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Research and testing of high-efficiency milling technology
WANG Qi, HAN Xiaoqiang, SUN Baojing, CHANG Fangrui, ZHANG Xianchao, YOU Guanqun
[Abstract](5) [FullText HTML](65) PDF 1836KB(577)
To improve the low milling rate and rapid wearing of conventional milling shoes, the cutting mechanism, structure, materials, and operating parameters of milling tools were investigated, and a novel high-efficiency milling tool was designed. The results showed that the cutter design with cutting angles of 5°−10° and a dip angle of 5° delivers the optimal cutting performance; the application with imported alloy materials is associated with the least wear rate; the milling efficiency is the highest, with alloy materials designed as multiple rhombi. Moreover, based on the downhole complex issues, three mill shoe structures were proposed, namely the flat, concave and pilot mill shoes. The field testing confirmed that the application of high-efficiency milling tools improves the average milling efficiency by 40% and the invention has the potential for application promotion.
Research and application of macro management chart on working condition of water injection well based on K-means-SVM algorithm
ZHANG Jiang, YANG Xuefeng
 doi: 10.13639/j.odpt.2022.03.019
[Abstract](1) [FullText HTML](42) PDF 4246KB(37)
The macro management chart on the working condition of water injection wells is an important map that reflects the working condition of water injection wells. The construction of digital oil field provides massive data for the dynamic monitoring of water injection wells. Based on the massive data samples from water injection wells, by using the K-means clustering algorithm, macro working conditions of water injection wells, that is, the macro management chart composed the area to be reformed, the under-injection area, the normal injection area, the over-injection area, and the pending area was established. The regional boundary line was determined by using the support vector machine (SVM), and a control chart model on working condition management of injection wells was established. Using this model, the drawing method and application process of block macro management chart and single well dynamic management chart were formed. The field application shows that the macro control chart model constructed based on the big data method can reflect the relationship between the production dynamic characteristics, water injection intensity, water absorption capacity and injection completion rate of the research block and single well, which provides a decision-making basis for the next implementation of measures on water injection wells.
Experimental law of well scaling in the production process of deepwater gas well
LIU Wenyuan, HU Jinqiu, YAO Tianfu, OUYANG Tiebing, LI Xiangfang
 doi: 10.13639/j.odpt.2020.03.021
[Abstract](6) [FullText HTML](872) PDF 1629KB(2771)
Offshore gas wells are characterized by large depth, complex scale removing operation and high operation cost, so it is imperative to predict and control the scaling in the wells of deepwater gas wells. In this paper, laboratory experiment and theoretical calculation were combined to evaluate the scaling risks in the wells during the production of four typical deepwater gas wells in the South China Sea Gasfield, predict scaling velocities and scaling positions in the wells of gas wells in the process of production and analyze the scaling characteristics and laws. It is indicated that the scaling type of gas well is controlled by the compositions of formation water and the scaling velocity in the production process of gas well is mainly dependent on the deposition velocity of stable scale after the surface deposition period. The scaling difference at different well depths in the production process of deepwater gas well is mainly dominated by the temperature distribution along the well, and the scale control shall focus on the middle and lower parts of the well and the conditions of high gas production rate and high water/gas ratio. Compared with onshore gas wells, deepwater gas wells are affected more by the scaling in wells, so to keep the efficient and safe production of deepwater gas wells, it is quite important to take the scale control measures in time to prevent the formation of scale and control the scale deposition in the allowable range.
2023, 45(6).  
[Abstract](0) PDF 3226KB(0)
2023, 45(6).  
