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Abstract:
To improve the low milling rate and rapid wearing of conventional milling shoes, the cutting mechanism, structure, materials, and operating parameters of milling tools were investigated, and a novel high-efficiency milling tool was designed. The results showed that the cutter design with cutting angles of 5°−10° and a dip angle of 5° delivers the optimal cutting performance; the application with imported alloy materials is associated with the least wear rate; the milling efficiency is the highest, with alloy materials designed as multiple rhombi. Moreover, based on the downhole complex issues, three mill shoe structures were proposed, namely the flat, concave and pilot mill shoes. The field testing confirmed that the application of high-efficiency milling tools improves the average milling efficiency by 40% and the invention has the potential for application promotion.
To improve the low milling rate and rapid wearing of conventional milling shoes, the cutting mechanism, structure, materials, and operating parameters of milling tools were investigated, and a novel high-efficiency milling tool was designed. The results showed that the cutter design with cutting angles of 5°−10° and a dip angle of 5° delivers the optimal cutting performance; the application with imported alloy materials is associated with the least wear rate; the milling efficiency is the highest, with alloy materials designed as multiple rhombi. Moreover, based on the downhole complex issues, three mill shoe structures were proposed, namely the flat, concave and pilot mill shoes. The field testing confirmed that the application of high-efficiency milling tools improves the average milling efficiency by 40% and the invention has the potential for application promotion.
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doi: 10.13639/j.odpt.2022.03.019
Abstract:
The macro management chart on the working condition of water injection wells is an important map that reflects the working condition of water injection wells. The construction of digital oil field provides massive data for the dynamic monitoring of water injection wells. Based on the massive data samples from water injection wells, by using the K-means clustering algorithm, macro working conditions of water injection wells, that is, the macro management chart composed the area to be reformed, the under-injection area, the normal injection area, the over-injection area, and the pending area was established. The regional boundary line was determined by using the support vector machine (SVM), and a control chart model on working condition management of injection wells was established. Using this model, the drawing method and application process of block macro management chart and single well dynamic management chart were formed. The field application shows that the macro control chart model constructed based on the big data method can reflect the relationship between the production dynamic characteristics, water injection intensity, water absorption capacity and injection completion rate of the research block and single well, which provides a decision-making basis for the next implementation of measures on water injection wells.
The macro management chart on the working condition of water injection wells is an important map that reflects the working condition of water injection wells. The construction of digital oil field provides massive data for the dynamic monitoring of water injection wells. Based on the massive data samples from water injection wells, by using the K-means clustering algorithm, macro working conditions of water injection wells, that is, the macro management chart composed the area to be reformed, the under-injection area, the normal injection area, the over-injection area, and the pending area was established. The regional boundary line was determined by using the support vector machine (SVM), and a control chart model on working condition management of injection wells was established. Using this model, the drawing method and application process of block macro management chart and single well dynamic management chart were formed. The field application shows that the macro control chart model constructed based on the big data method can reflect the relationship between the production dynamic characteristics, water injection intensity, water absorption capacity and injection completion rate of the research block and single well, which provides a decision-making basis for the next implementation of measures on water injection wells.
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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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2022, 44(6): 665-670.
doi: 10.13639/j.odpt.2022.06.001
Abstract:
The IV belt of the Shunbei oilfield is located in a slipping fault zone. Its reservoirs mostly of the Ordovician carbonate rocks are mainly recovered using horizontal/direction wells. The average vertical depth is nearly 8 000 m, with a maximum formation temperature of 174 °C, The ultra-high depth, high temperature and complex geology lead to technical challenges for directional drilling in this area, such as high difficulties in well trajectory control, high failure rates of devices and low timeliness to handle gas invasion. Under this background, the casing program was optimized to reduce difficulties in directional drilling, and the proportion of composite drilling was on average increased by 10%. The efficiency of well trajectory control was greatly improved, with a target hit rate of 100%, by optimizing the BHA and drilling parameters and applying the tool-face stable adjustment and control technology and seismic-assisted guiding-while-drilling technology. Based on the investigation of the well temperature field distribution, the MWD technology was improved, and the tool failure rate dropped from 23% to 9.3%. With the simplified MPD technology, the handling efficiency for the gas invasion was enhanced. The presented directional drilling technology was applied to 12 wells in the field. Compared with the drilling engineering design, the directional drilling duration of the reservoir is on average reduced by 14.3%, and the average rate of penetration is increased by 32.1%, compared with that of the adjacent block. Applications of the presented directional drilling technology should be further promoted.
