Journal of Southwest Petroleum University(Science & Technology Edition)

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Mechanism of Complex Modes of the Pore Structure of Sandstone/Conglomerate Reservoirs

YIN Senlin, CHEN Gongyang, CHEN Yukun, WU Xiaojun

西南石油大学学报(自然科学版) 2019, 41 (1): 1-17. DOI: 10.11885/j.issn.1674-5086.2018.01.01.01

Abstract （432）

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The formation mechanism of complex modes of the pore structure of sandstone/conglomerate reservoirs is still unclear. Thus, this study investigated the difference mechanisms of lithofacies classification, pore structure modes, and displacement efficiencies based on experimental data of 325 core examples through mercury intrusion porosimetry, cast thin sections, scanning electron microscopy, and X-ray computed tomography. The results reveal that, taking both oil field exploitation and utility into consideration, lithofacies of sandstone/conglomerate reservoirs can be classified to 3 primary categories, 7 secondary categories, and 13 tertiary categories. They have different pore structure modal characteristics and relatively great variance in their efficiency of displacement by water injection. Single-mode rock particles are mostly coarse sandstones with highly developed and relatively well inter-connected pores in a network structure. The displacement by water injection is mainly via connected networks, resulting in higher efficiency. Dual-mode rock particles are composed of two classes of particles:conglomerates and medium-coarse sandstones. They have relatively developed and moderately inter-connected pores in a sparse network structure. The displacement, here, is mainly via star-shaped connected networks, with ordinary efficiency. Complexmode rock particles consist of three types of particles:conglomerates, medium-coarse sandstones, and silt or mud. Their pores are moderately developed and relatively poorly inter-connected with a star-shaped networking structure. The water injectiondriven displacement is mostly scattered over local high-permeability zones, resulting in poor overall efficiency. The same lithofacies typically show different pore structure modes while different lithofacies can have identical structure modes. Differential transformation due to particle configuration and diagenesis leads to different pore structure modes for identical lithofacies; while sorting, rounding, and arrangement of particles result in identical pore structure modes for different lithofacies.

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Quantitative Characterization of Heterogeneity and Geological Modeling of the Yingmai X1 Dolomite Oil Reservoir

CAO Peng, DAI Chuanrui, ZHANG Chao, CHANG Shaoying, LIU Jiangli

西南石油大学学报(自然科学版) 2019, 41 (1): 18-32. DOI: 10.11885/j.issn.1674-5086.2017.11.08.01

Abstract （405）

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The Yingmai X1 dolomite oil reservoir has entered the ultra-high water-cut exploitation stage; therefore, it is particularly important to quantitatively characterize the heterogeneity of the reservoir and determine the distribution pattern of residual oil. This study examines the field geologic outcrop, and the results are integrated with characteristics of individual boreholes. We find that the heterogeneity of the Yingmai X1 dolomite oil reservoir is primarily controlled by sedimentation cycles and lithological properties. High-quality reservoirs are mostly located in fine to medium-grained dolomite. Low-permeability bands formed by micritic dolomite influence fluid seepage behavior. The six low-permeability stratigraphic frameworks developed in the reservoir predominantly govern the distribution pattern of the residual oil. By calculating the true thicknesses of stratigraphic layers and using thin-layer inversion techniques, stratigraphic frameworks were constructed and applied as constraints in establishing geological and numerical models for oil reservoirs. It is estimated that the residual oil reserve in the dolomite region amounts to 133.33×10 ⁴ t and production can reach 22.9×10 ⁴ t if appropriate measures are introduced. The methodology of this study can be a valuable reference for exploiting similar oil reservoirs.

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The Reservoir Characteristics and the Pore Evolution of Yingshan Formation in Gucheng Region, Tarim Basin

ZHANG Shaonan, HUANG Baiwen, SUI Huan, YE Ning, LI Yingtao

西南石油大学学报(自然科学版) 2019, 41 (1): 33-46. DOI: 10.11885/j.issn.1674-5086.2018.08.31.01

Abstract （424）

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This study focuses on the pore evolution during the diagenetic period of the Yingshan Formation in the Gucheng region in the Tarim Basin. Specifically, the petrophysical characteristics, diagenetic effect, and reservoir characteristics of the target layers are investigated based on the analysis of core description, flake identification, cathodoluminescence, well logging data, and geochemical data. The results show that reservoir rocks of Yingshan Formation in Gucheng region are primarily composed of limestone and dolomite. Of which, the dolomite is mostly distributed in the lower section of the Yingshan Formation. Furthermore, the fine grained automorphic-semi-automorphic dolomite and medium-coarse crystalline dolomite both exhibit relatively good porosity. The reservoir space is mainly made up of intercrystalline pores, intercrystalline pores and cracks, which forms three types of reservoirs including the crack type, pore type, and crack-hole type reservoirs. The diagenetic effect has a significant impact on the storing performance of the reservoir in the research region. In particular, the early cementation, compaction and pressure dissolution, silicidation, and filling of hydrothermal minerals have a destructive effect on the primary pores. The dolomitization, rupture, and hydrothermal dissolution in the shallow burial are constructive diagenetic effects. Affected by the transitional dolomitization, the intercrystalline pores in dolomites exhibit a low degree of development. The hydrothermal dissolution effect plays a key role in the formation of high-quality reservoir.

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Characteristics and Controlling Factors of High-quality Dolomite Reservoirs in the Permian Qixia Formation, Northwestern Sichuan

BAI Xiaoliang, YANG Yueming, YANG Yu, WEN Long, LUO Bing

西南石油大学学报(自然科学版) 2019, 41 (1): 47-56. DOI: 10.11885/j.issn.1674-5086.2017.12.25.02

Abstract （242）

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The characteristics and primary controlling factors of high-quality dolomite reservoirs in the Qixia Formation in the northwestern Sichuan Basin were studied based on the diversity of their genesis and distribution. Through field studies, observation and analysis of cores and lamellae, and interpretation of well log images, the lithology and spatial characteristics of the Qixia Formation reservoir were summarized and the patterns of distribution of dolomite reservoirs in the Qixia Formation were analyzed. Finally, the main factors controlling the development of high-quality dolomite reservoirs in the Qixia Formation are discussed. It is believed that (1) the particle size in the Qixia Formation-coarse-grained dolomite and sugary dolomite-reflect a significant increase in the thickness of grain-bearing facies in the uplift near the end of the Carboniferous fully demonstrates that the paleogeomorphology before the Permian deposition controlled the distribution of beach facies in the Qixia Formation. (2) The Qixia Formation in the northwestern Sichuan Basin is a phased dolomite reservoir. The primary reservoir lithology is subhedral-euhedral-coarse grain dolomite, saccharoid-subhedral-intermediate grain dolomite, with obvious residual particle imaging, intergranular development of porosity, replacement of bright-grain limestone with dolomite, and inheritance and adjustment of intergranular pores in the original limestone. (3) The Qixia Formation in northwestern Sichuan experienced multiple hydrothermal activities in deep-buried conditions, and development of intergranular dissolution pores in medium-to-coarse-grained dolomite and dissolution pores in the dolomite crystal face. Beach-phase dolomite superimposed with buried hydrothermal activity and tectonic fracture reconstruction have resulted in large-scale distribution of high-quality dolomite reservoirs.

