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Abstract:
Low-permeability shale reservoirs can hardly form industrial oil and gas flow naturally, and their commercial production is commonly realized by using horizontal well and hydraulic fracturing to create hydraulic fracture networks. As large-scale infill well deployment and fracturing is conducted, however, horizontal well spacing gets short and stimulated reservoir volume (SRV) is increased, so interference induced by hydraulic fractures occurs between wells, which impacts the wellhead pressure and production rate of the neighboring well and even induces the problems of well control, casing damage and proppant invasion and seriously results in the abandonment of horizontal well, so as to impact the production efficiency greatly. In addition, the depletion of old wells can lead to the dynamic evolution of reservoir geostress on the basis of the in-situ geostress to form the complex geostress state, which will impact the reservoir stimulation effects of infill horizontal wells and refracturing wells and restrict the productivity performance of well pads. The development of the shale oil and gas resources in the Junggar Basin, the Sichuan Basin and the Ordos Basin of China has stepped into the stage of small well spacing and infill well deployment, so well interference has already impact the normal production obviously. Therefore, it is in urgent to carry out specific studies. In this paper, domestic and foreign well interference phenomena, mechanism studies and diagnosis methods of shale oil and gas were introduced in details, and the intervention countermeasures were proposed. It is indicated that accurate characterization and prediction of fractured horizontal well interference shall be carried out in the framework of geology and engineering integration. The accurate understanding of natural fractures, faults, in-situ geostress and reservoir rock mechanical characteristics is the prerequisite to evaluate well interference. The modeling and characterization of formation depletion induced dynamic geostress and complex hydraulic fracture network is the key means to quantitatively evaluate the interconnection of complex fracture network between wells, as well as the effective method to quantitatively predict the impact of well interference on the estimated ultimate reserve (EUR) of well pad. Well shutdown, liquid injection into old well, refracturing, well spacing optimization and fracturing optimization are the means to intervene or diminish well interference.
Low-permeability shale reservoirs can hardly form industrial oil and gas flow naturally, and their commercial production is commonly realized by using horizontal well and hydraulic fracturing to create hydraulic fracture networks. As large-scale infill well deployment and fracturing is conducted, however, horizontal well spacing gets short and stimulated reservoir volume (SRV) is increased, so interference induced by hydraulic fractures occurs between wells, which impacts the wellhead pressure and production rate of the neighboring well and even induces the problems of well control, casing damage and proppant invasion and seriously results in the abandonment of horizontal well, so as to impact the production efficiency greatly. In addition, the depletion of old wells can lead to the dynamic evolution of reservoir geostress on the basis of the in-situ geostress to form the complex geostress state, which will impact the reservoir stimulation effects of infill horizontal wells and refracturing wells and restrict the productivity performance of well pads. The development of the shale oil and gas resources in the Junggar Basin, the Sichuan Basin and the Ordos Basin of China has stepped into the stage of small well spacing and infill well deployment, so well interference has already impact the normal production obviously. Therefore, it is in urgent to carry out specific studies. In this paper, domestic and foreign well interference phenomena, mechanism studies and diagnosis methods of shale oil and gas were introduced in details, and the intervention countermeasures were proposed. It is indicated that accurate characterization and prediction of fractured horizontal well interference shall be carried out in the framework of geology and engineering integration. The accurate understanding of natural fractures, faults, in-situ geostress and reservoir rock mechanical characteristics is the prerequisite to evaluate well interference. The modeling and characterization of formation depletion induced dynamic geostress and complex hydraulic fracture network is the key means to quantitatively evaluate the interconnection of complex fracture network between wells, as well as the effective method to quantitatively predict the impact of well interference on the estimated ultimate reserve (EUR) of well pad. Well shutdown, liquid injection into old well, refracturing, well spacing optimization and fracturing optimization are the means to intervene or diminish well interference.
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Abstract:
The methods for calculating pump intake pressure and piston stress were determined respectively based on the differences of liquid supply capacity in the lift process of sucker-rod pump. After the static model was established, the method for calculating the damping factor in the process of well lift was modified according to the sucker-rod wave theory, and the dynamic model of the lift of sucker-rod pump was established. the numerical distribution of pressure and sucker rod string stress in the vertical space of well under different liquid supplying conditions was calculated under the constraint of surface dynamometer card, the pump intake pressure, dynamic liquid level, formation flow pressure and other parameters were simulation calculated, and the method for the continuous simulation calculation of the lift process parameters of sucker-rod pump under different liquid supplying conditions was established. The research results show that this method can meet the required calculation accuracy of dynamic liquid level in oil wells under the working conditions with insufficient liquid supply and provide theoretical basis for the analysis and working system optimization and adjustment of well lift.
The methods for calculating pump intake pressure and piston stress were determined respectively based on the differences of liquid supply capacity in the lift process of sucker-rod pump. After the static model was established, the method for calculating the damping factor in the process of well lift was modified according to the sucker-rod wave theory, and the dynamic model of the lift of sucker-rod pump was established. the numerical distribution of pressure and sucker rod string stress in the vertical space of well under different liquid supplying conditions was calculated under the constraint of surface dynamometer card, the pump intake pressure, dynamic liquid level, formation flow pressure and other parameters were simulation calculated, and the method for the continuous simulation calculation of the lift process parameters of sucker-rod pump under different liquid supplying conditions was established. The research results show that this method can meet the required calculation accuracy of dynamic liquid level in oil wells under the working conditions with insufficient liquid supply and provide theoretical basis for the analysis and working system optimization and adjustment of well lift.
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Abstract:
Igneous rocks dominated by basalt and tuff of overflow facies are widely developed in the Dongying Formation in the gentle slope belt of Huanghekou Sag. This type of rocks are relatively hard and tend to suffer low rate of penetration (ROP), circulation loss, hole collapse and other problems in the process of drilling, which have greater impact on drilling engineering. In this paper, the volcanic eruption cycles and stages in the first and second Members of Dongying Formation (Ed1 and Ed2) were identified and divided by using mud logging and wireline logging data comprehensively. And combined with seismic data, the volcanic overflow facies in BZ34-9 block was described precisely. It is indicated that the volcanic rocks in the study area are mainly distributed in the conjugate strike-slip fault zone of BZ34-9 and KL4-2 structure zones, where fissure type volcanic eruption is dominant. Six eruptive cycles and sixteen eruptive stages can be identified and divided in Ed1 and Ed2. The eruptive cycles in the early stage of lower Ed2 and the early and late stages of Ed1 are small sized while those in the late stage of lower Ed2 and the early and late stages of upper Ed2 are large sized, which reflects the growth process of volcanic activity from weak to strong and then weak gradually. Based on the construction of complex fault and formation model, combined with the simulation of tectonic stress field, geomechanically weak belts or fracture development characteristics can be predicted, which provide reliable basis for the trajectory optimization of development wells and the selection of drilling tools, drilling parameters and drilling fluids.
Igneous rocks dominated by basalt and tuff of overflow facies are widely developed in the Dongying Formation in the gentle slope belt of Huanghekou Sag. This type of rocks are relatively hard and tend to suffer low rate of penetration (ROP), circulation loss, hole collapse and other problems in the process of drilling, which have greater impact on drilling engineering. In this paper, the volcanic eruption cycles and stages in the first and second Members of Dongying Formation (Ed1 and Ed2) were identified and divided by using mud logging and wireline logging data comprehensively. And combined with seismic data, the volcanic overflow facies in BZ34-9 block was described precisely. It is indicated that the volcanic rocks in the study area are mainly distributed in the conjugate strike-slip fault zone of BZ34-9 and KL4-2 structure zones, where fissure type volcanic eruption is dominant. Six eruptive cycles and sixteen eruptive stages can be identified and divided in Ed1 and Ed2. The eruptive cycles in the early stage of lower Ed2 and the early and late stages of Ed1 are small sized while those in the late stage of lower Ed2 and the early and late stages of upper Ed2 are large sized, which reflects the growth process of volcanic activity from weak to strong and then weak gradually. Based on the construction of complex fault and formation model, combined with the simulation of tectonic stress field, geomechanically weak belts or fracture development characteristics can be predicted, which provide reliable basis for the trajectory optimization of development wells and the selection of drilling tools, drilling parameters and drilling fluids.
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Abstract:
The trajectory design of extended reach well is quite important for its safe and efficient drilling. The drilling of extended reach well faces several problems, such as poor wellbore stability in the long open hole section, high torque and drag, serious string buckling and difficult hole cleaning, so its trajectory design needs comprehensive analysis and evaluation. In this paper, a model for evaluating the trajectory design scheme of extended reach well was established based on the entropy weight method, in which the weights are calculated and the schemes are scored by making full use of the fluctuation of evaluation indexes, so that the trajectory design scheme of extended reach well is quantitatively evaluated. It has been successfully applied to the drilling of extended reach well in one certain oilfield. This research not only provides a new idea and a guidance method for the selection of trajectory design scheme of extended reach well, but also a technical reference for the subsequent drilling technology optimization and risk evaluation of extended reach well.