The IV belt of the Shunbei oilfield is located in a slipping fault zone. Its reservoirs mostly of the Ordovician carbonate rocks are mainly recovered using horizontal/direction wells. The average vertical depth is nearly 8 000 m, with a maximum formation temperature of 174 °C, The ultra-high depth, high temperature and complex geology lead to technical challenges for directional drilling in this area, such as high difficulties in well trajectory control, high failure rates of devices and low timeliness to handle gas invasion. Under this background, the casing program was optimized to reduce difficulties in directional drilling, and the proportion of composite drilling was on average increased by 10%. The efficiency of well trajectory control was greatly improved, with a target hit rate of 100%, by optimizing the BHA and drilling parameters and applying the tool-face stable adjustment and control technology and seismic-assisted guiding-while-drilling technology. Based on the investigation of the well temperature field distribution, the MWD technology was improved, and the tool failure rate dropped from 23% to 9.3%. With the simplified MPD technology, the handling efficiency for the gas invasion was enhanced. The presented directional drilling technology was applied to 12 wells in the field. Compared with the drilling engineering design, the directional drilling duration of the reservoir is on average reduced by 14.3%, and the average rate of penetration is increased by 32.1%, compared with that of the adjacent block. Applications of the presented directional drilling technology should be further promoted.
2022, 44(6): 671-677.
doi: 10.13639/j.odpt.2022.06.002
Abstract:
For the purposes of protecting the ecological environment and increasing single-well production, the Changqing gas field deploys multiple wells with horizontal wells exceeding 3000 m. Given the ultra-long horizontal openhole well and the excessive drag and torque, the S135-steel grade drill string and the cutting-removal drillpipe drag reduction tool were adopted; the rotary steerable system was used for trajectory control; the drilling parameters were optimized. Specifically, the optimal annular circulation rate of drilling fluids is 1.20–1.30 m/s; the minimum drill string rotation speed is 60 r/min; the potassium chlorite, limestone and high-performance lubricant are used to improve the lubricant performance of drilling fluids and formed mud cake, control the content of unwanted solids in drilling fluids, and raise the ratio of yield point to plastic viscosity to 0.5Pa/(mPa · s). The above measures jointly form the drag reduction technology for ultra-long horizontal wells in the Changqing tight gas field. It has been applied to Well Jing 51-X with a 5256 m long horizontal well. The average dogleg severity of the horizontal well was 0.74 (°)/30 m; the maximum solid content of drilling fluids was 16%; the maximum drag of tripping out after completion of drilling is 380 kN; the maximum drag of tripping in was 280 kN. Such an application to ultra-long horizontal drilling demonstrates the excellent drag reduction performance of the presented technology.
For the purposes of protecting the ecological environment and increasing single-well production, the Changqing gas field deploys multiple wells with horizontal wells exceeding 3000 m. Given the ultra-long horizontal openhole well and the excessive drag and torque, the S135-steel grade drill string and the cutting-removal drillpipe drag reduction tool were adopted; the rotary steerable system was used for trajectory control; the drilling parameters were optimized. Specifically, the optimal annular circulation rate of drilling fluids is 1.20–1.30 m/s; the minimum drill string rotation speed is 60 r/min; the potassium chlorite, limestone and high-performance lubricant are used to improve the lubricant performance of drilling fluids and formed mud cake, control the content of unwanted solids in drilling fluids, and raise the ratio of yield point to plastic viscosity to 0.5Pa/(mPa · s). The above measures jointly form the drag reduction technology for ultra-long horizontal wells in the Changqing tight gas field. It has been applied to Well Jing 51-X with a 5256 m long horizontal well. The average dogleg severity of the horizontal well was 0.74 (°)/30 m; the maximum solid content of drilling fluids was 16%; the maximum drag of tripping out after completion of drilling is 380 kN; the maximum drag of tripping in was 280 kN. Such an application to ultra-long horizontal drilling demonstrates the excellent drag reduction performance of the presented technology.