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Investigation of the Typical Oil Reserves and Selection of Exploration Fields of the Dabasong Fan, Eastern Slope of the Mahu Depression

QIAN Haitao, BAI Yu, YOU Xincai, LI Peng, YIN Lu

西南石油大学学报(自然科学版) 2019, 41 (1): 57-67. DOI: 10.11885/j.issn.1674-5086.2017.11.07.06

Abstract （246）

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The eastern slope of the Mahu Depression in the Junggar Basin possesses excellent conditions for oil reserve formation and characteristics indicative of an oil reserve of large area. The region has been scarcely explored, so it is a key area for oil and gas exploration. To determine the oil reserve formation pattern along the eastern slope of the Mahu Depression and to allow in-depth oil and gas exploration in the region, data from boreholes, cores, seismology, and analytical tests were integrated and techniques such as palaeo-geomorphology reconstruction, sedimentary facies characterization, and reservoir prediction for gravel-containing medium to coarse sandstones were employed. The oil reserve characteristics, main controlling factors, and exploration fields of the Triassic Baikouquan Formation at the DA13 site in the north wing of the Dabasong Fan were examined. The results demonstrate that the oil reserve is a fault-lithologic reservoir and is mainly jointly controlled by faults and largescale wide and gentle platform zones, slope breaks, and favorable front facies belts. While oil accumulation and sand bodies are determined by tectonics and slope breaks, respectively, the reserve itself is controlled by both lithology and faults. Therefore, by comparing the reserve formation conditions, it is confirmed that the south and north wings of the Dabasong Fan have similar reserve formation backgrounds and conditions. By analyzing the single-well facies and the seismic facies, large-scale favorable front facies belts and multiple fault-lithological traps are noted under the south wing of the Dabasong Fan. The region has great potential for exploration and is the favorable site for expanding oil and gas exploration in the Baikouquan Formation along the eastern slope of the Mahu Depression.

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Patterns and Comprehensive Predictions of Fracture Development in Bedrock Gas Reservoirs in Dongping, Qaidam Basin

LI Xiang, LIU Yingru, CHAI Xiaoying, LONG Wei, BAI Yadong

西南石油大学学报(自然科学版) 2019, 41 (1): 68-76. DOI: 10.11885/j.issn.1674-5086.2017.11.15.01

Abstract （213）

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Located in the front eastern section of the Altyn-Tagh in the northwestern Qaidam Basin, the Dongping bedrock reservoir is the largest complete bedrock buried hill gas reservoir recently discovered in the terrestrial basins of China. Nevertheless, due to natural fractures in gneiss and granite bedrocks and karst caves in the region and their complex formations, the area is highly heterogeneous with significant yield differences between wells. In addition, mass exploitation of a large-scale gas reservoir is relatively difficult. Because fractures are the key factor in allowing high and stable yields of bedrock reservoirs, it is especially important to conduct research on patterns and comprehensive predictions of fracture development in the reservoir of interest. Hence, lithological and physical properties and reserve types of the reservoir were examined, followed by statistical analyses based on core samples, thin sections, and well imaging. We found that the fracture system of the Dongping bedrock reservoir is dominated by tectonic fractures, accompanied by two types of dissolution fractures. The statistics of individual wells were used as standards to divide the study area according to its lithology. The Post-Stack Amplitude Direction Decomposition (PADD) technique was employed to predict the horizontal distribution of fractures in the study area. Finally, the results were integrated and analyzed with yield data. According to the relative relationships between different lithological zones, different fracture types, yields, and transformation effects, the study area was divided into three effective fracture development zones. One is a natural high-yield zone, while the other two are potential areas requiring appropriate transformation measures. Comprehensive predictions of reservoir potential in the study area were performed, and the predicted results matched actual yields at a rate higher than 70%.

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Reservoir Architecture-based Classification of Seepage Barriers of Flow Unit

WAN Qionghua, LUO Wei, LIANG Jie, CHEN Chen, YANG Qiufei

西南石油大学学报(自然科学版) 2019, 41 (1): 77-84. DOI: 10.11885/j.issn.1674-5086.2018.05.08.01

Abstract （400）

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With more in-depth investigations on various reservoir architectures, the theories of reservoir architectures have become increasingly mature, but application of the research results remains lagging. In this study, based on existing research on the architecture of typical braided stream reservoirs, a braided stream reservoir in the A Oilfield is divided into various architectural elements, such as the braided channels, mid-channel bars, silt layers, and troughs on bars. Criteria and methods for recognizing the seepage barriers and the connected bodies of braided stream reservoirs are analyzed and summarized, in order to provide intuitive guidance for oil and gas field exploration. The results reveal that the recognition of seepage barriers and the connected bodies establishes a linkage between the static architectural model at the pre-exploration stage and the dynamic classification of flow units at the exploration stage of oil reservoirs. Different classes of seepage barriers constrain different types of flow units. The development of seepage barriers directly impacts the types of the surrounding flow units and, thereby, affects the fluid movement pattern in the oil reservoir.

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P-wave to S-wave Velocity Ratio Scanning Method Based on the Sinc Interpolation and Correlation Spectrum

WANG Jian, WU Bo, XU Tianji

西南石油大学学报(自然科学版) 2019, 41 (1): 85-90. DOI: 10.11885/j.issn.1674-5086.2018.01.11.01

Abstract （177）

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In the multi-component seismic technique, accurate extraction of the P-wave to S-wave velocity ratio ( γ) is an important step in multi-component data processing, inversion, and interpretation. As the wave impedance ratio for the same underground layer is the same, the reflected P-wave and reflected converted wave are interrelated at this layer. The P-wave to S-wave velocity ratio and time ratio can be mutually converted. In the P-wave to S-wave velocity ratio scanning method based on the sinc interpolation algorithm and correlation coefficient spectrum analysis, a series is set, and the sinc interpolation algorithm is used to cross-correlate the stretched P-wave with the converted wave. When the cross-correlation coefficient reaches its maximum value, the corresponding ratio can be obtained. The effectiveness, accuracy, and practicality of this method are verified through testing with both theoretical and actual data.

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Study on Stress Sensitivity of the Formation Factors of Low-permeability Sandstones

LIU Zhongqun, CHEN Meng, LI Min

西南石油大学学报(自然科学版) 2019, 41 (1): 91-101. DOI: 10.11885/j.issn.1674-5086.2017.09.12.02

Abstract （186）

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To explore the influences of effective stress variations on the formation factors of the low-permeability sandstone reservoirs in the Ordos Basin, the formation factors of seven core samples under varying confining pressures ( p _c) and internal pressures (also known as pore pressures, p _p) were obtained experimentally. Experimental data were analyzed based on Biot's definition of effective stress and response surface functions. It is found that the effective stress coefficient ( α) obtained through the response surface secant method can characterize the effective stress more accurately. Also, α is discovered not to be a constant at 1.00, but be distributed within the range of 0.04～0.60, having certain functional relationships with the confining and internal pressures. It is confirmed that the formation factors of low-permeability sandstone reservoirs change non-linearly with the effective stress and that microfractures are the main cause of non-linear variations in effective stress. An equivalent microfracture model was established based on the microscopic structure of the cores. It was integrated with the theory of rock resistivity to deduce the functional relationships between formation factor and effective stress and to characterize the variation pattern of formation factors of low-permeability sandstone reservoirs under the action of non-linear effective stresses.

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Experimental Study on Hot Water Flooding in Tight Sandstone Reservoir to Reduce Water Injection Pressure and Increase Injection Capacity

YANG Shukun, GUO Hongfeng, ZHAO Guangyuan, JI Gongming, ZHANG Bo

西南石油大学学报(自然科学版) 2019, 41 (1): 102-110. DOI: 10.11885/j.issn.1674-5086.2018.04.04.02

Abstract （303）

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To investigate the use of hot water flooding to reduce water injection pressure and increase injection capacity in tight sandstone reservoirs, laboratory-based physical models were used to study the effects of hot water flooding on clay minerals from the target block in terms of hydration-induced expansion, rock pore structure, oil-water viscosity, crude oil thermal expansion, oil-water interfacial tension, oil and water phase starting pressures, and oil-water relative permeability curve. The mechanisms by which hot water flooding reduced water injection pressure and increased injection capacity in tight sandstone reservoirs were analyzed, and the effectiveness of hot water flooding at achieving these processes was assessed for a range of hot-water temperatures. Our experimental results showed that hot water flooding was highly effective at reducing water injection pressure and increasing injection capacity. Increase in the temperature of the water flood decreased the starting pressure of water injection and weakened the impact of the peak effect, thus improving the ability of the water flood at reducing water injection pressure and increasing injection capacity. The effectiveness of hot water flooding differed with the permeabilities of the rock cores and generally improved with decreases in the permeability coefficients of the rock cores. Finally, it was found that the optimal temperature for hot water flooding in the targeted tight sandstone reservoir block was approximately 100℃.