The trajectory design of extended reach well is quite important for its safe and efficient drilling. The drilling of extended reach well faces several problems, such as poor wellbore stability in the long open hole section, high torque and drag, serious string buckling and difficult hole cleaning, so its trajectory design needs comprehensive analysis and evaluation. In this paper, a model for evaluating the trajectory design scheme of extended reach well was established based on the entropy weight method, in which the weights are calculated and the schemes are scored by making full use of the fluctuation of evaluation indexes, so that the trajectory design scheme of extended reach well is quantitatively evaluated. It has been successfully applied to the drilling of extended reach well in one certain oilfield. This research not only provides a new idea and a guidance method for the selection of trajectory design scheme of extended reach well, but also a technical reference for the subsequent drilling technology optimization and risk evaluation of extended reach well.
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Abstract:
Steam assisted gravity drainage (SAGD) is an effective technology to develop thick super heavy oil reservoirs, but there are serious steam overlay, great heat loss, low oil/steam ratio and other problems in the middle and late stages of the development, which impact the development effect. In this paper, the influences of flue gas on in-place oil properties and the heat loss of steam in the overlying strata, change laws of steam chamber and production characteristics after the injection of steam with flue gas were experimentally studied in the laboratory by using PVT analyzer and proportional physical simulation system. It is indicated that the injected flue gas can effectively reduce the in-place oil viscosity, improve the flow capacity of crude oil and increase the volume coefficient and the elastic energy. Compared with conventional SAGD, the flue gas-assisted SAGD speeds up the transverse expansion of steam chamber and slows down the longitudinal expansion, so as to effectively inhibit the phenomenon of steam overlay. The flue gas injected together with steam accumulates above the steam chamber to form a heat insulation layer, which reduces the heat loss of steam in the overlying cover, so as to improve the heat utilization efficiency. Steam injection with flue gas in the process of conventional SAGD can reduce the amount of steam injection to a certain degree, increase the oil/steam ratio and improve the development effect.
Steam assisted gravity drainage (SAGD) is an effective technology to develop thick super heavy oil reservoirs, but there are serious steam overlay, great heat loss, low oil/steam ratio and other problems in the middle and late stages of the development, which impact the development effect. In this paper, the influences of flue gas on in-place oil properties and the heat loss of steam in the overlying strata, change laws of steam chamber and production characteristics after the injection of steam with flue gas were experimentally studied in the laboratory by using PVT analyzer and proportional physical simulation system. It is indicated that the injected flue gas can effectively reduce the in-place oil viscosity, improve the flow capacity of crude oil and increase the volume coefficient and the elastic energy. Compared with conventional SAGD, the flue gas-assisted SAGD speeds up the transverse expansion of steam chamber and slows down the longitudinal expansion, so as to effectively inhibit the phenomenon of steam overlay. The flue gas injected together with steam accumulates above the steam chamber to form a heat insulation layer, which reduces the heat loss of steam in the overlying cover, so as to improve the heat utilization efficiency. Steam injection with flue gas in the process of conventional SAGD can reduce the amount of steam injection to a certain degree, increase the oil/steam ratio and improve the development effect.
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Abstract:
Downhole throttling in gas wells is one key technology for the low-cost development of gas fields, and under suitable conditions, “downhole throttling + foam drainage gas recovery” process can improve the liquid carrying capacity of gas well. When the traditional gas-liquid two-phase choke flow pressure drop model is used for the size design of the downhole throttling choke in the gas well with foam drainage gas recovery process, the requireed production proration of the gas well cannot be satisified. Testing the throttling pressure drop laws and establishing or improving the mathematical model is conducive to improve the design level of downhole throttling in the gas wells with foam drainage gas recovery process. Physical simulation experimental equipment was designed and established for the downhole throttling in the gas wells with foam drainage gas recovery process. Then, the throttling pressure drop laws at different mass fractions of foam drainage agent were tested by using the foam drainage agent UT-11. In addition, four common mechanism models of gas-liquid two-phase choke flow (Sachdeva model, Perkins model, Ashford model and slippage numerical model) were evaluated from the aspects of choke flow regime transition predicting capacity and mass velocity and pre-choke pressure predicting capacity by using the experimetnal data. Finally, a formula for calculating the slippage factor of foam flow was constructed based on the experimental data. In this way, the accuracy of the slippage numerical model is improved, the absolute percentage error of mass velocity is decreased from 13.7% to 7.69% and that of pre-choke pressure is decreased from 16.5% to 8.01%. In conclusion, the research results provide an important theoretical base for the size design and pre-choke pressure prediction of downhole choke in the gas wells with foam drainage gas recovery process.
Downhole throttling in gas wells is one key technology for the low-cost development of gas fields, and under suitable conditions, “downhole throttling + foam drainage gas recovery” process can improve the liquid carrying capacity of gas well. When the traditional gas-liquid two-phase choke flow pressure drop model is used for the size design of the downhole throttling choke in the gas well with foam drainage gas recovery process, the requireed production proration of the gas well cannot be satisified. Testing the throttling pressure drop laws and establishing or improving the mathematical model is conducive to improve the design level of downhole throttling in the gas wells with foam drainage gas recovery process. Physical simulation experimental equipment was designed and established for the downhole throttling in the gas wells with foam drainage gas recovery process. Then, the throttling pressure drop laws at different mass fractions of foam drainage agent were tested by using the foam drainage agent UT-11. In addition, four common mechanism models of gas-liquid two-phase choke flow (Sachdeva model, Perkins model, Ashford model and slippage numerical model) were evaluated from the aspects of choke flow regime transition predicting capacity and mass velocity and pre-choke pressure predicting capacity by using the experimetnal data. Finally, a formula for calculating the slippage factor of foam flow was constructed based on the experimental data. In this way, the accuracy of the slippage numerical model is improved, the absolute percentage error of mass velocity is decreased from 13.7% to 7.69% and that of pre-choke pressure is decreased from 16.5% to 8.01%. In conclusion, the research results provide an important theoretical base for the size design and pre-choke pressure prediction of downhole choke in the gas wells with foam drainage gas recovery process.
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Abstract:
After the gas wells in the Lower Paleozoic carbonate reservoirs of the Ordos Basin are put into production, the formation pressure coefficient decreases. And in the process of well workover, reservoir gas channeling and wellbore fluid loss happen frequently. Therefore, it is necessary to plug the reservoirs, so as to ensure safe operation. In some reservoirs, gas production capacity is damaged by water production while water control is needed. Plugging fuzzy-ball fluid was adopted to carry the surfactant which can increase gas-water flow resistance difference into low-pressure gas reservoirs, to transform the traditional damage control into the gas stabilization and water control. In the experiment, a sand packed tube (diameter 38 mm and length 30-100 cm) was prepared to simulate the Lower Paleozoic carbonate reservoirs. The measurement results show that the displacement pressure is 4.59-16.18 MPa when the injected fuzzy-ball fluid flows to the outlet and it is increased by 7.04-18.22 MPa after repetitive fresh water injection, which is in proportion to the filling radius of fuzzy-ball fluid. Gel breaker is injected into sand packed tubes with four lengths to speed up the flowback. After nitrogen is injected under the same displacement pressure for 180 min, the permeability recovery ratio is 2.02%-6.07% higher than the formation water and the recovery ratio difference is in proportion to the filling radius. In four gas wells, the filling radius of fuzzy-ball fluid in the reservoirs increases from 2.12 m to 8.97 m, the formation bearing strength rises from 17 MPa to 21 MPa. The difference between daily water production decrease ratio and daily gas production decrease ratio rises from 18.68% 90 days before the operation to 62.90% 90 days after the operation. It is indicated that the temporary plugging strength and water control effect of fuzzy-ball fluid in the Lower Paleozoic carbonate reservoirs are both in proportion to the filling radius. Furthermore, fuzzy-ball fluid is conducive to the realization of temporary plugging and gas stabilization and water control in the process of well workover.