2022, 44(6): 678-683.
doi: 10.13639/j.odpt.2022.06.003
Abstract:
Well Yitan-1 is placed in the western margin thrust belt of the Ordos Basin. Due to the high dip angle of strata, well-developed fractures of the Liujiagou and Shiqianfeng Formations and complex geologic structure, the well inclination prevention, leakoff prevention and plugging, and wellbore instability are the main technical challenges of the well construction operation. Given the excessive dogleg severity of the upper strata, fault-related in-situ stress anomaly, inferior wellbore stability, and low pressure-bearing capacity of strata in Well Yitan-1, the BHA optimization was performed, and the casing anti-abrasion technology, high-performance drilling fluid, and flexible cement borehole wall protection were applied. These implemented measures solved the technical difficulties during drilling, such as bit sticking, frequent tool breaking, and wellbore instability and ensured the safety and operation smoothness of drilling. The drilling practice and obtained understanding effectively promote the advancement of safe high-efficiency drilling of risk exploration wells in complex geological structures.
Well Yitan-1 is placed in the western margin thrust belt of the Ordos Basin. Due to the high dip angle of strata, well-developed fractures of the Liujiagou and Shiqianfeng Formations and complex geologic structure, the well inclination prevention, leakoff prevention and plugging, and wellbore instability are the main technical challenges of the well construction operation. Given the excessive dogleg severity of the upper strata, fault-related in-situ stress anomaly, inferior wellbore stability, and low pressure-bearing capacity of strata in Well Yitan-1, the BHA optimization was performed, and the casing anti-abrasion technology, high-performance drilling fluid, and flexible cement borehole wall protection were applied. These implemented measures solved the technical difficulties during drilling, such as bit sticking, frequent tool breaking, and wellbore instability and ensured the safety and operation smoothness of drilling. The drilling practice and obtained understanding effectively promote the advancement of safe high-efficiency drilling of risk exploration wells in complex geological structures.
2022, 44(6): 684-692.
doi: 10.13639/j.odpt.2022.06.004
Abstract:
The severe leakoff in the Palaeogene composite salt layer of the Kuqa piedmont zone, the Tarim Basin, brings about tremendous challenges to drilling safety. The geological and geomechanical characteristics of key thief zones of the Kuqa piedmont composite salt layers were investigated. Moreover, in accordance with drilling operation parameters, the leak-off types were identified, the leakoff-prone lithologic association and leakoff pressure were analyzed, and the leakoff prevention method was developed. The research showed that the gypsum-salt rock with interbeds of salt-bearing and gypsum-bearing mudstone, and gypseous mudstone with interbeds of mudstone and limy mudstone are the main leakoff lithologic associations. The macro- and micro- scale analyses indicated no material basis for direct leakoff-natural fractures are underdeveloped, and the measured porosity and permeability are low. The tensile strengths of gypsum-bearing and salt-bearing mudstone are 0.61−1.12 MPa, averaging 0.946 MPa, and such layers are prone to fracturing via pressurization. The average leakoff rate of drilling fluids is less than 20 m3/h and represents minor-small leakoff, which can be effectively mitigated by reducing pump rates and mud density. The analysis of geology, geomechanics and engineering characteristics of inter-salt thief zones demonstrated that the leakoff of composite salt layers is attributed to induced fracturing, and the leakoff pressure is equal to the formation fracturing pressure (close to the minimum horizontal principal stress), which is validated via the comparison between the simulated stress field and the leakoff points during drilling. Given the above-mentioned, the key to preventing leakoff of composite salt layers is to clarify the leakoff-prone lithologic association of gypsum-salt rocks and calculate the minimum horizontal principal stress from the viscoelastic three-dimensional geomechanical model of composite salt layers. The findings of this research are of great significance for reducing inter-salt leakoff.