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Study of the Transport Mechanism of Low-speed Displacement in Eccentric Annulus of Horizontal Wells

SUN Jinfei, LI Zaoyuan, LUO Pingya, ZHANG Ganggang, JIAO Shaoqing

西南石油大学学报(自然科学版) 2019, 41 (1): 111-118. DOI: 10.11885/j.issn.1674-5086.2018.01.11.03

Abstract （234）

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When displacing the cementing of horizontal wells, it is usually difficult to realize the replacement in turbulent flow because of instrumental limitation. In laminar flow, however, the transport mechanism of two-phase flow in the eccentric annulus can be quite complex. Based on the computational fluid dynamics method, we developed a geometric and numerical model, tracked the displacement interface of two-phase flow using the fluid volume method, and analyzed the transport mechanism of displacing fluids in the eccentric annulus of horizontal wells under various displacing flow rates. The following conclusions are drawn from the results:(1) With a low eccentricity, one-time use of isolation fluid can realize 90% displacing efficiency. When the eccentricity is greater than 0.5, the displacing efficiency becomes relatively small. In this case, increasing the amount of isolation fluids cannot further increase the displacing efficiency; (2) Considering the severe eccentricity of the casing, reducing the flow rate from 1.0 m/s to 0.2 m/s can help stabilize the interface and results in 6.8%higher displacement of drilling oil. Furthermore, this approach can also resolve the retention issue on the narrow side and pointing issue on the wide side; (3) The cementing displacement process in the eccentric annulus of horizontal wells is affected by multiple factors, including the eccentric effect, gravity effect, and viscous effect. These factors interact and inhibit with each other. Therefore, a reasonable design of cementing process parameters based on the actual well conditions on site can not only improve cementing quality, but also reduce cost and increase efficiency.

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Prediction of Dynamic Sanding in Unconsolidated Sandstone Reservoirs of Bohai Oilfield

LI Jin, XU Jie, GONG Ning, HAN Yaotu, GAO Bin

西南石油大学学报(自然科学版) 2019, 41 (1): 119-128. DOI: 10.11885/j.issn.1674-5086.2018.04.08.01

Abstract （398）

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The accurate prediction of the risk of sanding is a key technological measure for sanding prevention. The Bohai Oilfield currently utilizes static methods for sanding prediction, which do not account for changes in ground stress, water saturation, reservoir pressure depletion, and pressure drawdown during oil production processes, and these have dynamic effects on reservoir sanding. This results in significant difference between the sanding predictions of the methods used and reality, and these predictions only provide general guidance for sanding prevention design. In this work, we investigated commonly used well completion methods in the Bohai Oilfield, namely oriented perforating and horizontal open hole wells, and constructed a method for predicting dynamic sanding throughout the lifecycle of an unconsolidated sandstone reservoir in the Bohai Oilfield based on analyses of the factors and mechanisms governing dynamic sanding and mechanical stabilities of wellbores. Our method provides a comprehensive analysis of the dynamic effects of ground stress, water content, pressure drawdown, and pressure depletion on reservoir sanding, thus enabling dynamic predictions and analyses of sanding risks throughout the petroleum extraction lifecycle of a reservoir. In practice, it was shown that our proposed method predicted the sanding of unconsolidated sandstone reservoirs in a more precise, accurate, and realistic manner than existing methods. The findings of this study will therefore contribute to optimization of sanding prevention measures, thus reducing costs and improving productivity.

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Optimization of Parameters for Well Flushing via Hot Fluid Circulation in Offshore Electric Submersible Pump Wells Clogged by Wax Deposits

YANG Wanyou, ZHENG Chunfeng, LI Ang, WANG Lei

西南石油大学学报(自然科学版) 2019, 41 (1): 129-136. DOI: 10.11885/j.issn.1674-5086.2018.04.18.02

Abstract （227）

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To investigate the distribution patterns of wellbore temperature fields during well flushing via hot fluid circulation in electric submersible pump (ESP) wells of the Bohai Oilfield, we constructed a computational model for the temperature fields of wellbores during hot fluid circulation in ESP wells based on the principle of conservation of heat. This model accounts for effects associated with the heating of the ESP, electric cable cooling, volume of hot fluid injection, injection depth, injection temperature, heat transfer in the wax-clogged pipeline segments, and thermal conductivities of seawater and air. Using this model, we analyzed the effects of injection temperature and injection volume on the wellbore temperature distribution of mixed production fluids. The results of this study show that the temperature distributions of mixed production fluids along the wellbore are positively correlated with increases in injection temperature and injection volume. Our model can be used as a guide to dewaxing processes in the field, thus prolonging the dewaxing cycles in wax-prone wells and reducing the rates at which fluid and oil production decrease over time.

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A 3-D Physical Simulation Experiment and Numerical Test on Multi-thermal Fluids Flooding After Huff and Puff

LIU Dong, SU Yanchun, CHEN Jianbo, ZHANG Caiqi, PAN Guangming

西南石油大学学报(自然科学版) 2019, 41 (1): 137-146. DOI: 10.11885/j.issn.1674-5086.2017.11.07.02

Abstract （247）

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Aiming at the problems of injection multi-thermal fluids (the mixture of the high temperature of steam, hot water, nitrogen and carbon dioxide), such as more components, more complex mechanism, different from conventional steam injection etc., a 3-D physical simulation experiment and numerical test on multi-thermal fluids flooding after huff and puff is carried out. Based on similarity criterion and taking a typical block of heavy oil in bohai oilfield as the prototype, a scaled three-dimensional physical model is established firstly. And the corresponding law between multi-thermal fluids flooding production performance and the stage of heated chamber extending is researched by three-dimensional physical simulation experiment of multi-thermal fluids flooding after huff and puff by horizontal wells. Then, the numerical simulation software stars module was used to establish the numerical model, on the basis of history matching of physical model, three numerical tests of multi-thermal fluids flooding, steam flooding and steam compound nitrogen to carbon dioxide flooding are carried out, and the temperature field and production performance are contrast analyzed. Finally, the best injection production parameters of N heavy Oilfield are optimized by numerical tests. The results can provide guidance and reference for the multi-thermal fluids flooding plan design of heavy oilfield.

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Development and Application of Gas Injection for Oil Recovery from Offshore Oilfields

FENG Gaocheng, HU Yunpeng, YAO Weiying, ZHANG Yu, YUAN Zhe

西南石油大学学报(自然科学版) 2019, 41 (1): 147-155. DOI: 10.11885/j.issn.1674-5086.2018.07.18.01

Abstract （241）

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The proportion of offshore low-permeability reservoirs and heavy oil reservoirs in untouched geological reserves has shown an annual increase. Thus, identifying methods for effective use of such hard-to-access reserves has become a major issue. Although gas injection for oil recovery has been applied both domestically and internationally for decades, China's offshore gas injection technology is still in its beginning stages. Focusing on these problems, this study examines the theory and application of gas injection development in both China and the world. Considering the current state of development and the production difficulties of China's offshore oilfields, seven constraints of the development of offshore gas injection technology in China were first analyzed, and solutions and measures were then proposed. The research shows that the potential use of gas injection for oil recovery technology in offshore oilfield applications is great and that localizing key technologies and applying multiple methods can reduce developmental risks and increase economic benefits.