After the gas wells in the Lower Paleozoic carbonate reservoirs of the Ordos Basin are put into production, the formation pressure coefficient decreases. And in the process of well workover, reservoir gas channeling and wellbore fluid loss happen frequently. Therefore, it is necessary to plug the reservoirs, so as to ensure safe operation. In some reservoirs, gas production capacity is damaged by water production while water control is needed. Plugging fuzzy-ball fluid was adopted to carry the surfactant which can increase gas-water flow resistance difference into low-pressure gas reservoirs, to transform the traditional damage control into the gas stabilization and water control. In the experiment, a sand packed tube (diameter 38 mm and length 30-100 cm) was prepared to simulate the Lower Paleozoic carbonate reservoirs. The measurement results show that the displacement pressure is 4.59-16.18 MPa when the injected fuzzy-ball fluid flows to the outlet and it is increased by 7.04-18.22 MPa after repetitive fresh water injection, which is in proportion to the filling radius of fuzzy-ball fluid. Gel breaker is injected into sand packed tubes with four lengths to speed up the flowback. After nitrogen is injected under the same displacement pressure for 180 min, the permeability recovery ratio is 2.02%-6.07% higher than the formation water and the recovery ratio difference is in proportion to the filling radius. In four gas wells, the filling radius of fuzzy-ball fluid in the reservoirs increases from 2.12 m to 8.97 m, the formation bearing strength rises from 17 MPa to 21 MPa. The difference between daily water production decrease ratio and daily gas production decrease ratio rises from 18.68% 90 days before the operation to 62.90% 90 days after the operation. It is indicated that the temporary plugging strength and water control effect of fuzzy-ball fluid in the Lower Paleozoic carbonate reservoirs are both in proportion to the filling radius. Furthermore, fuzzy-ball fluid is conducive to the realization of temporary plugging and gas stabilization and water control in the process of well workover.
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Abstract:
The drilling operation of extended reach well is of great difficulty and it requires highly in hole cleaning operation, so the influence of cuttings accumulation on the torque and drag shall not be neglected. In this paper, the coupling model of hole cleaning and torque and drag was established by modifying the soft string model which is commonly used to calculate the torque and drag. Then, the model for predicting the mechanical extension limit of extended reach well was established under the constraint of drilling rig, string and bit. Finally, a case study was performed on a real extended reach well with horizontal/vertical ratio of 5 by taking the influence of cuttings on the torque and drag into consideration. The torque and drag under different working conditions was calculated, the mechanical extension limit of horizontal section was predicted, and influence of the height of cuttings bed on the mechanical extension limit of extended reach well was analyzed. It is indicated that the mechanical extension limit of extended reach well predicted by the coupling model is more effective and true than the calculation result of the common soft string model. In addition, as cuttings bed accumulates, the influence of cuttings on the mechanical extension limit of extended reach well increases. The research results provide scientific basis for risk prediction, design and construction of extended reach wells.
The drilling operation of extended reach well is of great difficulty and it requires highly in hole cleaning operation, so the influence of cuttings accumulation on the torque and drag shall not be neglected. In this paper, the coupling model of hole cleaning and torque and drag was established by modifying the soft string model which is commonly used to calculate the torque and drag. Then, the model for predicting the mechanical extension limit of extended reach well was established under the constraint of drilling rig, string and bit. Finally, a case study was performed on a real extended reach well with horizontal/vertical ratio of 5 by taking the influence of cuttings on the torque and drag into consideration. The torque and drag under different working conditions was calculated, the mechanical extension limit of horizontal section was predicted, and influence of the height of cuttings bed on the mechanical extension limit of extended reach well was analyzed. It is indicated that the mechanical extension limit of extended reach well predicted by the coupling model is more effective and true than the calculation result of the common soft string model. In addition, as cuttings bed accumulates, the influence of cuttings on the mechanical extension limit of extended reach well increases. The research results provide scientific basis for risk prediction, design and construction of extended reach wells.
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doi: 10.13639/j.odpt.2020.03.021
Abstract:
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.
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.
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2021, 43(2): 131-138.
doi: 10.13639/j.odpt.2021.02.001
Abstract:
More and more practices of oil and gas field exploration and development indicate that geology-engineering integration is the only way to realize the benefit exploration and development of complex oil and gas reservoirs. In this paper, the research and application status of geology-engineering integration technology was summarized and its development process and implementation ideas were analysed. Domestic and foreign application cases were described. In addition, the research directions of geology-engineering integration were pointed out. It is indicated that geology-engineering integration has been practically applied in the North America and China’s Southwest Oil & Gasfield, Zhejiang Oilfield, Tarim Oilfield, Xinjiang Oilfield, Changqing Oilfield, Dagang Oilfield and Jilin Oilfield, and BHGE, Schlumberger and Halliburton have been actively cooperating with each oilfield to provide the services and software platforms for geology-engineering integration. After the implementation of geology-engineering integration in Changning Shale Gas Demonstration Area, the daily gas production is increased by 127%, the drilling rate is increased by 180%, the drilling cycle is shorted by 53.3% and all production performances of development wells exceed the expected indicators. As for domestic geology-engineering integration, it is in urgent to carry out the researches in the following aspects. First, form the unified idea of geology-engineering integration. Second, set up and improve the operation mechanism of geology-engineering integration. Third, strengthen the performance evaluation of geology-engineering integration. Fourth, speed up the technological breakthrough in the geology-engineering integrated development of shale gas. Fifth, strengthen the application of geomechanics in geology-engineering integration. Sixth, train inter-disciplinary talents in the field of geology-engineering integration.
More and more practices of oil and gas field exploration and development indicate that geology-engineering integration is the only way to realize the benefit exploration and development of complex oil and gas reservoirs. In this paper, the research and application status of geology-engineering integration technology was summarized and its development process and implementation ideas were analysed. Domestic and foreign application cases were described. In addition, the research directions of geology-engineering integration were pointed out. It is indicated that geology-engineering integration has been practically applied in the North America and China’s Southwest Oil & Gasfield, Zhejiang Oilfield, Tarim Oilfield, Xinjiang Oilfield, Changqing Oilfield, Dagang Oilfield and Jilin Oilfield, and BHGE, Schlumberger and Halliburton have been actively cooperating with each oilfield to provide the services and software platforms for geology-engineering integration. After the implementation of geology-engineering integration in Changning Shale Gas Demonstration Area, the daily gas production is increased by 127%, the drilling rate is increased by 180%, the drilling cycle is shorted by 53.3% and all production performances of development wells exceed the expected indicators. As for domestic geology-engineering integration, it is in urgent to carry out the researches in the following aspects. First, form the unified idea of geology-engineering integration. Second, set up and improve the operation mechanism of geology-engineering integration. Third, strengthen the performance evaluation of geology-engineering integration. Fourth, speed up the technological breakthrough in the geology-engineering integrated development of shale gas. Fifth, strengthen the application of geomechanics in geology-engineering integration. Sixth, train inter-disciplinary talents in the field of geology-engineering integration.
2021, 43(2): 139-145.
doi: 10.13639/j.odpt.2021.02.002
Abstract:
As the offshore oil and gas exploration and development advances continuously, deep wells in deep water (referred as the dual-deep well) have become the hot spot of exploration and development all over the world. Compared with conventional deepwater wells, dual-deep wells will face more complicated downhole geological setting and marine environment and greater operation risks. In recent years, with the continuous progresses of deepwater drilling operation, a set of key technologies for the drilling of dual-deep wells have been developed preliminarily from 7 aspects, including casing program, managed pressure drilling, drilling fluid system, cementing technology, well control, subsea wellhead and well integrity. These key drilling technologies provide the technological base for speeding up offshore oil and gas exploration and development. The research achievements have been applied in X Block of the South China Sea and the application results are remarkable. It is practically proved that the key technologies for the drilling of dual-deep wells have preliminarily adapted to the drilling operation requirements of deep wells in deep water, and in the future, it is necessary to promote the research and development of the drilling equipment and technologies of automation, scale, information and intelligence, so as to ensure the safe and efficient operation of dual-deep wells.
As the offshore oil and gas exploration and development advances continuously, deep wells in deep water (referred as the dual-deep well) have become the hot spot of exploration and development all over the world. Compared with conventional deepwater wells, dual-deep wells will face more complicated downhole geological setting and marine environment and greater operation risks. In recent years, with the continuous progresses of deepwater drilling operation, a set of key technologies for the drilling of dual-deep wells have been developed preliminarily from 7 aspects, including casing program, managed pressure drilling, drilling fluid system, cementing technology, well control, subsea wellhead and well integrity. These key drilling technologies provide the technological base for speeding up offshore oil and gas exploration and development. The research achievements have been applied in X Block of the South China Sea and the application results are remarkable. It is practically proved that the key technologies for the drilling of dual-deep wells have preliminarily adapted to the drilling operation requirements of deep wells in deep water, and in the future, it is necessary to promote the research and development of the drilling equipment and technologies of automation, scale, information and intelligence, so as to ensure the safe and efficient operation of dual-deep wells.