The severe leakoff in the Palaeogene composite salt layer of the Kuqa piedmont zone, the Tarim Basin, brings about tremendous challenges to drilling safety. The geological and geomechanical characteristics of key thief zones of the Kuqa piedmont composite salt layers were investigated. Moreover, in accordance with drilling operation parameters, the leak-off types were identified, the leakoff-prone lithologic association and leakoff pressure were analyzed, and the leakoff prevention method was developed. The research showed that the gypsum-salt rock with interbeds of salt-bearing and gypsum-bearing mudstone, and gypseous mudstone with interbeds of mudstone and limy mudstone are the main leakoff lithologic associations. The macro- and micro- scale analyses indicated no material basis for direct leakoff-natural fractures are underdeveloped, and the measured porosity and permeability are low. The tensile strengths of gypsum-bearing and salt-bearing mudstone are 0.61−1.12 MPa, averaging 0.946 MPa, and such layers are prone to fracturing via pressurization. The average leakoff rate of drilling fluids is less than 20 m3/h and represents minor-small leakoff, which can be effectively mitigated by reducing pump rates and mud density. The analysis of geology, geomechanics and engineering characteristics of inter-salt thief zones demonstrated that the leakoff of composite salt layers is attributed to induced fracturing, and the leakoff pressure is equal to the formation fracturing pressure (close to the minimum horizontal principal stress), which is validated via the comparison between the simulated stress field and the leakoff points during drilling. Given the above-mentioned, the key to preventing leakoff of composite salt layers is to clarify the leakoff-prone lithologic association of gypsum-salt rocks and calculate the minimum horizontal principal stress from the viscoelastic three-dimensional geomechanical model of composite salt layers. The findings of this research are of great significance for reducing inter-salt leakoff.
2022, 44(6): 693-700.
doi: 10.13639/j.odpt.2022.06.005
Abstract:
Long-term soaking in drilling fluids has vital effects on shale with well-developed bedding and subsequently wellbore stability in shale. The uni- and tri- axial compression tests were performed using the Longmaxi Formation shale samples from South Sichuan that have been immersed in different drilling fluids, to investigate the variation of mechanical characteristics and failure modes and also the mechanisms of wellbore instability. The results showed that due to the bedding development, the shale presents considerable mechanical anisotropy and dependency on confining pressure. The lubrication effect of oil-based drilling fluids on bedding planes strengthens the anisotropy, shale is found with the shear failure along bedding planes, and the failure mode is controlled by bedding planes. In the case of water-based drilling fluids, hydration damage is caused to shale, and the anisotropy is reduced due to the propagation and bedding connection of micro fractures. The failure is often composite, and the failure mode is controlled jointly by the matrix and bedding plane, which leads to high proneness to wellbore instability. The root causes of wellbore instability are hydration of clay minerals and capillary effects of pores and fractures. The findings of this research provide references for wellbore stability analysis of shale with well-developed bedding.
Long-term soaking in drilling fluids has vital effects on shale with well-developed bedding and subsequently wellbore stability in shale. The uni- and tri- axial compression tests were performed using the Longmaxi Formation shale samples from South Sichuan that have been immersed in different drilling fluids, to investigate the variation of mechanical characteristics and failure modes and also the mechanisms of wellbore instability. The results showed that due to the bedding development, the shale presents considerable mechanical anisotropy and dependency on confining pressure. The lubrication effect of oil-based drilling fluids on bedding planes strengthens the anisotropy, shale is found with the shear failure along bedding planes, and the failure mode is controlled by bedding planes. In the case of water-based drilling fluids, hydration damage is caused to shale, and the anisotropy is reduced due to the propagation and bedding connection of micro fractures. The failure is often composite, and the failure mode is controlled jointly by the matrix and bedding plane, which leads to high proneness to wellbore instability. The root causes of wellbore instability are hydration of clay minerals and capillary effects of pores and fractures. The findings of this research provide references for wellbore stability analysis of shale with well-developed bedding.
