoirs." SPE Reservoir Engineering 12, no. 04 (November 1, 1997): 284–87. http://dx.doi.org/10.2118/37532-pa.

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Bata, Timothy, John Parnell, Stephen Bowden, Adrian Boyce, and Dale Leckie. "Origin of heavy oil in Cretaceous petroleum reservoirs." Bulletin of Canadian Petroleum Geology 64, no. 2 (June 2016): 106–18. http://dx.doi.org/10.2113/gscpgbull.64.2.106.

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Mazo, Alexandr, and Konstantin Potashev. "Scaling in Super Element Model of Petroleum Reservoirs." Journal of Physics: Conference Series 1392 (November 2019): 012072. http://dx.doi.org/10.1088/1742-6596/1392/1/012072.

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Montel, François, Jacques Bickert, Aurélie Lagisquet, and Guillaume Galliéro. "Initial state of petroleum reservoirs: A comprehensive approach." Journal of Petroleum Science and Engineering 58, no. 3-4 (September 2007): 391–402. http://dx.doi.org/10.1016/j.petrol.2006.03.032.

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Abreu, E., J. Douglas, F. Furtado, D. Marchesin, and F. Pereira. "Three-phase immiscible displacement in heterogeneous petroleum reservoirs." Mathematics and Computers in Simulation 73, no. 1-4 (November 2006): 2–20. http://dx.doi.org/10.1016/j.matcom.2006.06.018.

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Dellagnezze, Bruna Martins, Gabriel Vasconcelos de Sousa, Laercio Lopes Martins, Daniela Ferreira Domingos, Elmer E. G. Limache, Suzan Pantaroto de Vasconcellos, Georgiana Feitosa da Cruz, and Valéria Maia de Oliveira. "Bioremediation potential of microorganisms derived from petroleum reservoirs." Marine Pollution Bulletin 89, no. 1-2 (December 2014): 191–200. http://dx.doi.org/10.1016/j.marpolbul.2014.10.003.

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Qin, Yaqiong, Zhaohui Ye, and Conghui Zhang. "Application of GBDT for division of petroleum reservoirs." Journal of Physics: Conference Series 1437 (January 2020): 012050. http://dx.doi.org/10.1088/1742-6596/1437/1/012050.

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Guidi, M. C., and O. J. Romero. "Numerical Simulation of Surfactant Flooding in Petroleum Reservoirs." IEEE Latin America Transactions 16, no. 6 (June 2018): 1700–1707. http://dx.doi.org/10.1109/tla.2018.8444389.

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Higgs, Karen E., Greg H. Browne, and Angus D. Howden. "Murihiku rocks as potential petroleum reservoirs in Zealandia." New Zealand Journal of Geology and Geophysics 61, no. 4 (September 19, 2018): 508–23. http://dx.doi.org/10.1080/00288306.2018.1509879.

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Oliver, Dean S., Yanfen Zhang, Hemant A. Phale, and Yan Chen. "Distributed parameter and state estimation in petroleum reservoirs." Computers & Fluids 46, no. 1 (July 2011): 70–77. http://dx.doi.org/10.1016/j.compfluid.2010.10.003.

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Houston, S. J., and B. W. D. Yardley. "Calcium variation in formation waters from petroleum reservoirs." Geochimica et Cosmochimica Acta 70, no. 18 (August 2006): A267. http://dx.doi.org/10.1016/j.gca.2006.06.538.

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Journal articles on the topic 'Petroleum reservoirs'

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