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Carbon dioxide capture, utilization and storage technology and industrialization development path under the dual carbon goal
LI Yang, ZHAO Qingmin, XUE Zhaojie
2023, 45(6): 655-660.   doi: 10.13639/j.odpt.202201052
[Abstract](0) [FullText HTML](0) PDF 1192KB(0)
Carbon capture, utilization and storage (CCUS)technology is an important means to effectively reduce carbon emissions from fossil fuel combustion and industrial processes. It can reduce the economic, social and environmental costs of carbon emission reduction, and is an important technical support for achieving the goal of carbon neutrality. CCUS technologies have developed rapidly and have the technical feasibility of large-scale application in various industries. However, the large-scale deployment of CCUS still faces many problems. To this end, the development of carbon capture technology, CO2 flooding and storage technology, CO2 chemical conversion and utilization technology were systematically reviewed, and the opportunities for CCUS development under the dual carbon target (achieve carbon peaking by 2030 and carbon neutrality by 2060) were analyzed. Finally, the development path of CCUS technologies and industrialization as well as three main industrial development models were proposed. At the same time, it is necessary to carry out the cultivation of relevant industrial clusters and the construction of low-carbon and zero-carbon demonstration bases to help achieve the goal of carbon neutrality.
Formation identification method for coring during shallow optimal and fast drilling based on configuration interface control
SU Zhaobo
2023, 45(6): 661-667.   doi: 10.13639/j.odpt.202305035
[Abstract](0) [FullText HTML](0) PDF 1012KB(0)
The sand bodies in the Mingxia member in shallow Neogene reservoirs, Bohai Oilfield show thin, scattered, and miscellaneous characteristics, in addition, due to various factors such as engineering, geological conditions, and manual influences, traditional formation identification methods struggle to accurately compare and determine the coring layer during optimal and fast drilling, which results in excessive penetration and low sandstone recovery rates. To address this issue, a method combining configuration interface constraints and drilling parameter variations was proposed to determine the cyclic points of formation identification. Firstly, based on logging and drilling data, a configuration interface division scheme was formulated, and configuration analysis was performed on the drilled wells, establishing a closed and isochronous configuration framework for the target area. Then, real-time drilling data was input into the configuration framework to analyze and pick up layer interfaces, predicting the position of coring sand bodies. Finally, based on drilling parameter variations, drilling was stopped in a cyclic manner to determine whether coring is required. This method was applied to three wells in the Bohai Oilfield, and on-site testing show that it can achieve precise layer identification within 2.0 meters in the context of optimal and fast drilling. This significantly improves the coring efficiency and quality during drilling, contributing to cost reduction and efficiency improvement.
Drilling technology for carbonate reservoir with dual density drilling fluid of drilling tool and annulus
DING Zhimin, ZHENG Quanbao, SHAO Changchun, YUAN Ye, XIA Tianguo, SUN Zhi
2023, 45(6): 668-674.   doi: 10.13639/j.odpt.202310026
[Abstract](0) [FullText HTML](0) PDF 782KB(0)
Due to the strong heterogeneity of carbonate reservoirs, multiple sets of pressure systems may exist in the same formation, leading to incidents such as coexistence of severe circulation loss and overflow. Conventional drilling techniques fail to effectively balance the issues of safe drilling and drilling costs. To address this, a dual-density unconventional drilling technology based on bit nozzle and annular space was proposed. Different densities of drilling fluids were used in the annular space and the bit nozzle on drilling tool, eliminating the need for circulation during drilling. Simultaneously, the changes in formation pressure were monitored in real time by measuring the annular fluid level and casing pressure, and the optimal drilling fluid density was promptly selected, enabling rapid drilling in complex formations. This technology was successfully applied in over 10 wells in different blocks of the Tarim Oilfield, achieving a successful penetration depth of 1 881.62 meters using low-density drilling fluid, which not only increased the penetration depth but also reduced drilling fluid costs. The application results show that this technology can penetrate formations with severe circulation loss and frequent high casing pressure without causing plugging or requiring additional equipment. This technology significantly improves production efficiency while achieving cost savings, which meets well trajectory monitoring requirements and can be directionally drilled when necessary to ensure the trajectory conforms to design specifications. This technology can maximize reservoir exposure, achieve geological objectives, release production capacity, and further meet the requirements of efficient development, demonstrating promising application prospects.
