Table of Content

10 April 2019, Volume 41 Issue 2

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

LUO Xia

2019, 41(2):  1-9.  DOI: 10.11885/j.issn.1674-5086.2018.06.09.02

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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.

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

XU Ke, DAI Junsheng, FENG Jianwei, REN Qiqiang

2019, 41(2):  10-22.  DOI: 10.11885/j.issn.1674-5086.2018.01.10.01

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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.

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

LIU Zhongqun

2019, 41(2):  23-32.  DOI: 10.11885/j.issn.1674-5086.2018.06.04.03

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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.

Formation Evolution and Influencing Factors of Organic Pores in Shale

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

2019, 41(2):  33-44.  DOI: 10.11885/j.issn.1674-5086.2018.03.05.03

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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.

Study on Identification of Dry Layers Based on Fuzzy Mathematics

XU Xiaoming, LI Yanlan, SUN Jingmin

2019, 41(2):  45-52.  DOI: 10.11885/j.issn.1674-5086.2017.12.14.04

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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.

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

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

2019, 41(2):  53-63.  DOI: 10.11885/j.issn.1674-5086.2018.11.16.10

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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 NmⅡ-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.

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

ZHAO Yingdong, ZHAO Yinjun

2019, 41(2):  64-74.  DOI: 10.11885/j.issn.1674-5086.2018.03.16.01

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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.

Characteristics of Cavity Differential Dissolution of Jintan Salt Cave Gas Reservoir

QI Deshan, LI Shuping, WANG Yuangang

2019, 41(2):  75-83.  DOI: 10.11885/j.issn.1674-5086.2018.04.19.02

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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.

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

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

2019, 41(2):  84-96.  DOI: 10.11885/j.issn.1674-5086.2018.05.21.01

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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.

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

2019, 41(2):  97-108.  DOI: 10.11885/j.issn.1674-5086.2018.05.28.02

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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.

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

SUN Zhigang, MA Bingjie, LI Fen

2019, 41(2):  109-117.  DOI: 10.11885/j.issn.1674-5086.2018.05.09.02

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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.

Coupling Model for Nanopore Gas Transport in Shale Reservoirs

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

2019, 41(2):  118-126.  DOI: 10.11885/j.issn.1674-5086.2018.07.16.01

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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.

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

LIU Haohan, YAN Yongqin

2019, 41(2):  127-136.  DOI: 10.11885/j.issn.1674-5086.2018.08.04.01

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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.

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

LIU Chen

2019, 41(2):  137-142.  DOI: 10.11885/j.issn.1674-5086.2018.08.08.01

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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.

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

ZU Lin

2019, 41(2):  143-151.  DOI: 10.11885/j.issn.1674-5086.2018.07.27.01

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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.

Study on Pressure Management of Annulus Pressure Buildup in Deepwater Wells

YANG Xiangqian, ZHANG Xingquan, LIU Shujie, REN Meipeng

2019, 41(2):  152-159.  DOI: 10.11885/j.issn.1674-5086.2018.04.10.01

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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.

Prediction of Compressor Unit Performance Based on Error Correction Model

PU Hongbin

2019, 41(2):  160-166.  DOI: 10.11885/j.issn.1674-5086.2018.09.10.01

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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.

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

YANG Bo, CAO Xuepeng

2019, 41(2):  167-174.  DOI: 10.11885/j.issn.1674-5086.2017.12.14.03

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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·m³), 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.

Prediction of Tubing String Corrosion Rate in CO₂-injection Production Wells

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

2019, 41(2):  175-184.  DOI: 10.11885/j.issn.1674-5086.2018.06.07.01

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The pattern of tubing corrosion in different stages in CO₂ production wells was investigated from the viewpoint of the phenomenon of tubing string corrosion. Moreover, the progression of CO₂ 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 CO₂ 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.