2022, 44(6): 701-705.
doi: 10.13639/j.odpt.2022.06.006
Abstract:
After years of production, part of oil reservoirs in the mature oilfield has entered the ultra-high water cut development stage. The remaining oil occurrence is highly dispersed, and it is hard to maintain stable production. Meanwhile, multiple re-perforating and plugging-perforating operations have been performed in oil wells along the vertical profile of oil layers, which results in complex wellbore conditions and failure to meet the requirements of well treatment. This severely impacts the reconstruction performance of well patterns. To improve wellbore conditions and meet the treatment requirements of gradually producing layers from bottom to top, such as CO2 synergistic cyclic injection and the combination of profile control, plugging, and cyclic injection, the field testing of small casing secondary well completion in directional wells was performed. To overcome the difficulties in casing running and ensuring cementing quality, the directional well small casing secondary well completion technical series was formed, which consists of high-efficiency channel milling, hydraulic rolling casing swage, and small casing cementing techniques. The presented technique series delivers the wellbore reconstruction, characterized by the long-interval sealing of complex wells, resistance to CO2 corrosion, and high pressure-bearing capacity, and provides technical support for well pattern improvement and increasing recoverable reserves in mature oilfields.
After years of production, part of oil reservoirs in the mature oilfield has entered the ultra-high water cut development stage. The remaining oil occurrence is highly dispersed, and it is hard to maintain stable production. Meanwhile, multiple re-perforating and plugging-perforating operations have been performed in oil wells along the vertical profile of oil layers, which results in complex wellbore conditions and failure to meet the requirements of well treatment. This severely impacts the reconstruction performance of well patterns. To improve wellbore conditions and meet the treatment requirements of gradually producing layers from bottom to top, such as CO2 synergistic cyclic injection and the combination of profile control, plugging, and cyclic injection, the field testing of small casing secondary well completion in directional wells was performed. To overcome the difficulties in casing running and ensuring cementing quality, the directional well small casing secondary well completion technical series was formed, which consists of high-efficiency channel milling, hydraulic rolling casing swage, and small casing cementing techniques. The presented technique series delivers the wellbore reconstruction, characterized by the long-interval sealing of complex wells, resistance to CO2 corrosion, and high pressure-bearing capacity, and provides technical support for well pattern improvement and increasing recoverable reserves in mature oilfields.
2022, 44(6): 706-710.
doi: 10.13639/j.odpt.2022.06.007
Abstract:
It is required to unload the closing and opening chambers of blowout preventers before repairing or replacing the rams and rubber seals of blowout preventers. The conventional three-position four-way rotary valve suffers from complex operation, waste of pressure, wear of valves and the disadvantage that all controlled components cannot be remotely operated after pressure relief of pipes. Given this, the four-position four-way rotary valve was developed. An extra oil unloading path was designed for the valve body and element, respectively to change the original valve into a four-position four-way rotary valve capable of automated pressure relief. In practice, it is required to only switch the valve handle to the unloading position to separately depressurize the repair target while maintaining the pressure in the rest pipes. All the other controlled components, except for those to be repaired, are under remote hydraulic control. The invention simplifies operations of repairing and replacing blowout preventer rams and rubber seals, reduces their energy consumption and improves their efficiency. The presented design also decreases the wear of valves attributed to repeated switching and greatly enhances operational efficiency.
It is required to unload the closing and opening chambers of blowout preventers before repairing or replacing the rams and rubber seals of blowout preventers. The conventional three-position four-way rotary valve suffers from complex operation, waste of pressure, wear of valves and the disadvantage that all controlled components cannot be remotely operated after pressure relief of pipes. Given this, the four-position four-way rotary valve was developed. An extra oil unloading path was designed for the valve body and element, respectively to change the original valve into a four-position four-way rotary valve capable of automated pressure relief. In practice, it is required to only switch the valve handle to the unloading position to separately depressurize the repair target while maintaining the pressure in the rest pipes. All the other controlled components, except for those to be repaired, are under remote hydraulic control. The invention simplifies operations of repairing and replacing blowout preventer rams and rubber seals, reduces their energy consumption and improves their efficiency. The presented design also decreases the wear of valves attributed to repeated switching and greatly enhances operational efficiency.
2022, 44(6): 711-718.
doi: 10.13639/j.odpt.2022.06.008
Abstract:
Salt-cavern gas storage, characterized by the low reservoir permeability, high damage restoration capacity, high injection-production ratio, and the small amount of required cushion gas that is also fully recoverable, is found with extensive applications. However, due to the inferior quality of salt rocks, massive insoluble salt rock materials accumulate in the formed salt cavity, and a large amount of brine exists in the pores of such sediments and cannot be drained. This leads to a tremendous spatial waste of gas storage, and how to maximize the utilization of the salt cavity space is a problem demanding prompt solutions. The geology of salt layers of China’s salt-cavern gas storage and the space utilization technology for basal sediments were reviewed, which pointed out that further investigation is required for placing the brine drainage string into the base of insoluble sediments, although the gas-driven brine drainage above such sediments has increasing technical maturity. In terms of the running in and out the pipe string, the plugging problem after the string is placed and corresponding solutions, pipe diameter optimization, and future hydrogen storage, Suggestions were made to provide references for technical research on the salt-cavern gas storage space utilization in China.