Technology of compound salt weak gel drilling fluid for long horizontal wells in deep shale oil reservoirs
WANG Guangcai, LIU Wancheng, CHEN Xiangming, ZHENG Jiangbo, MA Pingping, XIONG Kaijun, KONG Fanling
2023, 45(6): 675-682.   doi: 10.13639/j.odpt.202307067
[Abstract](0) [FullText HTML](0) PDF 953KB(0)
When drilling long horizontal wells in the deep reservoir of Block Jixin 2 in Tuha Oilfield, several challenges were identified, including the instability of shale wellbore, difficulty in hole cleaning as well as challenges in reducing friction and resistance. This prompted the need for advanced drilling fluid technology with high performance in inhibiting properties, sealing and collapse prevention, cutting carrying capacity and lubrication. Therefore, a study on drilling fluid technology was conducted. By compounding NaCl, KCl, sodium formate and ZNP-1, the drilling fluid system exhibits strong inhibition, effectively addressing the wellbore instability issue. The system employed "asphalt powder + acrylic resin plugging agent + wall cementing agent" to achieve full plugging of pores and fissures of micron, sub-micron and nano size. Additionally, a combination of low-fluorescence lubricant and encapsulated friction reducer was used to enhance the lubrication capability of the drilling fluid. A weak gel shear thinning agent was incorporated to improve the carrying capacity of the drilling fluid. The formulation of the compound salt weak gel drilling fluid system is finalized as follows: water+4% bentonite+0.2% caustic soda+15%NaCl+5%KCl+15%NaCOOH+1%ZNP-1+1%DRGJ-1+0.5%LV-CMC+4% asphalt powder+2% resin plugging agent+2% solid wall agent+0.3% weak gel+2% low-fluorescence lubricant+3% encapsulated friction reducer+barite. The performance of this system was evaluated, and the results showed a linear expansion rate of 7.21% of mud shale after 16 hours, a dynamic shear force of not less than 11 Pa, a filtrate viscosity coefficient not exceeding 0.0612, a drilling fluid activity of not more than 0.76, a high-temperature and high-pressure filtrate loss less than 10 mL, and resistance against 10% drill cuttings and 5% CaSO4 contamination. The technology was applied in 5 wells in Block Jixin 2, and when compared to neighboring wells such as Jixin 2 and Jixin 2-2, the drilling cycle was reduced by 33.05%, the average wellbore diameter enlargement rate decreased by 68.49%, and the average complexity rate decreased by 68.19%. This technology provides a technical support for safe and efficient drilling of similar deep long horizontal wells in oilfields.
Green treatment agent for waste polysulfonate drilling fluid solid phase resourceful utilization
XU Guiqin, XIE Shuixiang, REN Wen, ZHANG Mingdong, PAN Lifang, LIU Guoyu, YUE Changtao, LI Songhui
2023, 45(6): 683-689.   doi: 10.13639/j.odpt.202308040
[Abstract](0) [FullText HTML](0) PDF 3713KB(0)
With increasingly stringent national environmental protection requirements, the effective disposal of polysulfonate drilling waste has become an urgent issue for oil and gas enterprises. The traditional disposal methods such as curing landfill and preparing building materials have some shortcomings such as potential environmental risks and limited absorptive capacity, while the abundant organic matter in polysulfonate drilling waste remains underutilized. Utilizing greening soil prepared from polysulfonate drilling waste (V204H10) enables resourceful and harmless treatment of V204H10. By employing the response surface method, we obtained the optimal formulation of the improver with a mass ratio of 4.00∶1.80∶0.15∶0.15∶1.00∶3.00 for biomass activated carbon, sodium humate, compound biological fertilizer, fish bone meal, citric acid, and bionic curing agent, respectively. The soil germination index of JH-greening soil prepared using this amendment was significantly higher than that of V204H10. Moreover, COD, pH, organic matter content, and total petroleum hydrocarbon concentrations in JH-greening soil all complied with relevant national standards, while the heavy metal content in the leaching solution met GB/T 14848—2017 Groundwater Quality criteria. This technology introduces a novel approach to the harmless disposal of polysulfonate drilling waste and enhances their comprehensive resource utilization rate.