2021, 43(2): 146-150, 159.
doi: 10.13639/j.odpt.2021.02.003
Abstract:
Well trajectory control is the basic operation task of directional well engineers, and in the past, the control parameters were often estimated according to experience. In this paper, a mathematic model was established based on the constant tool face angle curve for the “combined+sliding” drilling process of joint. Then, two algorithms to solve this mathematical model were provided according to the concept of optimization, and the optimal design scheme of construction parameters was worked out. Finally, the algorithms were verified sufficiently by using the theoretical model data. It is indicated that the algorithms can inversely calculate the theoretical model parameters with quite high numerical accuracy (10−9). And as for the actual drilling data, the accuracy is 10−2, which meets the accuracy requirement of the engineering. This method can be used by the on-site directional well engineers to perform daily design of control parameters. And combined with the real-time acquisition of MWD data, its application prospect in the real-time drilling feedback control of electric control system is extensive.
Well trajectory control is the basic operation task of directional well engineers, and in the past, the control parameters were often estimated according to experience. In this paper, a mathematic model was established based on the constant tool face angle curve for the “combined+sliding” drilling process of joint. Then, two algorithms to solve this mathematical model were provided according to the concept of optimization, and the optimal design scheme of construction parameters was worked out. Finally, the algorithms were verified sufficiently by using the theoretical model data. It is indicated that the algorithms can inversely calculate the theoretical model parameters with quite high numerical accuracy (10−9). And as for the actual drilling data, the accuracy is 10−2, which meets the accuracy requirement of the engineering. This method can be used by the on-site directional well engineers to perform daily design of control parameters. And combined with the real-time acquisition of MWD data, its application prospect in the real-time drilling feedback control of electric control system is extensive.
2021, 43(2): 151-159.
doi: 10.13639/j.odpt.2021.02.004
Abstract:
When drilling through the hard and brittle fractured oil shale, borehole collapse is likely to happen, which seriously restricts the efficient development of shale oil and gas. In this paper, the shale circumferential stress distribution model was established by considering the influences of chemical potential difference, hydraulic pressure difference and fracture seepage on the formation pressure near the wellbore. Then, the model for calculating the shear stress and normal stress under the occurrence of any fracture surface was established based on the occurrence of fracture surface in shale formation. Finally, the hydraulic-mechanical-chemical-thermal multi-field coupling model of stable wellbore in the fracture surface containing shale was formed based on the failure criterion of fracture surface containing shale that the shear stress on the fracture surface is larger than the friction force. The analysis on the wellbore stability in the hard and brittle fractured oil shale of ZH sag shows that when the drilling is performed in the direction of the minimum horizontal geostress in this block, the minimum formation collapse pressure is 1.173 g/cm3, and the existence of formation fractures leads to the increase of the minimum collapse pressure in this direction by 0.05 g/cm3. The 10 d collapse pressure of horizontal hole rises to 1.38 g/cm3. What’s more, the seepage leads to the increase of the formation collapse pressure by 0.04 g/cm3, and low-temperature and low-activity drilling fluid can reduce the borehole collapse pressure effectively, which is favorable for the wellbore stability in the oil shale of ZH sag.
When drilling through the hard and brittle fractured oil shale, borehole collapse is likely to happen, which seriously restricts the efficient development of shale oil and gas. In this paper, the shale circumferential stress distribution model was established by considering the influences of chemical potential difference, hydraulic pressure difference and fracture seepage on the formation pressure near the wellbore. Then, the model for calculating the shear stress and normal stress under the occurrence of any fracture surface was established based on the occurrence of fracture surface in shale formation. Finally, the hydraulic-mechanical-chemical-thermal multi-field coupling model of stable wellbore in the fracture surface containing shale was formed based on the failure criterion of fracture surface containing shale that the shear stress on the fracture surface is larger than the friction force. The analysis on the wellbore stability in the hard and brittle fractured oil shale of ZH sag shows that when the drilling is performed in the direction of the minimum horizontal geostress in this block, the minimum formation collapse pressure is 1.173 g/cm3, and the existence of formation fractures leads to the increase of the minimum collapse pressure in this direction by 0.05 g/cm3. The 10 d collapse pressure of horizontal hole rises to 1.38 g/cm3. What’s more, the seepage leads to the increase of the formation collapse pressure by 0.04 g/cm3, and low-temperature and low-activity drilling fluid can reduce the borehole collapse pressure effectively, which is favorable for the wellbore stability in the oil shale of ZH sag.
2021, 43(2): 160-169, 238.
doi: 10.13639/j.odpt.2021.02.005
Abstract:
Sand erodes the wire wrapped screen again and again and results in its local damage (e.g. the deformation of screen mesh size), which is main cause leading to the sand control failure of wire wrapped screen ultimately. At present, the theoretical studies on the erosion destroy of wire wrapped screen generally consider the mass loss of the wire wrapped screen only, but not the influences of screen mesh deformation on the sand control effect of wire wrapped screen. In this paper, the CFD finite element model was established based on the theory of erosion-dynamic mesh coupling, and the liquid-solid two-phase flow model of wire wrapped screen was established by means of Mclaury abrasion forecast model and Realizable k-\begin{document}$\varepsilon $\end{document} ![]()
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Sand erodes the wire wrapped screen again and again and results in its local damage (e.g. the deformation of screen mesh size), which is main cause leading to the sand control failure of wire wrapped screen ultimately. At present, the theoretical studies on the erosion destroy of wire wrapped screen generally consider the mass loss of the wire wrapped screen only, but not the influences of screen mesh deformation on the sand control effect of wire wrapped screen. In this paper, the CFD finite element model was established based on the theory of erosion-dynamic mesh coupling, and the liquid-solid two-phase flow model of wire wrapped screen was established by means of Mclaury abrasion forecast model and Realizable k-
2021, 43(2): 170-176.
doi: 10.13639/j.odpt.2021.02.006
Abstract:
During the construction of dense cluster wells, the magnetic interference of casing is complicated, the anti-collision construction is difficult and the location relationships between wells can be hardly determined. To solve these problems, it was proposed to adopt the casing coordinate section method to locate the well trajectory in the vertical section of cluster well with the magnetic interference of casing. The mathematical model of the magnetic field on the cross section of casing was established by simplifying the magnetization model of the space near the casing. In addition, the distribution laws of the magnetic field on the cross section of casing were figured out by performing simulation experiments on the magnetic interference of casing. Based on this, the casing coordinate section method was put forward. Then, it was used to invert the spatial location of measurement points in the casing and plot the trajectory of the hole section with magnetic interference in the well being drilled, so that the relative spatial relation between the measurement points and the neighboring casing can be discriminated accurately in the hole section with magnetic interference. The field construction test in 10 cluster wells of Huabei Oilfield verifies the accuracy and validity of casing coordinate section method. Thus, the anti-collision relation of cluster well is located accurately and the anti-collision problem in the construction of dense cluster well is solved.
During the construction of dense cluster wells, the magnetic interference of casing is complicated, the anti-collision construction is difficult and the location relationships between wells can be hardly determined. To solve these problems, it was proposed to adopt the casing coordinate section method to locate the well trajectory in the vertical section of cluster well with the magnetic interference of casing. The mathematical model of the magnetic field on the cross section of casing was established by simplifying the magnetization model of the space near the casing. In addition, the distribution laws of the magnetic field on the cross section of casing were figured out by performing simulation experiments on the magnetic interference of casing. Based on this, the casing coordinate section method was put forward. Then, it was used to invert the spatial location of measurement points in the casing and plot the trajectory of the hole section with magnetic interference in the well being drilled, so that the relative spatial relation between the measurement points and the neighboring casing can be discriminated accurately in the hole section with magnetic interference. The field construction test in 10 cluster wells of Huabei Oilfield verifies the accuracy and validity of casing coordinate section method. Thus, the anti-collision relation of cluster well is located accurately and the anti-collision problem in the construction of dense cluster well is solved.
2021, 43(2): 177-183.
doi: 10.13639/j.odpt.2021.02.007
Abstract:
The deep oil/gas bearing structures in the southwest zone of Bozhong sag, Bohai Oilfield have abundant reserves and their development potential is great, but this block is characterized by complex geological conditions, high-temperature and high-pressure target layers, complex pressure systems and poor drillability of deep strata, which bring several challenges to the drilling operation. To deal with the technical difficulties in the deep drilling operation in the southwest zone of Bozhong sag, the casing program of “non-standard borehole + reaming while drilling + non-standard casing” is adopted innovatively to ensure the isolation of setting positions in each horizon and meet the requirements of formation evaluation. A set of full-hole ROP (rate of penetration) improvement technologies are formed by optimizing the BHA (bottom hole assemblage) based on the conditions of different hole sections, so that the rock breaking efficiency is improved greatly. A high-temperature, solid-free drilling fluid system with the capacity of reservoir protection is developed, whose limit temperature tolerance is increased from 170 ℃ to 200 ℃, so as to meet the performance requirements of reservoir protection in buried hills. The precise pressure technology is developed for buried hill reservoirs to improve the ROP, which effectively alleviates the risks of lost circulation and pressure difference induced pipe sticking in buried hill reservoirs. The research results play a guiding role in ensuring the safe drilling, ROP improvement and cost reduction of deep exploration wells in the Bozhong area.