Salt-cavern gas storage, characterized by the low reservoir permeability, high damage restoration capacity, high injection-production ratio, and the small amount of required cushion gas that is also fully recoverable, is found with extensive applications. However, due to the inferior quality of salt rocks, massive insoluble salt rock materials accumulate in the formed salt cavity, and a large amount of brine exists in the pores of such sediments and cannot be drained. This leads to a tremendous spatial waste of gas storage, and how to maximize the utilization of the salt cavity space is a problem demanding prompt solutions. The geology of salt layers of China’s salt-cavern gas storage and the space utilization technology for basal sediments were reviewed, which pointed out that further investigation is required for placing the brine drainage string into the base of insoluble sediments, although the gas-driven brine drainage above such sediments has increasing technical maturity. In terms of the running in and out the pipe string, the plugging problem after the string is placed and corresponding solutions, pipe diameter optimization, and future hydrogen storage, Suggestions were made to provide references for technical research on the salt-cavern gas storage space utilization in China.
2022, 44(6): 719-726, 739.
doi: 10.13639/j.odpt.2022.06.009
Abstract:
Considering the first rising and then falling of the isotherm at high temperature and high pressure for deep shale gas reservoirs, the Langmuir isotherm was modified, and the mathematic model incorporating supercritical adsorption and nonlinear flow was developed for gas-water two-phase flow of fractured horizontal wells in deep shale gas reservoirs. Moreover, the developed model was solved in a finite element approach and then used to investigate the effects of the matrix permeability, the reconstruction zone area and main fracture permeability on the flow of gas and water. The research showed that a larger the reconstruction zone area is not always preferred—further expansion of the reconstruction zone area beyond a threshold brings about no considerable gain in production. Moreover, it is indicated that during the production, the fluids inside the main fracture first flow into the well, then the fluids in the reconstruction zone flow into the main fracture, and finally the matrix fluids recharge the reconstruction zone. Therefore, early production is mostly affected by the main fracture permeability, and late production is dominated by matrix permeability. The findings of this research provide guidance for the recovery of deep shale gas.
Considering the first rising and then falling of the isotherm at high temperature and high pressure for deep shale gas reservoirs, the Langmuir isotherm was modified, and the mathematic model incorporating supercritical adsorption and nonlinear flow was developed for gas-water two-phase flow of fractured horizontal wells in deep shale gas reservoirs. Moreover, the developed model was solved in a finite element approach and then used to investigate the effects of the matrix permeability, the reconstruction zone area and main fracture permeability on the flow of gas and water. The research showed that a larger the reconstruction zone area is not always preferred—further expansion of the reconstruction zone area beyond a threshold brings about no considerable gain in production. Moreover, it is indicated that during the production, the fluids inside the main fracture first flow into the well, then the fluids in the reconstruction zone flow into the main fracture, and finally the matrix fluids recharge the reconstruction zone. Therefore, early production is mostly affected by the main fracture permeability, and late production is dominated by matrix permeability. The findings of this research provide guidance for the recovery of deep shale gas.
2022, 44(6): 727-732.