Mechanism of organic slow-release microemulsified acid for blockage removal
JIA Jianghong, LAN Qiang, HUANG Weian, WANG Xuechen, LI Xiuling
2023, 45(6): 690-695.   doi: 10.13639/j.odpt.202302044
[Abstract](0) [FullText HTML](0) PDF 1060KB(0)
The mechanism of organic slow-release microemulsified acid for blockage removal is not yet completely clear. By using interfacial tension method, lubrication coefficient method drilling cuttings dissolution rate method, and SEM scanning method, the mechanism of organic slow-release microemulsified acid for blockage removal was investigated. The research results show that organic slow-release microemulsified acid can reduce the interfacial tension between itself and the formation fluid to below 20.0 mN/m, thereby enhancing its permeation within the formation. It also reduces the lubrication coefficient of the drilling fluid by more than 40%, further increasing its contact probability with the formation rock. The rock dissolution rate of the organic slow-release microemulsified acid is only 43.8% compared to bare acid, and it proceeds slowly and steadily, allowing it to penetrate deep into the reservoir for blockage removal. Additionally, it reduces the thickness of the hydration film on the rock surface by more than 50% and decreases the contact angle on the drill bit surface from 50.2° to 8.3°, effectively improving the cleanliness of the well and drill bit. After comprehensive analysis, it is believed that the blockage removal mechanism of the organic slow-release microemulsified acid is: the internal acid solution, encapsulated by the oil phase, exhibits a slow-release effect. Under high-temperature and high-pressure conditions in the reservoir, it effectively reduces the interfacial tension between itself and the formation fluid, decreases the hydration film and contact angle on the rock surface, and thereby enhances its permeation within the formation. This ultimately leads to successful blockage removal in deep reservoir.
Automatic identification of drilling fluid loss types based on symbolic aggregate approximation
SHI Xiaoyan, JI Yong, CUI Meng, LI Zhongming, ZHAO Fei
2023, 45(6): 696-703.   doi: 10.13639/j.odpt.202302038
[Abstract](0) [FullText HTML](0) PDF 1009KB(0)
Currently, the determination of drilling fluid loss types relies on detailed geological engineering information, supplemented by manual analysis, leading to subjectivity and delay in identification. Based on the drilling fluid loss causes and parameter characterization patterns, characteristic curve templates for four types of fluid loss types, that is, fracture, pore, dissolution, and induced fracture, were established, and the characteristic curves were transformed into symbolic sequences using symbolic aggregate approximation (SAX) method. By comparing the SAX string representation of the characteristic curve from the well under investigation with template strings and calculating the similarity, the fluid loss type can be automatically identified based on quantified similarity. Validation results from sample wells show that this method, utilizing logging data directly, can automatically identify the drilling fluid loss types, and achieves an identification efficiency improvement of over 90% compared to traditional manual analysis methods. This approach can be applied to large-scale historical data mining for analysis to guide future drilling operations, or can be applied to real-time fluid loss type judgement to provide scientific basis for selecting plugging measures.