The deep oil/gas bearing structures in the southwest zone of Bozhong sag, Bohai Oilfield have abundant reserves and their development potential is great, but this block is characterized by complex geological conditions, high-temperature and high-pressure target layers, complex pressure systems and poor drillability of deep strata, which bring several challenges to the drilling operation. To deal with the technical difficulties in the deep drilling operation in the southwest zone of Bozhong sag, the casing program of “non-standard borehole + reaming while drilling + non-standard casing” is adopted innovatively to ensure the isolation of setting positions in each horizon and meet the requirements of formation evaluation. A set of full-hole ROP (rate of penetration) improvement technologies are formed by optimizing the BHA (bottom hole assemblage) based on the conditions of different hole sections, so that the rock breaking efficiency is improved greatly. A high-temperature, solid-free drilling fluid system with the capacity of reservoir protection is developed, whose limit temperature tolerance is increased from 170 ℃ to 200 ℃, so as to meet the performance requirements of reservoir protection in buried hills. The precise pressure technology is developed for buried hill reservoirs to improve the ROP, which effectively alleviates the risks of lost circulation and pressure difference induced pipe sticking in buried hill reservoirs. The research results play a guiding role in ensuring the safe drilling, ROP improvement and cost reduction of deep exploration wells in the Bozhong area.
2021, 43(2): 184-188.
doi: 10.13639/j.odpt.2021.02.008
Abstract:
In Huizhou area of eastern South China Sea, the Paleogene coal bed in the upper part undergoes sloughing easily and there are risks of well collapse after the hydration swelling of hard brittle shale, while the Pre-Paleogene volcanic rock in the lower part is characterized by high temperature, tightness, low porosity and low permeability. These stratigraphic characteristics require drilling fluid system to have good capacities of inhibition, sealing, temperature resistance and reservoir protection, but conventional drilling fluid systems cannot meet all these requirements simultaneously. Based on neighboring well data, lithological characteristics and geological requirements, the strong-sealing polymer drilling fluid system is applied in the Paleogene, which has strong shale inhibition capacity and presents good sealing capacity when the dosage of combined sealing agent is only 4%. The high-temperature solid free drilling fluid system is used in the Pre-Paleogene, which can meet the temperature requirement of 150 ℃ at the bottom hole. In addition, the recovery rate of core permeability is up to 85%, indicating its reservoir protection capacity is good. The field application indicates that applying two different drilling fluid systems in the upper and lower parts respectively solves the problems of coal bed sloughing and hard brittle shale collapse in the Paleogene and satisfies the requirements of high temperature and reservoir protection in the Pre-Paleogene, so as to ensure the safe downhole operation while guaranteeing the smooth testing operation. The research results provide the reference for the selection of drilling fluid systems in the similar strata.
In Huizhou area of eastern South China Sea, the Paleogene coal bed in the upper part undergoes sloughing easily and there are risks of well collapse after the hydration swelling of hard brittle shale, while the Pre-Paleogene volcanic rock in the lower part is characterized by high temperature, tightness, low porosity and low permeability. These stratigraphic characteristics require drilling fluid system to have good capacities of inhibition, sealing, temperature resistance and reservoir protection, but conventional drilling fluid systems cannot meet all these requirements simultaneously. Based on neighboring well data, lithological characteristics and geological requirements, the strong-sealing polymer drilling fluid system is applied in the Paleogene, which has strong shale inhibition capacity and presents good sealing capacity when the dosage of combined sealing agent is only 4%. The high-temperature solid free drilling fluid system is used in the Pre-Paleogene, which can meet the temperature requirement of 150 ℃ at the bottom hole. In addition, the recovery rate of core permeability is up to 85%, indicating its reservoir protection capacity is good. The field application indicates that applying two different drilling fluid systems in the upper and lower parts respectively solves the problems of coal bed sloughing and hard brittle shale collapse in the Paleogene and satisfies the requirements of high temperature and reservoir protection in the Pre-Paleogene, so as to ensure the safe downhole operation while guaranteeing the smooth testing operation. The research results provide the reference for the selection of drilling fluid systems in the similar strata.
2021, 43(2): 189-196.
doi: 10.13639/j.odpt.2021.02.009
Abstract:
As one of the effective unconventional well control technologies, bullheading killing can reduce and avoid surface and platform risks in the case of overflow, blowout and other accidents. At present, the researches on the calculation of bullheading process only focus on the flow inside the well, without considering the influences of reservoir properties, so they cannot meet the on-site actual demands completely. In order to research the influences of reservoirs properties on the bullheading process, the research firstly established the well gas-liquid two-phase flow model. Then, the flow laws of the killing fluid after being squeezed back into the reservoir were studied by considering the influences of mud cake, reservoir contamination belt, reservoir permeability, porosity and saturation comprehensively, and the change laws of the well pressure in the process of bullheading were analyzed. Finally, the influences of different factors on bullheading reservoir efficiency were quantitatively determined. It is indicated that well killing is influenced less by reservoir gas saturation and mud cake permeability, but more by reservoir thickness and porosity. The bullheading killing which considers the influences of different reservoir properties comprehensively can provide the technical guarantee for the safe drilling of gas wells.
As one of the effective unconventional well control technologies, bullheading killing can reduce and avoid surface and platform risks in the case of overflow, blowout and other accidents. At present, the researches on the calculation of bullheading process only focus on the flow inside the well, without considering the influences of reservoir properties, so they cannot meet the on-site actual demands completely. In order to research the influences of reservoirs properties on the bullheading process, the research firstly established the well gas-liquid two-phase flow model. Then, the flow laws of the killing fluid after being squeezed back into the reservoir were studied by considering the influences of mud cake, reservoir contamination belt, reservoir permeability, porosity and saturation comprehensively, and the change laws of the well pressure in the process of bullheading were analyzed. Finally, the influences of different factors on bullheading reservoir efficiency were quantitatively determined. It is indicated that well killing is influenced less by reservoir gas saturation and mud cake permeability, but more by reservoir thickness and porosity. The bullheading killing which considers the influences of different reservoir properties comprehensively can provide the technical guarantee for the safe drilling of gas wells.
2021, 43(2): 197-202.
doi: 10.13639/j.odpt.2021.02.010
Abstract:
To address the key problems influencing the pressure control accuracy in the process of MPD, this paper carried out original researches from bottom-level control hardware to top-level calculation model and control method. Firstly, in view that existing throttle valves can hardly realize fine back pressure control, a new concept of linear pressure drop control of axial dynamic optimization of open area was put forward, and the throttle valve whose pressure drop varies linearly with the opening in the opening range of 25%-85% was designed. Then, in view that wellbore pressure can be hardly calculated accurately and the control model is complicated, a kind of real-time model coefficient prediction method was established to realize the real-time accurate calculation of bottom hole pressure. Finally, wellbore pressure serials control was realized by means of fast back pressure control, so as to solve the difficulty in the fine wellbore pressure control. Wellbore pressure control module was developed, and the control method was verified by virtue of experiment and application, which showed that the control accuracy of bottom hole pressure is up to 0.2 MPa. The research results provide theoretical and technical support for the fine wellbore pressure control.
To address the key problems influencing the pressure control accuracy in the process of MPD, this paper carried out original researches from bottom-level control hardware to top-level calculation model and control method. Firstly, in view that existing throttle valves can hardly realize fine back pressure control, a new concept of linear pressure drop control of axial dynamic optimization of open area was put forward, and the throttle valve whose pressure drop varies linearly with the opening in the opening range of 25%-85% was designed. Then, in view that wellbore pressure can be hardly calculated accurately and the control model is complicated, a kind of real-time model coefficient prediction method was established to realize the real-time accurate calculation of bottom hole pressure. Finally, wellbore pressure serials control was realized by means of fast back pressure control, so as to solve the difficulty in the fine wellbore pressure control. Wellbore pressure control module was developed, and the control method was verified by virtue of experiment and application, which showed that the control accuracy of bottom hole pressure is up to 0.2 MPa. The research results provide theoretical and technical support for the fine wellbore pressure control.