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Analysis of Drainage Process for Crude Oil Production Using Pipeline with Large Drop-in-height

LIU Enbin, MA Xi, LI Chun, XIANG Min, HUANG Liyu

西南石油大学学报(自然科学版) 2019, 41 (1): 156-164. DOI: 10.11885/j.issn.1674-5086.2018.04.18.01

Abstract （382）

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For oil-after-water commissioning that involves a maximum drop-in-height of 1 432.64 m and uses a crude oil pipeline containing a U-shaped section with a large drop-in-height, the density difference between crude oil and water leads to stagnation issues in the oil head. To resolve this problem, we proposed to drain the pipeline and release pressure using a pressure relief valve installed in the valve chamber near the oil-water interfacial point. Based on the OLGA multiphase flow transient simulation method and taking the actual situation as an example, we simulated the gas-driven water drainage process in the pipe section with a large drop-in-height. Specifically, the simulation focused on analyzing the change in flow rate and pressure over time with varying diameters of the leakage aperture. A series of available sizes of the leakage apertures and corresponding changes in the displacement, flow, and pressure over time were obtained from the simulation. The results demonstrate that the maximum displacement in the selected pipe section (capacity≈6 367.98 m ³) can reach 3 375 m ³. From the perspectives of economy, safety and effectiveness, the best leakage aperture range was found to be 90～110 mm. This number was consistent with that in the actual situation. This study provides a practical basis for alleviating similar abnormal conditions in real production processes.

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Improved Genetic Algorithm and its Application in the Design of Drilling Fluid

LI Jian, CAI Haiyan, LI Jiadi

西南石油大学学报(自然科学版) 2019, 41 (1): 165-174. DOI: 10.11885/j.issn.1674-5086.2018.04.26.03

Abstract （308）

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The selection of a proper drilling fluid system is the key to enabling fast and high-quality drilling operations while avoiding or reducing the occurrence of drilling accidents when working in deep wells, ultra-deep wells, and complex formations. When designing the drilling fluid using case-based reasoning (CBR), the drilling fluid system can be derived from multiple attributes such as lithology, well type, and well depth. However, the derivation results can be substantially affected by each attribute's weight assignment. The genetic algorithm suffers from slow convergence and low convergence precision when used for optimization of the attribute weights. Considering this issue, this study proposes an improved genetic algorithm to address the issue of attribute weight assignment in CBR. Initially, the genetic operator is improved using the following techniques. An exponential scale transformation method is used to optimize the selection of the individual operator. A self-adaptive adjustment is performed on the scale factors in the arithmetic crossover. With reference to the mutation operator, the mutation direction of each individual is modified to maintain the diversity of the population. Next, the self-adaptive adjustment of the crossover probability is realized from two aspects, namely the individual fitness and the level of variation between crossover individuals. Finally, by performing comparative experiments on the UCI dataset, we proved that the improved genetic algorithm can enhance the global convergence performance and increase the accuracy of CBR. Experimental results demonstrate that applying the improved genetic algorithm to the CBR-based drilling fluid design can effectively optimize the weight assignments of each attribute and therefore improve the quality of drilling fluid.

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Simulation of Deep Filtration Process for Wastewater Containing Polymers and Optimization of Technical Boundaries

WANG Zhihua, LI Jiexun, ZHOU Nan, BAI Ye, XU Yunfei

西南石油大学学报(自然科学版) 2019, 41 (1): 175-186. DOI: 10.11885/j.issn.1674-5086.2018.06.30.01

Abstract （405）

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This study addresses the problem of unbalanced water injection and production in a ground system. Based on the existence of insufficient wastewater sources following deep filtration treatments and lack of precious clean water sources in oilfields, this study considers the technology of a two-stage deep filtration treatment that utilizes "double-layered filter material+ three-level graded filter material" after ordinary treatment of polymer-containing wastewater. The advanced treatment technology of two-stage filtration considers variations in polymer concentration and its correlation with filtration process parameters. A numerical simulation is conducted to describe the aggregated distribution characteristics of oil beads and suspended particles in the flow field of the deep filtration process. This is necessary to determine changes in the content of oil and suspended solids in filtered water following deep filtration. The results show that it is feasible to control the water quality indices of oil and the content of suspended solids to within 5.00 mg/L by performing deep filtration on the polymer-containing wastewater. An optimized technical boundary relationship map of the deep filtration technology for polymer-containing wastewater can be used to enhance the indicators and efficiency of its treatment. The operational load and stability of the polymer-containing wastewater treatment process can also be ensured.

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The Formation Mechanism of Paleozoic Tectonic and Stratigraphic Diversity in Chengdao Area

LUO Xia

西南石油大学学报(自然科学版) 2019, 41 (2): 1-9. DOI: 10.11885/j.issn.1674-5086.2018.06.09.02

Abstract （274）

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In this study, we analyzed the formation mechanism of Paleozoic tectonic and stratigraphic diversity in Chengdao Area using 3D seismic, drilling data, and regional stress field results. The results show that affected by the left-lateral →rightlateral "reciprocating" strike-slip movement of Tanlu fault during the Late Triassic-Eocene period, Paleozoic in Chengdao Area experienced three stages including "compressing and plunging folds, stretching and reversing into mountains, and differential slipping and shaping". At the end of the Triassic period, the NE-SW region in Chengdao Area was compressed from SW to NE under the left-lateral strike-slip movement of Tanlu fault. This compression movement resulted in the formation of three overthrust blocks in the west, middle, and east. The difference effect in the uplift caused different degrees of erosion in Paleozoic. During the late Jurassic-early Cretaceous period, Chengdao Area experienced stretching from the NWW-SEE to the NW-SE direction under the left-lateral strike-slip movement of Tanlu fault. Unbalanced reversion of thrust faults forms three rows of mountains in the west, middle, and east, as well as the "convergence in the south and discrete in the north" fault. In the Late Cretaceous-Eocene, the base shearing displacement of the three rows of the mountains from the west to the east direction in Chengdao Area is increasing under the effect of right-lateral strike-slip movement of Tanlu fault. The EW fault and the NEtrending strike-slip fault formed due to the base shearing from the middle mountain and east mountain, respectively, which tend to cut into each other. The structural styles and lithology distributions are now more complex.

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Fault System and Its Controlling Effect on Fracture Distribution in Moxi-Gaoshiti Block, Sichuan Basin, China

XU Ke, DAI Junsheng, FENG Jianwei, REN Qiqiang

西南石油大学学报(自然科学版) 2019, 41 (2): 10-22. DOI: 10.11885/j.issn.1674-5086.2018.01.10.01

Abstract （276）

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In order to determine the fault and fracture distribution characteristics of the Moxi-Gaoshiti block, faults were classified into different types and levels based on geomechanical theory and seismic, logging, core, and relevant experimental data. Fractures were quantitatively predicted, and the relationship between the distributions of faults and fractures was established. The results showed that the faults in the Moxi-Gaoshiti block have a large scale in the vertical direction, long extensions, a large number of disconnected layers, and obvious delamination. They can be divided into 3 structural layers, and have significant plane partitioning and banding. Faults with different scales, directions, and characteristics have significant influences on fracture distribution. Fracture density is generally 1.5~5.0/m with a maximum of 7.0/m. Zones with high values are primarily distributed in the fault and its periphery. The maximum fracture opening in the fault development zone can reach 3 mm. The Moxi-Gaoshiti block is a fault-fracture symbiotic system. The primary fault controls the development of secondary faults and fractures, and the secondary fault controls the development of local fractures.