Estimating the location of leakage layer by drilling pressure loss engineering formula
LUO Limin, TAN Rui, GENG Lijun, LI Xiaobo, XU Zhengxian, YAN Wei
2023, 45(6): 704-711.   doi: 10.13639/j.odpt.202310001
[Abstract](0) [FullText HTML](0) PDF 1109KB(0)
The phenomenon of well leakage during drilling operations can damage oil and gas reservoirs, leading to malignant events such as well collapse, blowout, stuck drilling, and scrapping of some sections of the well, which poses a technical challenge in the safe and efficient development of oil and gas fields. Accurately determining the location of formation leakage is crucial for on-site resolution of drilling leakage issues. Conventional methods for determining leakage locations are complex, prone to errors, and economically inefficient. Therefore, a rapid method for estimating the leakage location and the time of leakage transition based on drilling pressure loss formula, standpipe pressure, and casing pressure was proposed. The method involves calculating flow regime friction based on the injected flow rate, displacement, circulating pressure loss, and flow regime, calculating leakage formation and determining leakage location based on the iteration of data from standpipe pressure and casing pressure before and after leakage, and determining the time for leakage transition according to standpipe pressure and casing pressure. The calculated leakage location for two leaking wells in the Bohai Sea region show a high overlap with the confirmed leakage location on site, with a calculation error below 5.06%, and the estimated leakage range 100% covers the on-site leakage locations. Furthermore, as the standpipe pressure increases, the leakage transition time also increases. The research method offers a convenient and concise calculation process, reducing errors caused by insufficient accuracy of input parameters. It can serve as a preliminary calculation method for determining leakage locations, providing technical support for on-site well plugging operations.
Quasi static design method for the structure of the lunar pool stabilizer on an ocean drilling vessel
SONG Yu, HUANG Fangfei, DUAN Mingxing, ZHANG Hang
2023, 45(6): 712-719.   doi: 10.13639/j.odpt.202301024
[Abstract](0) [FullText HTML](0) PDF 3153KB(0)
The amplitude response of ocean drilling vessels is more severe than that of floating platforms, and there is a high risk of interference between the drilling string and the moon pool. To address this issue, a moon pool centralizer was designed. Considering the motion characteristics and load distribution of the drilling string, the overall structure of the moon pool centralizer was designed, and the offshore current load excitation was restored. The ultimate bearing capacity of the moon pool l centralizer was analyzed under three different operating conditions: drilling, casing running, and drifting of the drilling vessel. The load distribution and risk points for each condition were analyzed based on the failure mode under the ultimate state, and structural improvement schemes were then proposed. The research indicates that the failure-prone location of the moon pool centralizer is at the pin shaft; the moon pool centralizer is more dangerous under the condition of drifting of the drilling vessel; and by adjusting the position of the base pin shaft and adding a set of thrust bearing cylinders, the load distribution of the overall structure and the pin shaft can be reduced.The research results provide theoretical support for the subsequent research on the optimal design of the moon pool centralizer structure.
A simulation method for gas-liquid splitting of fluid state in the well during the shutdown and continuous flow stage of intermittent production gas wells
SI Xiang, ZHANG Bao, JING Hongtao, PENG Jianyun, TANG Jiaxin, HAN Guoqing
2023, 45(6): 720-728, 737.   doi: 10.13639/j.odpt.202311014
[Abstract](0) [FullText HTML](0) PDF 1902KB(0)
In intermittent production wells, most of which are free of packers, such issues as the gas-liquid production splitting and the changes in liquid levels in annulus space and tubing with shut-in duration occur. The conventional responding measures determine the liquid level changes in the tubing and casing during the shut-in stage by simply assuming the flow direction of the gas and liquid in the tubing and casing at the shoe, which will introduce significant errors. By employing a discrete wellbore model, considering zero-liquid-flow two-phase flow dynamics and pressure equilibrium in the tubing and casing, a gas-liquid splitting model for intermittent gas wells was established. The model allows for the determination of critical parameters, such as pressure distribution, flow pattern changes, fluctuation in liquid column heights and bubble velocities during the zero-liquid-flow liquid column movement. Additionally, a full-scale wellbore experimental setup was constructed to simulate the ascent of bubbles during shut-in periods in intermittent production wells. By using high-speed cameras, the flow pattern distribution in zero-liquid-flow liquid column was captured, and the velocities and pressures of the bubbles in the liquid column were measured. The research results show that bubbles in the zero-liquid-flow liquid column exhibit dispersed and Taylor bubble forms, with Taylor bubbles becoming dominant as gas flow rates increase. The fluid pressures, flow pattern changes and bubble velocities in the established model were verified based on the experimental results, with an accuracy of over 95%. This model can accurately describe the gas-liquid flow pattern and pressure distribution during after flow stage for intermittent gas production wells.