2021, 43(2): 203-211.
doi: 10.13639/j.odpt.2021.02.011
Abstract:
Geothermal tail water reinjection is an effective measure to maintain the sustainable production of geothermal resources and prevent the problems of geological setting (e.g. surface subsidence), is of great significance to various geothermal reservoirs in production and is the key factor to the success of geothermal development. In the process of geothermal reinjection, however, some problems may be caused, such as temperature decline of the produced fluid in the production well, scaling and corrosion of reinjection well and blockage in the wellbore of reinjection well in sandstone geothermal reservoir and its surrounding geothermal reservoir, which decrease the reinjection efficiency and impact the geothermal reservoir productivity. In order to better solve the problems in the geothermal tail water reinjection, this paper firstly investigated the common reinjection technologies by taking the status of geothermal tail water injection at home and abroad as the beginning point. Then, the main problems and influence factors of tail water reinjection were analyzed and four suggestions were proposed as follows. First, strengthen the study on geothermal reservoirs to increase the matching degree between development mode and geothermal reservoir. Second, carry out reinjection design reasonably to ensure the smooth operation of the reinjection system in the long term. Third, set the dynamic monitoring system to provide the reference for the later development. Fourth, innovatively research and develop reinjection technologies to increase the volume of reinjected tail water and maximize the economic benefit. They are of important significance to decrease the difficulty of geothermal tail water reinjection, increase the utilization rate of geothermal energy and promote the sustainable development of geothermal resources.
Geothermal tail water reinjection is an effective measure to maintain the sustainable production of geothermal resources and prevent the problems of geological setting (e.g. surface subsidence), is of great significance to various geothermal reservoirs in production and is the key factor to the success of geothermal development. In the process of geothermal reinjection, however, some problems may be caused, such as temperature decline of the produced fluid in the production well, scaling and corrosion of reinjection well and blockage in the wellbore of reinjection well in sandstone geothermal reservoir and its surrounding geothermal reservoir, which decrease the reinjection efficiency and impact the geothermal reservoir productivity. In order to better solve the problems in the geothermal tail water reinjection, this paper firstly investigated the common reinjection technologies by taking the status of geothermal tail water injection at home and abroad as the beginning point. Then, the main problems and influence factors of tail water reinjection were analyzed and four suggestions were proposed as follows. First, strengthen the study on geothermal reservoirs to increase the matching degree between development mode and geothermal reservoir. Second, carry out reinjection design reasonably to ensure the smooth operation of the reinjection system in the long term. Third, set the dynamic monitoring system to provide the reference for the later development. Fourth, innovatively research and develop reinjection technologies to increase the volume of reinjected tail water and maximize the economic benefit. They are of important significance to decrease the difficulty of geothermal tail water reinjection, increase the utilization rate of geothermal energy and promote the sustainable development of geothermal resources.
2021, 43(2): 212-216.
doi: 10.13639/j.odpt.2021.02.012
Abstract:
The liquid increasing of oil well is one important measure to stabilize the production when an oilfield steps into the period of high water cut. Speaking of the conventional limit liquid production capacity study, its key point is only confined to the discrimination of energy supply capacity and limit production pressure difference, and its prediction on the limit liquid increasing capacity is mainly by means of the Darcy linear method. It is assumed that the porous medium where the fluid flows in the reservoir is rigid and the reservoir permeability is constant. Unconsolidated sandstone reservoirs of high porosity, high permeability and poor consolidation are widely distributed in the offshore oilfields of the Bohai Bay. These reservoir characteristics and liquid increasing method lead to elastic and plastic deformation, skeleton deformation and sand production of the porous medium where the fluid flows, which result in the essential transformation of the percolation conditions, so the error of the conventional limit liquid production capacity prediction method is large. After firstly dissecting the conventional limit liquid production capacity study, this paper theoretically analyzed the influence factors and change laws of porous medium. Then, combined with the oilfield production practice data, the change laws were introduced into the percolation theory to infer the liquid production capacity prediction method based on fluid-solid coupling. This prediction method is applied in Bohai C Oilfield. And compared with the actual oilfield data, the error rate of the fitting result is only 5% and the fitting rate is 40%-50% higher than that of conventional method. Therefore, this prediction method is worth popularizing.
The liquid increasing of oil well is one important measure to stabilize the production when an oilfield steps into the period of high water cut. Speaking of the conventional limit liquid production capacity study, its key point is only confined to the discrimination of energy supply capacity and limit production pressure difference, and its prediction on the limit liquid increasing capacity is mainly by means of the Darcy linear method. It is assumed that the porous medium where the fluid flows in the reservoir is rigid and the reservoir permeability is constant. Unconsolidated sandstone reservoirs of high porosity, high permeability and poor consolidation are widely distributed in the offshore oilfields of the Bohai Bay. These reservoir characteristics and liquid increasing method lead to elastic and plastic deformation, skeleton deformation and sand production of the porous medium where the fluid flows, which result in the essential transformation of the percolation conditions, so the error of the conventional limit liquid production capacity prediction method is large. After firstly dissecting the conventional limit liquid production capacity study, this paper theoretically analyzed the influence factors and change laws of porous medium. Then, combined with the oilfield production practice data, the change laws were introduced into the percolation theory to infer the liquid production capacity prediction method based on fluid-solid coupling. This prediction method is applied in Bohai C Oilfield. And compared with the actual oilfield data, the error rate of the fitting result is only 5% and the fitting rate is 40%-50% higher than that of conventional method. Therefore, this prediction method is worth popularizing.
2021, 43(2): 217-225.
doi: 10.13639/j.odpt.2021.02.013
Abstract:
Ammeter card diagnosis is one typical means to diagnose the working conditions of electrical submersible pump (ESP). The tradition pattern recognition of ammeter card needs artificial operation and has technical barriers, so subjective error can be introduced. As a kind of machine learning algorithm, artificial neural network can make up for the error of artificial recognition. In order to realize fast, accurate and objective pattern recognition, this paper established the artificial neural network model based on the corresponding relationship between the actual working condition and the current data characteristic value obtained after the data pretreatment of the collected ammeter cards. Then, this artificial neural network model was applied to working condition diagnosis. It is indicated that the artificial neural network model is absolutely more advantageous than the traditional artificial recognition of ammeter card. An artificial neural network model was established by means of above mentioned method and applied to pattern recognition. The working condition diagnosis model was verified by extracting the ammeter card data of untrained wells, which indicates higher accuracy. The research results indicate the feasibility and reliability of artificial neural network to fast pattern recognition of ammeter card and working condition diagnosis.
Ammeter card diagnosis is one typical means to diagnose the working conditions of electrical submersible pump (ESP). The tradition pattern recognition of ammeter card needs artificial operation and has technical barriers, so subjective error can be introduced. As a kind of machine learning algorithm, artificial neural network can make up for the error of artificial recognition. In order to realize fast, accurate and objective pattern recognition, this paper established the artificial neural network model based on the corresponding relationship between the actual working condition and the current data characteristic value obtained after the data pretreatment of the collected ammeter cards. Then, this artificial neural network model was applied to working condition diagnosis. It is indicated that the artificial neural network model is absolutely more advantageous than the traditional artificial recognition of ammeter card. An artificial neural network model was established by means of above mentioned method and applied to pattern recognition. The working condition diagnosis model was verified by extracting the ammeter card data of untrained wells, which indicates higher accuracy. The research results indicate the feasibility and reliability of artificial neural network to fast pattern recognition of ammeter card and working condition diagnosis.
2021, 43(2): 226-232.
doi: 10.13639/j.odpt.2021.02.014
Abstract:
The Mishrif oil reservoir in Halfaya Oilfield of the Middle East is a monoblock anticlinal oil reservoir of strong heterogeneity, and its stimulation scale is limited due to the influence of bottom water when the acid fracturing pilot is carried out at the edge of the structure. The reservoir rocks are lithologically pure, which is not beneficial to the nonuniform acid etching in the process of acid fracturing. The Young’s modulus is low and the shielding capacity of stress barriers is poorer, which are not beneficial to the extension of fracture length and the control of fracture height. The crude oil is emulsified seriously after the acid/rock reaction, which is not beneficial to the flow back. Numerical simulation and experimental results show that the adoption of acid fracturing technology of multi-stage alternating injection and the optimization of injection technological parameters base on reservoir characteristic can increase the operating distance of acid/rock reaction and realize nonuniform acid etching; the support technology of fiber for temporary plugging and fluid loss control and mutual solvent for emulsion breaking and flow back promotion address the problems of great fluid loss in the process of fracturing and difficult flow back after the fracturing; and the closed acidizing in the last stage enhances the flow conductivity near the well. The “crosslinked fracturing fluid+gel acid” system is selected, which slows down the acid/rock reaction velocity effectively. Its application effect in Well MF3 is excellent. The length of the effective etched fractures is up to 80 m and the tested oil production rate of single well is 317 t/d, which indicates remarkable reservoir stimulation effect. The research results provide the effective engineering technology and method for the production of similar reservoirs in the Middle East.