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Geological Characteristics and Development Strategies of Fractured Tight Oil Reservoirs in Jinghe Oilfield

LIU Zhongqun

西南石油大学学报(自然科学版) 2019, 41 (2): 23-32. DOI: 10.11885/j.issn.1674-5086.2018.06.04.03

Abstract （301）

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Based on the geological characteristics and the development perspectives, this paper discusses the challenges in the exploration of fractured tight oil reservoirs, and proposes strategies for the development of their exploitation. The work, based on results from the Jinghe Oilfield, provides a reference for the development of oil fields of the same type. The Jinghe oil field is a dense reservoir with fine pore structure, poor connectivity, and a low percentage of movable fluids. Such structure, as well as the horizontal layered fractures, are the main factors controlling the yield of the reservoir. The reservoirs can be divided into four types, among which types I and Ⅱ are" sweet spots", and are characterized by a strong heterogeneity, low thickness, low porosity, low oil saturation, and low abundance. The wells have a low production, large difference in the production capacity, rapid decline in the production, low cumulative production, and low recovery capability. It is highly difficult to economically develop the reservoir. The issues in its development include the difficulty in accurately locating the " sweet spots", improving the controllable reserves, improving the recovery rate, and in performing energy injection. Six development strategies are proposed, to address the development difficulties specifically, namely:a "discontinuous" well location deployment, a segmental fracturing of horizontal wells, a rolling construction and production, the optimization of reservoir engineering parameters, the implementation of pilot tests for energy injection, and the implementation of low-cost procedures.

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Formation Evolution and Influencing Factors of Organic Pores in Shale

DING Jianghui, ZHANG Jinchuan, YANG Chao, HUO Zhipeng, LANG Yue

西南石油大学学报(自然科学版) 2019, 41 (2): 33-44. DOI: 10.11885/j.issn.1674-5086.2018.03.05.03

Abstract （331）

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Being an important constituent of the shale pore system, organic pores are formed during hydrocarbon generation in shale. They are traces of shale gas generation, diffusion, and accumulation, and they also reflect the gas generation and storage capacity of shale reservoirs. We explored the formation mechanism of organic pores based on the current literature and existing geological information. It is believed that organic pores form on a large scale when the expansive force of gas generation is sufficiently strong and organic matter breaks through its surface. Hence, organic pores form via the expansive force of gas generation. Factors influencing the development of organic pores are also discussed. The results show that organic pore development is not only influenced by the geochemical properties of organic matter, e.g., TOC, R _o, types of organic matter, and microscopic composition, but also by other factors, e.g., organic plasticity, forms of organic matter, secondary asphalt, compaction, and formation pressure coefficients. Intensive compaction deformation of organic matter does not favor preservation of organic pores during metamorphosis. Adhesion of organic matter onto mineral surfaces is conducive to late-stage preservation of organic pores, while formation pressure coefficients correspond relatively well to organic pore development. Finally, the organic pore evolution process is classified into four stages using Ro as the primary classification indicator, i.e., none to pre-mature, mature, highly to excessively mature, and metamorphosis. Many organic pores form during the highly to excessively mature stage.

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Study on Identification of Dry Layers Based on Fuzzy Mathematics

XU Xiaoming, LI Yanlan, SUN Jingmin

西南石油大学学报(自然科学版) 2019, 41 (2): 45-52. DOI: 10.11885/j.issn.1674-5086.2017.12.14.04

Abstract （179）

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It is important to make fine adjustments to the injection and production of oil fields based on detailed geological understanding of reservoirs for the development of high-water-cut wells in mature oil fields. This work has studied a detailed description of the middle and deep layers of the oil/oil-water/water reservoir in Bohai Bay and a data analysis of its actual oil production. It is assumed that some dry layers of water wells connected with oil wells demonstrate a certain degree of water absorption. Therefore, the effective use of a dry layer can further increase the injection-production ratio, improve the water drive degree, and ultimately enhance the water absorption ratio. The connection of a dry layer with an oil reservoir depends on many complex factors. This study has employed the principal component analysis and theory of fuzzy closeness to propose an identification method for the membership function of a fuzzy set using the integrated information of each discriminant variable. This method has reduced the dimension of initial variables while ensuring comprehensiveness and accuracy of the discriminant function.Research results show that the proposed method based on fuzzy closeness has achieved an accuracy of over 85% in terms of the effective identification of dry layers. A numerical simulation has been adopted for data analysis and comparison. The effective use of the dry layer has further enhanced the injection-production ratio and significantly improved the oil development. Considering the aforementioned factors, it is established that the comprehensive identification method is reliable and fairly practical for the future development of oilfields.

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Study on the Hierarchy of A Distributary-mouth Bar Type Shallow-water Delta Reservoir

WU Qiongyuan, CHEN Xiaoming, ZHAO Hanqing, ZHANG Yanhui, CAO Long

西南石油大学学报(自然科学版) 2019, 41 (2): 53-63. DOI: 10.11885/j.issn.1674-5086.2018.11.16.10

Abstract （306）

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To determine the distribution characteristics and internal structure of a distributary-mouth bar type shallow-water delta reservoir, this study integrated current sedimentation, rock core, well logging, and dynamic data and performed hierarchy analysis on the N mⅡ-1 layer of oilfield A in Bohai Sea. The study established a grading system for the hierarchy of the distributary-mouth bar type shallow-water delta and describes the spatial configuration among its internal single sandbodies. Distributary-mouth bars were identified as the main structural unit of this class of shallow-water deltas, of which the level 5 structural units are complexes formed from distributary-mouth bars of the same period, level 4 units are single distributary-mouth bars, and level 3 units are internal accretion bodies of the distributary-mouth bars. Three main types of single-phase sandbody structural interfaces were identified:mudstone, argillaceous siltstone, and silty mudstone. The length, width, and thickness of distributary-mouth bars of single origin are about 600~1 300 m, 400~800 m, and 2.5~7.0 m respectively, arranged vertically in partially overlapped, main-body overlapped and main-body superimposed configurations, and laterally in isolated, edge sideway joined and main-body sideway joined patterns. The overall evolution is "early foreset deposit with lateral migration-late gradual overlapping aggradations." Three mud interlayers of varied genesis developed in the distributary-mouth bars:foreset inclined layer along the source direction, sideway overlapped layer, and vertically accreted horizontal layer perpendicular to the source. The sideway overlapped layer developed in the proximity of the source, whereas the vertically accreted horizontal layer developed at the lake basin region to the far side. The interlayer thickness of the study area is generally 0.4~1.2 m, with extension less than 300 m.

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Classification, Content and Extension of Evaluation Methods for Oil and Gas Resources

ZHAO Yingdong, ZHAO Yinjun

西南石油大学学报(自然科学版) 2019, 41 (2): 64-74. DOI: 10.11885/j.issn.1674-5086.2018.03.16.01

Abstract （330）

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According to differences in calculation principles, modes and processes, evaluation methods for oil and gas resources can be classified into three major categories, namely genetic methods, statistical methods, and analogical methods. These three types of methods can be further divided into subcategories. By studying the nature and the key problems of different evaluation methods for oil and gas resources, it is believed that genetic methods can be considered "simulation methods" in nature. Each genetic method has its own computing focus and calculations can be viewed as a "gradually decreasing" mode. Meanwhile, statistical methods estimate oil and gas resources through analyzing data, so they can be called "data methods". Their calculation processes can be viewed as a "gradual increasing" mode. Lastly, analogical methods determine the degree of enrichment of oil and gas resources in the prediction area based on the area's similarity with respect to a calibration area. The calculation results are often influenced by some sensitive parameters. These methods are "subjective cognition methods" and their calculation processes can be viewed as a "median". Some suitable evaluation methods must be selected in order to enhance reliability in different evaluation or exploration areas. This paper also discusses a new way to integrate resource amounts. This interval method can be used to more intuitively analyze resource coverage and enhance the accuracy of the final results.