The relationship between perforation orientation determined by near well coupling in oil reservoirs and oilfield development
PAN Hao, CAO Yanfeng, WEN Min, HOU Zening, MA Nan, QI Zhiyuan
2023, 45(6): 729-737.   doi: 10.13639/j.odpt.202311052
[Abstract](0) [FullText HTML](0) PDF 2813KB(0)
In order to achieve accurate simulation of different perforation orientations during reservoir numerical simulation for horizontal wells, and to improve the simulation accuracy in the well and near-well regions, as well as to investigate the influence of various perforation orientations in horizontal wells on reservoir development, a detailed reservoir-near well-well coupling model was established using three types of grids: corner-point grids, layered unstructured grids and three-dimensional radial grids. This model enables a detailed description of radial flow near the well and the spatial distribution of perforation orientations. By using this model, the influences of four perforating patterns, including top, middle, bottom and all perforations, on reservoir development under two different well diameter conditions were studied. The simulation results show that the top perforation pattern covers the largest affected area, with the lowest bottomhole pressure, the highest cumulative oil production and the best production behavior. The middle and all perforation patterns show similar production behavior, with moderate affected areas and cumulative oil production among the four perforation patterns, but higher bottomhole pressure. The bottom perforation pattern covers the smallest affected area, with lower bottomhole pressure, the lowest cumulative oil production and the worst production behavior. Therefore, the choice of perforation orientation in horizontal wells should prioritize the top perforation pattern. However, due to the lower bottomhole pressure associated with the top perforation pattern, which may lead to gas breakout, the middle or all perforation patterns should be considered if gas breakout is a concern, and bottom perforation pattern is not recommended.
Flow characteristics of fractured horizontal wells in pressure-sensitive multi-media gas reservoirs
ZHU Shaopeng, OU Jinjing
2023, 45(6): 738-747.   doi: 10.13639/j.odpt.202310002
[Abstract](0) [FullText HTML](0) PDF 2167KB(0)
In the context of high-pressure and abnormally high-pressure gas reservoirs, the production pressure drop in gas wells can easily induce a strong pressure-sensitive effect. To investigate the flow characteristics of fractured horizontal wells in pressure-sensitive multi-media gas reservoirs, a comprehensive flow model for multi-stage fractured horizontal wells in pressure-sensitive multi-media gas reservoirs was established. By utilizing point source functions, perturbation methods, Laplace transforms and Fourier integral transforms, the analytical solution for unstable pressure in Laplace space was derived. Subsequently, by employing the Duhamel principle and Stehfest numerical inversion, the bottomhole pressure in real space was obtained, and the log-log theoretical diagram for well testing was plotted. The research shows that stress sensitivity amplifies pressure drop responses during the late flow stages, manifested as an upturn at the end of the log-log well testing curve. As the channeling coefficient increases, the earlier the channeling segment occurs in the multi-media gas reservoir, the more the channeling concavity on the pressure derivative curve moves to the left. The more the artificial fractures, the smaller the angle, the larger the half-length, and the further the pressure derivative curve moves downward. The newly established flow model for pressure-sensitive multi-media gas reservoirs, when combined with actual pressure recovery data, successfully fits and interprets the reservoir parameters and flow characteristics, which versa validates the accuracy of the model.