The Mishrif oil reservoir in Halfaya Oilfield of the Middle East is a monoblock anticlinal oil reservoir of strong heterogeneity, and its stimulation scale is limited due to the influence of bottom water when the acid fracturing pilot is carried out at the edge of the structure. The reservoir rocks are lithologically pure, which is not beneficial to the nonuniform acid etching in the process of acid fracturing. The Young’s modulus is low and the shielding capacity of stress barriers is poorer, which are not beneficial to the extension of fracture length and the control of fracture height. The crude oil is emulsified seriously after the acid/rock reaction, which is not beneficial to the flow back. Numerical simulation and experimental results show that the adoption of acid fracturing technology of multi-stage alternating injection and the optimization of injection technological parameters base on reservoir characteristic can increase the operating distance of acid/rock reaction and realize nonuniform acid etching; the support technology of fiber for temporary plugging and fluid loss control and mutual solvent for emulsion breaking and flow back promotion address the problems of great fluid loss in the process of fracturing and difficult flow back after the fracturing; and the closed acidizing in the last stage enhances the flow conductivity near the well. The “crosslinked fracturing fluid+gel acid” system is selected, which slows down the acid/rock reaction velocity effectively. Its application effect in Well MF3 is excellent. The length of the effective etched fractures is up to 80 m and the tested oil production rate of single well is 317 t/d, which indicates remarkable reservoir stimulation effect. The research results provide the effective engineering technology and method for the production of similar reservoirs in the Middle East.
2021, 43(2): 233-238.
doi: 10.13639/j.odpt.2021.02.015
Abstract:
The temporary plugging and diversion fracturing of carbonate reservoirs in Tahe Oilfield is successful, but the displacement parameters in the process of construction have no support of calculation data, which is not beneficial to the popularization and application of temporary plugging and diversion multiple fracturing. The optimization design model of the displacement of temporary plugging and diversion fracturing was established by means of the numerical iterative process based on the fracture geometry model. Then, the optimal displacements in the temporary plugging stage and the fracturing stage of carbonate reservoir were determined. Finally, the construction method of temporary plugging and diversion was developed, i.e., injecting temporary plugging agent at low displacement to plug the tip and injecting fracturing fluid at high displacement to realize diversion. It is indicated that the displacement shall meet the need of diversion pressure and fracture length simultaneously. In addition, as the time goes, the fracture propagation length contributed by the displacement cannot meet the needed fracture length of temporary plugging agent. Temporary plugging agent cannot exert diversion effect no matter how much it is. The displacement optimization under the field conditions by the optimization design model shows that the displacement shall be controlled lower than 3.0 m3/min in the stage of temporary plugging and higher than 6.0 m3/min in the stage of fracturing, which is the most suitable for diversion fracturing. The research results provide theoretical support the field application.
The temporary plugging and diversion fracturing of carbonate reservoirs in Tahe Oilfield is successful, but the displacement parameters in the process of construction have no support of calculation data, which is not beneficial to the popularization and application of temporary plugging and diversion multiple fracturing. The optimization design model of the displacement of temporary plugging and diversion fracturing was established by means of the numerical iterative process based on the fracture geometry model. Then, the optimal displacements in the temporary plugging stage and the fracturing stage of carbonate reservoir were determined. Finally, the construction method of temporary plugging and diversion was developed, i.e., injecting temporary plugging agent at low displacement to plug the tip and injecting fracturing fluid at high displacement to realize diversion. It is indicated that the displacement shall meet the need of diversion pressure and fracture length simultaneously. In addition, as the time goes, the fracture propagation length contributed by the displacement cannot meet the needed fracture length of temporary plugging agent. Temporary plugging agent cannot exert diversion effect no matter how much it is. The displacement optimization under the field conditions by the optimization design model shows that the displacement shall be controlled lower than 3.0 m3/min in the stage of temporary plugging and higher than 6.0 m3/min in the stage of fracturing, which is the most suitable for diversion fracturing. The research results provide theoretical support the field application.
2021, 43(2): 239-243.
doi: 10.13639/j.odpt.2021.02.016
Abstract:
The multi-packer separate layer fracturing operation in the deep, high temperature, high pressure, low porosity and low permeability gas reservoirs of Kuqa piedmont area tends to suffer packer failure, steel ball blocking pipe string and incomplete fluid displacement at the lower part of perforation interval, which are the key problems impacting the success of reservoir stimulation operation. In order to solve these problems, the completion string was installed with a slip joint to extend to the bottom boundary of the perforation interval. A kind of high-strength dissoluble ball of aluminum alloy was developed, which takes the composite organosilicon resin coat with the transitional layer of melamine as the special protection film, has pressure bearing strength more than 69 MPa and dissolves slowly first and then fast. In addition, a kind of full-bore fracturing valve was developed, which adopts ratchet-type structure and dropping-to-pressurizing mode. When the side hole is opened by the sliding sleeve, the hole is enlarged to run the ball through it to the bottom of the string, so that the full bore can be kept consistent with the lower packer. Thus, the multi-packer separate layer fracturing technology suitable for deep, high temperature, high pressure deep gas wells was formed. It has been applied on site 14 well times, and no packer failure, string blocking or incomplete fluid displacement occurs during the fracturing. The analysis indicates that slip joints can alleviate the axial force generated by temperature effect and inner-outer pipe pressure difference; dissoluble balls avoid the occurrence of retention blockage while meeting the requirements of fracturing operation; extension string, combined with full-bore fracturing valve provides the channels for the effective injection of fracturing fluid and displacement fluid in the perforation intervals, so as to solve the settling blockage of drilling fluid in perforation intervals and the deposition of proppant at the bottom hole. In conclusion, the multi-packer separate layer fracturing technology can provide reliable technological support for the reservoir fracturing stimulation of deep, high temperature and high pressure gas wells.
The multi-packer separate layer fracturing operation in the deep, high temperature, high pressure, low porosity and low permeability gas reservoirs of Kuqa piedmont area tends to suffer packer failure, steel ball blocking pipe string and incomplete fluid displacement at the lower part of perforation interval, which are the key problems impacting the success of reservoir stimulation operation. In order to solve these problems, the completion string was installed with a slip joint to extend to the bottom boundary of the perforation interval. A kind of high-strength dissoluble ball of aluminum alloy was developed, which takes the composite organosilicon resin coat with the transitional layer of melamine as the special protection film, has pressure bearing strength more than 69 MPa and dissolves slowly first and then fast. In addition, a kind of full-bore fracturing valve was developed, which adopts ratchet-type structure and dropping-to-pressurizing mode. When the side hole is opened by the sliding sleeve, the hole is enlarged to run the ball through it to the bottom of the string, so that the full bore can be kept consistent with the lower packer. Thus, the multi-packer separate layer fracturing technology suitable for deep, high temperature, high pressure deep gas wells was formed. It has been applied on site 14 well times, and no packer failure, string blocking or incomplete fluid displacement occurs during the fracturing. The analysis indicates that slip joints can alleviate the axial force generated by temperature effect and inner-outer pipe pressure difference; dissoluble balls avoid the occurrence of retention blockage while meeting the requirements of fracturing operation; extension string, combined with full-bore fracturing valve provides the channels for the effective injection of fracturing fluid and displacement fluid in the perforation intervals, so as to solve the settling blockage of drilling fluid in perforation intervals and the deposition of proppant at the bottom hole. In conclusion, the multi-packer separate layer fracturing technology can provide reliable technological support for the reservoir fracturing stimulation of deep, high temperature and high pressure gas wells.
2021, 43(2): 244-249.
doi: 10.13639/j.odpt.2021.02.017
Abstract:
Extra-super heavy oil reservoirs are generally developed by means of steam assisted gravity drainage (SAGD). In the early water injection stage, reservoir’s shear dilation generates shear fractures in the shear zone, which leads to the change of porosity and water/oil saturation. In order to study the dynamic evolution laws of the effective permeability in the process of water injection, this paper related absolute permeability with porosity through Kozeny-Poiseuille equation and Touhidi-Baghini equation and water effective permeability with water saturation through oil and water relative permeability curve equations, in view that porosity and water saturation vary with dilation volumetric strain. Then, three mathematical models of shear dilation induced permeability evolution were established. In addition, the prediction effects of each model were evaluated and analyzed based on experimental data. It is indicated that the traditional Kozeny-Carman equation is only applicable to porous granular media, but not to Karamay continental oil sand, which is the composite skeleton composed of bitumen basement type cementation, and neither to describe the permeability evolution induced by the shear fractures in the shear dilation zone. What’s more, the shear dilation induced permeability model established on the basis of Touhidi-Baghini equation can accurately predict the evolution laws of water effective permeability in the process of water injection, so as to provide reference and experience for the studies related to permeability.