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Characteristics of Cavity Differential Dissolution of Jintan Salt Cave Gas Reservoir

QI Deshan, LI Shuping, WANG Yuangang

西南石油大学学报(自然科学版) 2019, 41 (2): 75-83. DOI: 10.11885/j.issn.1674-5086.2018.04.19.02

Abstract （283）

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In China, salt mines that can be used for salt cave gas reservoir construction are mostly composed of layered salt rocks, and differential dissolution of the cavity often occurs during solution mining. Research into the characteristics and causes of such phenomenon can provide references for future construction of salt cave gas reservoirs in China. This work investigates the Jintan Salt Cave Gas Reservoir, which is the first salt cave gas reservoir in China. Based on sonar cavity data, differential dissolution in the cavity can be quantitatively analyzed using the differential dissolution coefficient, which is the ratio of the maximum cavity radius to the minimum radius in the same plane. The direction of the maximum radius is the direction of differential dissolution in the cavity. The statistical results reveal that, for the Jintan Gas Reservoir, the differential dissolution coefficient in the cavity is 1.13~11.88, and differential dissolution occurs primarily along the northeast-southwest direction. The causes of differential dissolution in the cavity are analyzed by integrating the thickness and ground stress data of interlayers and salt layers that can be used for mining. It is believed that non-uniform collapses of interlayers during solution mining can lead to differential dissolution in the cavity. Thicker salt layers that are more suitable for mining result in greater likelihood and severity of differential dissolution in the cavity. The ground stress directions significantly influence partial melting in the cavity.

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Numerical Simulation of Fracture Propagation in Horizontal Wells of Shale Reservoirs in Jiyang Depression

XUE Renjiang, GUO Jianchun, ZHAO Zhihong, ZHOU Guangqing, MENG Xianbo

西南石油大学学报(自然科学版) 2019, 41 (2): 84-96. DOI: 10.11885/j.issn.1674-5086.2018.05.21.01

Abstract （361）

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Physical experiments are limited by experimental conditions and the number of experimental samples available. Thus, it is difficult to conduct large-scale studies on fracture propagation patterns. Hence, a numerical simulation study on fracture initiation and propagation patterns during hydraulic fracturing of shales is conducted based on certain mechanical tests of rocks, rupture tests on hydraulic fracturing of shales, and physical model tests on fracture propagation during hydraulic fracturing of shales. Based on fluid-solid coupling through Biot's consolidation theory and Darcy's seepage law, the maximum tensile strength criterion, and the Mohr-Coulomb criterion as a damage threshold for damage determination of units, a new material distribution algorithm is introduced to construct a finite element calculation model of fracture propagation during hydraulic fracturing. Parameter calibration tests were performed on rock samples, and the influences of key physical parameters on fracture propagation in shales were investigated through the finite element calculation method. The key physical parameters are ground stresses, brittleness indices of shales, the viscosity of fracturing fluids, and bedding characteristics. The general view is that when brittleness indices are small, hydraulic fractures propagate in the shale matrix mostly along the direction of the maximum principal stress. The fractures hardly change direction to form a complex network of fractures. For highly cemented beds, hydraulic actions cannot deviate at a large angle continuously, even in partially open natural beds, and thus form only relatively uniform fractures. Fracture networks become more complex when ground stress ratios and the viscosity of fracturing fluids are lower, and bedding densities are higher.

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A Sophisticated Prediction Method for Water-cut Variation Patterns of Deep-water Turbidite Sandstone Oilfield

KANG Botao, YANG Li, YANG Baoquan, ZHANG Yingchun, YUAN Zhiwang

西南石油大学学报(自然科学版) 2019, 41 (2): 97-108. DOI: 10.11885/j.issn.1674-5086.2018.05.28.02

Abstract （234）

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Because of its complex reservoir characteristics, it is difficult to predict the single-well dynamic patterns of deep-water turbidite sandstone oilfields. Hence, realizing sophisticated prediction of single-well water-cut variation patterns is crucial. In this research, the Akpo Oilfield in the Niger Delta Basin of West Africa is studied. Its reservoir architecture and other influential factors such as sedimentary facies, sand body connectivity between injection wells, and reservoir heterogeneity are evaluated comprehensively to establish a method based on the reservoir characteristics for classifying the different modes of water-cut variation in production wells. By combining reservoir engineering and dynamic analysis, a prediction method for single-well full-cycle water-cut variation patterns based on reservoir characteristics is formulated. Through the analysis of the main contradictions at different stages of the production wells under various water-cut variation modes, targeted optimization and adjustment strategies are proposed. The applicability of the proposed method to other oilfields is also verified. The results show that:(1) the reservoir architecture of deep-water turbidite sandstone oilfields is complex and reservoir characteristics are the key factors affecting water-cut variations. (2) There are significant differences in the single-well dynamic patterns of deep-water turbidite sandstone oilfields. Thus, production decisions should be tailored to the specific field. (3) The proposed method is the first to integrate complex reservoir characteristics and diverse single-well dynamic patterns of deep-water turbidite sandstone oilfields, and it provides highly accurate predictions. (4) The research idea and flow are generally applicable to other deep-water turbidite oilfields.

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Mechanism and Characteristics of Nonlinear Flow in Porous Media of Low Permeability Reservoir

SUN Zhigang, MA Bingjie, LI Fen

西南石油大学学报(自然科学版) 2019, 41 (2): 109-117. DOI: 10.11885/j.issn.1674-5086.2018.05.09.02

Abstract （261）

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The mechanisms of nonlinear seepage in low permeability reservoirs were analyzed based on the microseepage effect, and a mathematical model was constructed for these nonlinear seepages in low permeability reservoirs using the forcebalance equation and experimental data from mercury porosimetry experiments. This model was further used to analyze the characteristics of nonlinear seepage in low permeability reservoirs, and the concept of dynamic resistance gradients(DRGs) was introduced to enable the dynamic characterization of these nonlinear seepages. Based on the results of this study, the primary causes of nonlinear seepage are the additional resistances against low permeability seepage caused by the boundary layers, fluid yield stress, and surface forces between boundary layer fluids and bulk fluids. Nonlinear seepages are always present at all displacement pressure gradients, but the effects are more pronounced at low DPGs and weaker at high DPGs. It was also found that the characterization of nonlinear seepage became more realistic when the starting pressure gradient was replaced by the DRG. As the DPG increases, the dynamic displacement gradient initially undergoes an instantaneous decrease from a high initial value and then gradually increases. In addition, the ratio of the DRG to DPG initially increases with the DPG, but subsequently decreases with further increase in the DPG.

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Coupling Model for Nanopore Gas Transport in Shale Reservoirs

HUANG Ting, TAN Wei, ZHUANG Qi, WANG Guosheng, YIN Tingting

西南石油大学学报(自然科学版) 2019, 41 (2): 118-126. DOI: 10.11885/j.issn.1674-5086.2018.07.16.01

Abstract （274）

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Shale gas is affected by many factors during nanopore transport, including pore size and pressure, pore wall surface roughness, pore mechanics reaction, adsorption-induced expansion reaction, and weighting factors. Therefore, the effects that these factors and the space occupied by the adsorbed gas molecules in the pores have on the gas flow must be considered. This is necessary to clarify the contribution to the total gas flow in the nanopores resulting from different migration mechanisms of shale gas (surface diffusion, slip flow, Knudsen diffusion, and viscous flow) based on different pore sizes and pressures. First, physical descriptions and mathematical characterizations of different migration mechanisms of shale gas are provided. A mathematical gas transport coupling model for shale gas is then developed that considers pore wall surface roughness, pore mechanics reaction, adsorption-induced expansion reaction, and weighting factors. The reliability of the model is verified by the lattice Boltzmann method. The results show that when the pore diameter is less than 10 nm, the total flow in the nanopores mainly consists of surface diffusion flux. In addition, the smaller the pore size, the greater is the surface diffusion flux. When the pore diameter is 40~250 nm at low pressure, the slip flow and Knudsen diffusion have a considerable effect on gas transport. When the pore diameter is longer than 10 μm, the total flow in the nanopores is primarily viscous.