Step pump injection pressure drop test to determine the morphology of formation fractures after fracturing
CAI Dingning, CHENG Shiqing, LI Yijichuan, BAI Wenpeng, XU Zexuan, WANG Yang
2023, 45(6): 748-755.   doi: 10.13639/j.odpt.202303036
[Abstract](0) [FullText HTML](0) PDF 1375KB(0)
The mini-frac tests can be used to obtain reservoir fracturing characteristics and parameters, which can guide the design of construction parameters in formal fracturing process. By optimizing the method for analyzing the parameters in step pump injection pressure drop testing, the testing process was divided into three stages: pump injection period-early pump injection stage, pump injection period-fracture propagation stage and pressure drop period-fracture extension closure stage. In view of the situations where there are few testing steps, unequal step duration and unobvious inflection points, the pressure characteristics in the early pump injection stage and fracture propagation stage were analyzed by using the radial flow and linear flow models of unsteady flow, respectively, which helps to make the fracture propagation timing and fracture propagation pressure clear. Based on the volume balance relationship during dynamic fluid loss of fracturing fluid and other pressure drop testing methods, the fracture propagation length, fracture width and fracture toughness after pumping-off were calculated. The research results show that this method makes up for the inability to obtain effective fracture propagation pressure due to unclear inflection points of the injection rate-pressure curve curve in non-standard tests, and the calculation results of reservoir and fracturing parameters are reliable. In the absence of experiments, reasonable reference values for fracture toughness were obtained, expanding the application scope of the step-rate tests.
Influence of spontaneous imbibition on post-fracturing well soaking in shale oil reservoirs
WEI Shiming, JIN Yan, XIA Yang, XU Dan, ZENG Ping
2023, 45(6): 756-765.   doi: 10.13639/j.odpt.202302025
[Abstract](0) [FullText HTML](0) PDF 3865KB(0)
To address the current challenges such as the determination of well soaking after fracturing in shale oil reservoirs and lack of theoretical guidance on the design of soaking duration, this study established an oil-water two-phase flow model in consideration of capillary imbibition. By employing finite element-finite volume methods, joint simulation of well soaking and production was performed, which took into account whether the imbibition of the shale matrix will produce micro-fractures and their influence on imbibition and production. Furthermore, the influences of well soaking duration and capillary force on the water absorption of shale matrix during well soaking process and the shale oil production after well opening were investigated. The simulation results revealed that if micro-fractures are generated in the shale matrix due to capillary imbibition of fracturing fluid, imbibition significantly enhances shale oil production. With increasing well soaking duration and shale hydrophilicity, more micro-fractures will be generated in the shale matrix after fracturing, and the water-oil displacement effect becomes stronger, leading to increased shale oil production. In cases where capillary imbibition does not introduce micro-fractures in the shale matrix, the imbibition effect will reduce shale oil production. With soaking duration and shale hydrophilicity increase, water saturation in the matrix rises, causing a decrease in the relative permeability of the oil phase, resulting in reduced shale oil production. This study clarifies that not all shale oil reservoirs are suitable for well soaking after hydraulic fracturing, which provide a crucial guidance for the design of hydraulic fracturing in shale oil reservoirs.
Supercapacitor energy storage system for pumping units
ZHANG Zhonghui, ZHENG Qiang, LIU Xiaoling, HUANG Runjing, CHEN Zhaowei
2023, 45(6): 766-772.   doi: 10.13639/j.odpt.202311048
[Abstract](0) [FullText HTML](0) PDF 1230KB(0)
Addressing issues such as difficulty in maintaining complete balance of the balance block in the pumping unit system, grid pollution caused by reverse power generation, heating caused by braking, and energy waste, a comprehensive solution of energy storage system for pumping units based on super capacitor was proposed. Design of specific functional modules such as super capacitor modules, fast charge and discharge units, reverse power generation status identification systems as well as protection systems were innovated, and the field trial of energy storage system for pumping units was conducted in three wells in Shengli Oilfield. When super capacitors are determined as the preferred storage medium for the energy storage system used by oil pumping units, the field application shows the capacity remains at 251 F with a capacity retention rate of 86.55% after 170 000 cycles, meeting the demands for the energy storage system used by oil pumping units. During charging, ZVS phase-shift technology was employed, ensuring that power devices operate at a zero-voltage turn-on state, minimizing power losses. Following the addition of the energy storage system, the power consumption of the oil pumping units significantly decreased. Notably, the power savings for Pump No. 3 reached 27.0%, translating to a daily energy saving of 27.11 kW · h and an annual cost saving of RMB 6 829. This research plays significant role in making full use of energy reversely generated by the pumping unit and power saving, which provides valuable experience for the subsequent promotion and application of pumping unit energy-saving technologies.