Extra-super heavy oil reservoirs are generally developed by means of steam assisted gravity drainage (SAGD). In the early water injection stage, reservoir’s shear dilation generates shear fractures in the shear zone, which leads to the change of porosity and water/oil saturation. In order to study the dynamic evolution laws of the effective permeability in the process of water injection, this paper related absolute permeability with porosity through Kozeny-Poiseuille equation and Touhidi-Baghini equation and water effective permeability with water saturation through oil and water relative permeability curve equations, in view that porosity and water saturation vary with dilation volumetric strain. Then, three mathematical models of shear dilation induced permeability evolution were established. In addition, the prediction effects of each model were evaluated and analyzed based on experimental data. It is indicated that the traditional Kozeny-Carman equation is only applicable to porous granular media, but not to Karamay continental oil sand, which is the composite skeleton composed of bitumen basement type cementation, and neither to describe the permeability evolution induced by the shear fractures in the shear dilation zone. What’s more, the shear dilation induced permeability model established on the basis of Touhidi-Baghini equation can accurately predict the evolution laws of water effective permeability in the process of water injection, so as to provide reference and experience for the studies related to permeability.
2021, 43(2): 250-253.
doi: 10.13639/j.odpt.2021.02.018
Abstract:
Compared with the separate-layer allocation of traditional wireline fishing, the wireless intelligent water regulator greatly improves the separate-layer injection allocation efficiency of offshore large-displacement water injectors. In this industry, however, there is no related selection standard on the nozzle opening of offshore large-displacement wireless intelligent water regulator, so during the field allocation, the nozzle opening can be only selected tentatively according to existing experience. Therefore, there is still some improvement space for the existing separate-layer testing and allocation efficiency. To this end, the pressure loss at water nozzle generated at 15 openings of wireless intelligent water regulator and different flow rates (0-500 m3/d) was simulated by using FLUENT software. As a result, 137 groups of nozzle opening, flow rate and pressure loss data were formed. Then, the simulation data was applied to the allocation operation in 11 water injection intervals of 3 water injectors in Bohai Oilfield. It is shown that the qualification rate of the injection allocation is over 90% while the selection of nozzle opening for 11 water injection intervals is completed in one time, and the single-layer testing and allocation efficiency is 1/2-2/3 higher than that of empirical method, so it can be used to guide the testing and allocation of offshore large-displacement water injectors.
Compared with the separate-layer allocation of traditional wireline fishing, the wireless intelligent water regulator greatly improves the separate-layer injection allocation efficiency of offshore large-displacement water injectors. In this industry, however, there is no related selection standard on the nozzle opening of offshore large-displacement wireless intelligent water regulator, so during the field allocation, the nozzle opening can be only selected tentatively according to existing experience. Therefore, there is still some improvement space for the existing separate-layer testing and allocation efficiency. To this end, the pressure loss at water nozzle generated at 15 openings of wireless intelligent water regulator and different flow rates (0-500 m3/d) was simulated by using FLUENT software. As a result, 137 groups of nozzle opening, flow rate and pressure loss data were formed. Then, the simulation data was applied to the allocation operation in 11 water injection intervals of 3 water injectors in Bohai Oilfield. It is shown that the qualification rate of the injection allocation is over 90% while the selection of nozzle opening for 11 water injection intervals is completed in one time, and the single-layer testing and allocation efficiency is 1/2-2/3 higher than that of empirical method, so it can be used to guide the testing and allocation of offshore large-displacement water injectors.
2021, 43(2): 254-258.
doi: 10.13639/j.odpt.2021.02.019
Abstract:
During the SAGD development of Fengcheng super heavy oil reservoir, the producing degree of horizontal section is low and the expansion of steam chamber is not uniform. To solve these problems, this paper obtained the semi-log curve slope of the temperature coefficient (T*) of horizontal production well by means of heat transfer theory and formula derivation, which is the exponential relation between temperature drop coefficient (m) and steam chamber volume. Then, through the numerical simulation fitting of a1 well group in Fengcheng A Well Block, the temperature drop coefficient (m) of each temperature monitoring point was calculated, and the exponential relation expression between temperature drop coefficient (m) and its corresponding steam chamber volume was regressed. Finally, the applicability of this expression was verified by using the measurement data of the neighboring well. It is indicated that the numerical simulation result is basically accordant with the calculation result based on the measurement data of the neighboring well, which proves the stronger applicability of this expression. In practice, this expression can be used directly to describe the shape of steam chamber, so as to provide the guidance for the rapid quantitative description of SAGD steam chamber.
During the SAGD development of Fengcheng super heavy oil reservoir, the producing degree of horizontal section is low and the expansion of steam chamber is not uniform. To solve these problems, this paper obtained the semi-log curve slope of the temperature coefficient (T*) of horizontal production well by means of heat transfer theory and formula derivation, which is the exponential relation between temperature drop coefficient (m) and steam chamber volume. Then, through the numerical simulation fitting of a1 well group in Fengcheng A Well Block, the temperature drop coefficient (m) of each temperature monitoring point was calculated, and the exponential relation expression between temperature drop coefficient (m) and its corresponding steam chamber volume was regressed. Finally, the applicability of this expression was verified by using the measurement data of the neighboring well. It is indicated that the numerical simulation result is basically accordant with the calculation result based on the measurement data of the neighboring well, which proves the stronger applicability of this expression. In practice, this expression can be used directly to describe the shape of steam chamber, so as to provide the guidance for the rapid quantitative description of SAGD steam chamber.
2021, 43(2): 259-264.
doi: 10.13639/j.odpt.2021.02.020
Abstract:
In this paper, the foam+resin based sand consolidation system was developed to deal with the serious fine siltstone production of the oil production wells in the low-temperature thin oil reservoirs of Chunguang Oilfield. In the experiment, the modified melamine formaldehyde resin was used as the raw material, the mass fractions of solidifying agent, foaming agent, foam stabilizer and other compositions were determined by taking compression strength and permeability as the indicators, the influences of gas/liquid volume ratio and reaming mode on the consolidation performance were investigated, and thus the foam+resin based sand consolidation system was developed. In addition, the solid consolidation depth was determined by means of back scour experiment. It is experimentally indicated that the foam+resin based sand consolidation system which takes N2 as the gas phase, SDS as the foaming agent, CMC as the foam stabilizer and mixed acid salt and organic acid as the solidifying agent is characterized by low density, high strength and high permeability. At the temperature of 25 ℃, the consolidation body has density of 0.54-0.62 g/cm3, compression strength of 6.12 MPa and permeability of 1.76 μm2. By December 2020, the foam+resin based sand consolidation technology had been tested on site 27 well times in Chunguang Oilfield and the pump detection period is extended from 35 d to 112 d, indicating good sand control effects.
In this paper, the foam+resin based sand consolidation system was developed to deal with the serious fine siltstone production of the oil production wells in the low-temperature thin oil reservoirs of Chunguang Oilfield. In the experiment, the modified melamine formaldehyde resin was used as the raw material, the mass fractions of solidifying agent, foaming agent, foam stabilizer and other compositions were determined by taking compression strength and permeability as the indicators, the influences of gas/liquid volume ratio and reaming mode on the consolidation performance were investigated, and thus the foam+resin based sand consolidation system was developed. In addition, the solid consolidation depth was determined by means of back scour experiment. It is experimentally indicated that the foam+resin based sand consolidation system which takes N2 as the gas phase, SDS as the foaming agent, CMC as the foam stabilizer and mixed acid salt and organic acid as the solidifying agent is characterized by low density, high strength and high permeability. At the temperature of 25 ℃, the consolidation body has density of 0.54-0.62 g/cm3, compression strength of 6.12 MPa and permeability of 1.76 μm2. By December 2020, the foam+resin based sand consolidation technology had been tested on site 27 well times in Chunguang Oilfield and the pump detection period is extended from 35 d to 112 d, indicating good sand control effects.
2014, 36(1): 1-5.
2015, 37(4): 105-112.
doi: 10.13639/j.odpt.2015.04.027
2015, 37(4): 58-62.
doi: 10.13639/j.odpt.2015.04.016
2015, 37(1): 13-18.
doi: 10.13639/j.odpt.2015.01.004
2016, 38(3): 277-285.
doi: 10.13639/j.odpt.2016.03.001
2014, 36(2): 82-87.
doi: 10.13639/j.odpt.2014.02.021
2014, 36(5): 1-4.
doi: 10.13639/j.odpt.2014.05.001
2017, 39(1): 112-118.
doi: 10.13639/j.odpt.2017.01.022
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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