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New Theory and Practice of Characterizing Phase Infiltration Relationships in Ultra-high Water-cut Period

LIU Haohan, YAN Yongqin

西南石油大学学报(自然科学版) 2019, 41 (2): 127-136. DOI: 10.11885/j.issn.1674-5086.2018.08.04.01

Abstract （184）

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In the (extra) high water-cut stage, the semi-logarithmic curve showing the relationship between the oil/water relative permeability ratio and water saturation tends to reach a turning point. Thus, applying the traditional linear theory of the relative permeability curve to the development of oil/water displacement in the (extra) high water-cut stage is difficult. In this study, nonlinear theoretical study of relative permeability in the high water-cut stage was conducted using a rational function for relative permeability established through a mathematical modeling method. Its parameters were identified based on the local weighted regression theory, and the appropriateness of the fitting was tested by constructing F-statistics. This is the first study in which the rational fitting theory has been applied to the characterization of relative permeability relationships in the (extra) high watercut stage. Through the use of actual data from the Beier, Yushulin, Xifeng, and Yangerzhuang oilfields, the traditional linear fitting, quadratic polynomial fitting, exponential fitting, and linear fitting methods based on data deformation were compared and analyzed. The new method and the oil/water displacement characteristic curve on which the new method is based showed higher prediction precision and stronger correlation. The new method can be used to reflect accurately the semi-logarithmic axis bending characteristics of the relative permeability curve of the (extra) high water-cut stage.

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Method for Calculating the Relative Permeability Curve of an Oil Reservoir Considering the Time-varying Effect of Relevant Reservoir Parameters

LIU Chen

西南石油大学学报(自然科学版) 2019, 41 (2): 137-142. DOI: 10.11885/j.issn.1674-5086.2018.08.08.01

Abstract （303）

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The current method used to calculate the relative permeability curve for a water-flooded oilfield fails to consider changes to reservoir parameters over time. To resolve this problem, a theoretical study was conducted. Based on a newly developed approximated theoretical water-flooding curve, we derived mathematical formulas for the key parameters associated with the relative permeability curve. These include the oil phase index, water phase index, and residual oil saturation quantity. Combining these formulas with the method used to calculate the residual oil saturation quantity, we developed a widely applicable method for calculating the dynamic curve of oil-water relative permeability that considers the time-varying effect of relevant reservoir parameters. Based on production data, this method can be used for a reservoir after prolonged water flooding. An application example shows that the oil-water relative permeability curve derived from the new method can reflect the dynamic characteristics of the reservoir effectively. The proposed method provides theoretical support for calibrating the recoverable reserves of an oilfield and for studying the distribution of residual oil. It can also be used in numerical simulations of ultra-high water content oil reservoirs or in analytical fitting of historical data.

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Pressure Field and Streamline Distribution of Jointly Developed Horizontal and Vertical Wells

ZU Lin

西南石油大学学报(自然科学版) 2019, 41 (2): 143-151. DOI: 10.11885/j.issn.1674-5086.2018.07.27.01

Abstract （257）

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Considering the current high proportion of low-yield and low-efficiency horizontal wells around Daqing Placanticline, research on the characteristics of residual oil distribution in horizontal well groups is urgently required. Thus, this study focuses on the flood pattern streamlines and pressure distribution characteristics of jointly developed horizontal and vertical wells. Through the application of the source-sink theory and the superposition principle for pressure, pressure field models with only vertical wells, only horizontal wells, only fracturing horizontal wells, and jointly developed vertical/horizontal wells were constructed. The Euler method was used to solve these models, where two, three, and four nodes formed the well network used in simulation to obtain the pressure field and streamline distribution. The research shows that the major trends of pressure fields and streamline distribution in horizontal wells when different network completion methods are applied were the same. When the wells were located at side wells, which are directly opposite to the horizontal wells, linear progression was easily formed between the wells and horizontal wells. When the wells were located at corner wells, which were thus not directly opposite the horizontal wells, linear progression could not be formed easily and resulted in a large area of low pressure. The distinct feature of fracturing horizontal wells is that the pressure gradient field of the outer crack is larger than that of the inner crack when the well is not directly opposite the horizontal wells. The accuracy of this study's results was further verified by comparison with the residual oil results of the well group numerical simulation. These results will help to fulfill the purpose of guiding the research and development adjustment of the residual oil distribution characteristics of the horizontal well group.

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Study on Pressure Management of Annulus Pressure Buildup in Deepwater Wells

YANG Xiangqian, ZHANG Xingquan, LIU Shujie, REN Meipeng

西南石油大学学报(自然科学版) 2019, 41 (2): 152-159. DOI: 10.11885/j.issn.1674-5086.2018.04.10.01

Abstract （265）

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The annulus pressure buildup (APB) in deepwater oil and gas wells may not be released even by employing a casing annulus resulting in accidents, such as casing collapse. Therefore, it is necessary to regulate the APB to ensure safety during oil and gas production. This study has calculated the trapped annular pressure in deepwater wells under different temperatures and analyzed and optimized the method to prevent and control the annular pressure in these wells. Using the strength standards for casing strings, this study has proposed a method to verify the strength of the casing string in the deepwater well and established a pressure management method for the trapped annulus. In terms of deepwater oil and gas wells, the control method for the trapped annular pressure involves relieving the pressure of the A-annulus through the formation pressure relief and wrapping the casing strings with compressed foam. The strength of the casing string must be verified using both equilibrium and nonequilibrium methods concerning the trapped annular pressure; the prevention and control methods must be considered together with these verification results to determine the pressure control range for the trapped A-annulus.

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Prediction of Compressor Unit Performance Based on Error Correction Model

PU Hongbin

西南石油大学学报(自然科学版) 2019, 41 (2): 160-166. DOI: 10.11885/j.issn.1674-5086.2018.09.10.01

Abstract （303）

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To resolve the problem of unrealistic operation plans developed at the early stage for centrifugal compressors, this study was conducted to predict the performance of centrifugal compressors. For the purpose of error correction and taking a centrifugal compressor unit of a specific compressor station as an example, we transformed the performance curve of the compressor unit using a multi-transformation algorithm. Subsequently, the performance curve as processed through similarity transformation was fitted based on the method of least-square surface fitting. Considering the deterioration of the compressor unit, an error correction model of the compressor performance parameters was obtained through least-squares one-element fitting. A comparative analysis was further performed between the model and multiple sets of historical data obtained under different working conditions. The results showed that the relative error of the shaft power and the pressure ratio prediction obtained from the error correction model was within 3% when compared to the actual measurement values. This finding validates the reliability of the proposed error correction model. It further provides realistic basic production data for developing a proper operating plan for a compressor unit.