A mixed integer nonlinear optimization method for inter well pumping between pumping units in a non energy storage opto electric microgrid
GAO Xiaoyong, LI Chenlong, TAN Chaodong, HUANG Fuyu, MI Siyi, YUAN Yu
2023, 45(6): 773-782.   doi: 10.13639/j.odpt.202311042
[Abstract](0) [FullText HTML](0) PDF 1407KB(0)
For most cluster wells in low-permeability reservoirs, intermittent pumping is adopted due to insufficient liquid supply, and the introduction of green energy such as photovoltaics and wind power is playing a crucial role in reducing carbon emissions in oilfield production. To address issues such as high energy consumption of well clusters running in manually scheduled staggered well opening and intermittent pumping systems, by taking the start-stop status and the power frequency of each pump, as well as the output of each photovoltaic unit and high-voltage power grid as variables for decision, mutual feedback of electrical energy reversely generated from pump units was achieved using DC bus. Taking into account the constraints of the source-load side according to the production demand of the well cluster, a mixed-integer nonlinear model for staggered well opening and intermittent pumping operation in an energy-storage-free “solar-electric” micro power grid was established with the goal of minimizing the system operating cost. And the model can be solved with Gurobi solver. Case analysis results show that compared to constant operation with high-voltage power grid supply and artificially scheduled intermittent pumping systems, the power consumption of the well cluster was reduced by 35.687% and 15.219%, and the system operating costs were reduced by 35.471% and 23.884%, respectively. Moreover, compared to the latter, the daily production of the well cluster increased by 21.620%. The study introduces photovoltaics into the intermittent pumping system and establishes a scheduling model, which significantly reduces well cluster energy consumption and operating costs, highlighting the effectiveness of the model.
Separate-layer waterflooding technology based on bidirectional cable-less data transmission
SUN Peng, HE Zuqing, PENG Hanxiu
2023, 45(6): 783-788.   doi: 10.13639/j.odpt.202208079
[Abstract](0) [FullText HTML](0) PDF 2738KB(0)
Mature oilfields are challenged by increasing casing damages in water injectors, prominent interlayer contradictions, and intensive water regulation/metering workload, long period and low efficiency in traditional separate-layer waterflooding. The intelligent separate-layer waterflooding technology was investigated to enable the bidirectional cable-less data transmission of parameters such as temperature, pressure, flow rate and nozzle state and the real-time regulation of injector rate. The bidirectional cable-less data transmission system is composed of surface system (incl. surface signal control system and control circuit) and downhole system (incl. pressure wave intercommunication system, bidirectional anchor, and intelligent water distributor). Laboratory simulation of intelligent well completion was performed to verify the effectiveness and reliability of control command and control circuit. Moreover, field tests in 7 wells demonstrate the success rate of 100% for both bidirectional data transmission and regulation on separate-layer water injection. The proposed technology provides a valuable support to the improvement of reservoir waterflooding performance, cost reduction and benefit increasing.

Supervisor: China National Petroleum Corporation(CNPC)

Sponsor: Huabei Oilfield Branch,PetroChina

Editor & Publisher: ODPT Etitorial Department

Editor-in-Chief: Dong Fan

Proprieter: Zhu QingZhong

Deputy Editor-in-Chief: Fu LiXia

Address: Research Institute of Engineering and Technology, No. 041 South Huizhan Road, Renqiu City, Hebei Province

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