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Energy-efficient Power Matching for Fully Hydraulic Fracturing Truck Based on MFO Algorithm

YANG Bo, CAO Xuepeng

西南石油大学学报(自然科学版) 2019, 41 (2): 167-174. DOI: 10.11885/j.issn.1674-5086.2017.12.14.03

Abstract （243）

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To overcome the disadvantages of high fuel consumption and cost of mechanical fracturing truck, a fully hydraulic fracturing truck is proposed. Considering the system power loss, "work-specific fuel consumption" is proposed to evaluate the actual fuel consumption of fracturing trucks. Global power matching is performed for the fully hydraulic truck, and mathematical models for engine universal characteristics, variable piston pump efficiency, and machine auxiliary power are constructed, respectively. Penalty functions are constructed using the self-adaptive penalty function law, and the objective function is constructed based on the optimal goal of achieving the lowest work-specific fuel consumption. Based on the MFO algorithm and choosing the required output pressure and outflow rate of the fracturing pump as the optimization input parameters, the best output combination of 11 tuning parameters in total, including the number of engines required to start, the revolution speed of each engine, and its piston pump displacement can be optimized. The results show that under all operating conditions, the work-specific fuel consumption of the fully hydraulic fracturing truck is maintained at 4.55~9.91 L/(60 MPa·m ³), which also decreases gradually as the loading pressure and displacement increase. Compared with the original plan, the new proposal can save up to 35.97% of fuel, and the fuel saving rate gradually decreases as the loading pressure increases. The newly proposed fully hydraulic fracturing truck can save up to 53.74% of fuel compared with a mechanical fracturing truck under the same operating conditions.

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Prediction of Tubing String Corrosion Rate in CO ₂-injection Production Wells

ZHANG Zhi, LIU Jinming, ZHANG Huali, LI Yufei, LUO Wei

西南石油大学学报(自然科学版) 2019, 41 (2): 175-184. DOI: 10.11885/j.issn.1674-5086.2018.06.07.01

Abstract （208）

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The pattern of tubing corrosion in different stages in CO ₂ production wells was investigated from the viewpoint of the phenomenon of tubing string corrosion. Moreover, the progression of CO ₂ corrosion in the tubing string is summarized. Based on kinetic principles and the theory of electrochemical corrosion of metals, factors such as the liquid production, water cut, wellhead temperature, production pressure difference, and fluid flow rate were considered. Further, the internal temperature and pressure distribution of the tubing were obtained, and methods for predicting the corrosion rate in CO ₂ production well tubing were investigated. The corrosion rates of the tubing string in actual wells were predicted, and the pattern of variation in the tubing string corrosion rate with the time and depth was investigated under the principal control factors. The results show that tubing corrosion occurs primarily in the production stage throughout the throughput cycle. The prediction results of corrosion conditions are in good agreement with the corrosion conditions measured in the field.

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On the Energy Revolution and the Mission of Science and Technology

ZOU Caineng, PAN Songqi, DANG Liushuan

西南石油大学学报(自然科学版) 2019, 41 (3): 1-12. DOI: 10.11885/j.issn.1674-5086.2019.04.07.01

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Energy is a country's driving force towards power and the cornerstone of national security. The world's energy development is currently entering the third stage of the transition from coal, oil, and gas to new energy sources. This stage is characterized by a new combination of energy supply worldwide:33% from petroleum, 24% from natural gas, 28% from coal, and 15% from new energy sources. However, China still has a coal-based energy, as its "coal-rich and oil-and-gas-lacking" energy endowment has led to an energy supply structure of "one leader with three followers":59% from coal, 19% from petroleum, 8% from natural gas, and 14% from new energy sources. It is therefore necessary to initiate a revolutionary process of transformation of the energy structure, in order to achieve a condition in which the energy supply is provided by a more balanced combination of coal (40%), oil and gas (31%), and new energy sources (29%). China's petroleum industry is undergoing a transformation from conventional to unconventional oil and gas resources; thus, it currently can be defined as a "mixed conventional-unconventional" oil and gas industry. At the same time, the industry is undergoing a "theoretical revolution" from the exploitation of single-entrapment oil and gas reservoirs to that of "sweet spot areas" on a large scale, a technological revolution from the use vertical natural wells to that of fractured horizontal well networks of "man-made reservoirs", a management revolution from manual operations to intelligent and low-cost development, and a strategic revolution from energy politics to reshaping the energy balance. China has chosen the strategies of "reducing coal, stabilizing petroleum, and increasing gas" and "vigorously developing new energy sources" as the two paths towards energy transformation. At the same time, China is facing "three major challenges":the need to achieve a clean coal utilization, the rising dependence on imported oil and gas, and the uncertainty about the future pillar industries of the new energy. In order to overcome these challenges, China needs to establish the "three major strategic areas" of coal, oil and gas, and new energy sources, by carrying out "four major revolutions" concerning the energy supply, consumption, technical aspects, and overall system; exploiting the "five major opportunities" presented by the current national policy (the "One Belt One Road" strategy); pursuing a new round of oil price recovery and a large-scale development of natural gas; and working in the direction of a technological revolution in the new energy resources so as to complete the historical mission of China's energy transformation. The development of social civilization and the progress of science and technology are two driving forces for energy transformation, with the former being the internal driving force and the latter the fundamental driving force. The transition from traditional fossil energy to non-fossil new energy sources is the inevitable trend and the inevitable choice of energy development.

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The Spatial Distribution of Elastic Parameters of Orthotropic Rocks

GUI Junchuan, CHEN Ping, MA Tianshou

西南石油大学学报(自然科学版) 2019, 41 (3): 13-28. DOI: 10.11885/j.issn.1674-5086.2018.09.21.02

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The mechanical parameters of rocks are the basic parameters for studying the wellbore stability and fracturing reformation. Their values can be calculated based on the stiffness matrix. Currently, the models used for calculating the mechanical parameter of rocks based on the stiffness matrix consider the formation as a VTI medium. This approach failed to take into consideration of the significant amount of ORT features in the actual formation and the effect of observation coordinate systems on the mechanical properties of rock. In this study, the expression of the stiffness parameter used for calculating the rock mechanical parameters was derived based on the constitutive equation of rock and considering the ORT features of shale gas formations. First, the expression of the stiffness matrix used for calculating the rock mechanical parameters was derived from the constitutive relation of the rock. Next, by considering the intersection angle between the wellbore and the stratum, combining the definition of mechanical parameters for rock, and performing coordinate transformation, a method for calculating the mechanical parameters of rocks was established in the observation coordinate system. The mechanical parameters of rocks in different observation coordinate systems were also analyzed and compared. Finally, considering that the actual formation is composed of shale-sandstone interbeds, we analyzed the influence of the variation in sandstone content on the mechanical parameters of rock in the observation coordinate system.

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Hydrocarbon Generation Potential and Pore Characteristics of Chang 7 Oil Shale in the Zhangjiawan Region

TANG Jianyun, ZHANG Gang, FAN Hongwei, LIU Jiantong, CHEN Yubao

西南石油大学学报(自然科学版) 2019, 41 (3): 29-41. DOI: 10.11885/j.issn.1674-5086.2018.03.12.01

Abstract （252）

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Hydrocarbon generation potential and pore characteristics of Chang 7 oil shale from the Yanchang Formation in the Zhangjiawan Region of the Zhiluo Oilfield were examined in this study. We conducted petrological and organic geochemical analyses, and methods like scanning electron microscopy and argon ion milling were used to analyze the distribution, geochemical characteristics, and pore characteristics of the Chang 7 shale in the study area. The results reveal that the Chang 7 black lake shale from the Yanchang Formation in the study area is heterogeneous both horizontally and vertically. It is thick in the northwest, but thin in the southeast. The organic matter in the Chang 7 oil shale are primarily type I and Ⅱ ₁ and are highly mature. Therefore, the shale is a desirable hydrocarbon source rock. The shale reservoir is a type 1 enrichment reservoir. The pores of the reservoir are mainly intergranular pores, intercrystalline pores, dissolution pores, and organic pores, where the pore sizes are mostly <0.5 μm. The throat radius ranges from 100 to 750 nm. There is a relatively porosity range (0.5% to 1.9%) with an average of approximately 1.0%. It is believed that the "newly discovered" Chang 7 shale in the study area has relatively great hydrocarbon generation potential, with a relatively high content of movable oil.

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