doi: 10.13639/j.odpt.2022.06.010
Abstract:
The Huabei Oilfield has performed enhanced oil recovery testing based on nitrogen injection gravity drainage in the buried hill oil reservoir since the 1990s. The pattern composed of the gas cap, oil-enriched zone and bottom water was formed. The existing wells were used for production, in which pay zones were drilled-in and left openhole after the upper wellbore was cased. However, these wells presented only gas production, with no oil production, Given this, the investigation integrating oil reservoir engineering and production engineering was performed and the production engineering design idea combining isolation, control, and selective production was proposed. It is considered that the key to preventing gas and water from directly flowing into the wellbore is to overcome the effects of gravitational differentiation and density difference to facilitate effective containment, pressure-bearing, and plugging. Inspired by the natural process of lava eruption, cooling and accumulation, the pressure-bearable channel plugging technology of fluid retention and temperature-controlled fast setting was developed, with the help of the unique thermosensitive rheology of thermosensitive resins to overcome gravitational differentiation. Reservoirs developed high-angle large fractures and caverns suffer from severe leakoff, which impacts the quality of cementing and well completion. Yet, the presented technology overcomes such challenges. Moreover, the presented technology combined with the control of drawdown pressure during artificial lifting realizes effective recovery of enriched oil zones with limited thickness. The application performance of this technology strengthens the confidence in applying gas injection gravity drainage in buried hill reservoirs.
The Huabei Oilfield has performed enhanced oil recovery testing based on nitrogen injection gravity drainage in the buried hill oil reservoir since the 1990s. The pattern composed of the gas cap, oil-enriched zone and bottom water was formed. The existing wells were used for production, in which pay zones were drilled-in and left openhole after the upper wellbore was cased. However, these wells presented only gas production, with no oil production, Given this, the investigation integrating oil reservoir engineering and production engineering was performed and the production engineering design idea combining isolation, control, and selective production was proposed. It is considered that the key to preventing gas and water from directly flowing into the wellbore is to overcome the effects of gravitational differentiation and density difference to facilitate effective containment, pressure-bearing, and plugging. Inspired by the natural process of lava eruption, cooling and accumulation, the pressure-bearable channel plugging technology of fluid retention and temperature-controlled fast setting was developed, with the help of the unique thermosensitive rheology of thermosensitive resins to overcome gravitational differentiation. Reservoirs developed high-angle large fractures and caverns suffer from severe leakoff, which impacts the quality of cementing and well completion. Yet, the presented technology overcomes such challenges. Moreover, the presented technology combined with the control of drawdown pressure during artificial lifting realizes effective recovery of enriched oil zones with limited thickness. The application performance of this technology strengthens the confidence in applying gas injection gravity drainage in buried hill reservoirs.
2022, 44(6): 733-739.
doi: 10.13639/j.odpt.2022.06.011
Abstract:
The buried hill metamorphic rock reservoir of the Jilantai oilfield features shallow burial (400−650 m), high heterogeneity, and the development of high-angle natural fractures and the bottom water system. The fracturing reservoir stimulation suffers from high difficulties in cracking strata, proneness to connection with the bottom water, and blindness for sweet spots. The analysis of the characteristics of the metamorphic rock reservoir combined with the gained fracturing experience showed that the optimal height of water avoidance for water production control is 100−120 m. The bridge plug-perforating integrated technology with the 25 ℃ low-temperature soluble bridge plug was applied to facilitate high-pump-rate large-scale multi-stage fracturing. The perforating azimuth was optimized to avoid perforating the upper 120° range and lower sand production risks. The water-soluble temporary plugging agent was adopted for inter-layer/intra-layer temporary plugging, which led to a pressure rise of 5−8 MPa. The geological-engineering dual sweet spots were identified via long-distance sonic imaging, and the reservoir stimulation model featuring fewer stages and more clusters was formed. The presented fracturing technology was applied to 13 wells of the buried hill metamorphic rock reservoir in the Jihua-1 block, including 74 fracturing stages and 361 perforation clusters. Compared with the testing wells in early 2020, these wells presented the average fracturing stage reduction by 2 stages/well and the growth of initial post-fracturing daily oil production by 48%. By the end of June 2022, the cumulative liquid production exceeded 26600 tons and the cumulative oil production surpassed 24500 tons, which represents high-efficiency reservoir stimulation and recovery of the shallow metamorphic rock reservoir.
The buried hill metamorphic rock reservoir of the Jilantai oilfield features shallow burial (400−650 m), high heterogeneity, and the development of high-angle natural fractures and the bottom water system. The fracturing reservoir stimulation suffers from high difficulties in cracking strata, proneness to connection with the bottom water, and blindness for sweet spots. The analysis of the characteristics of the metamorphic rock reservoir combined with the gained fracturing experience showed that the optimal height of water avoidance for water production control is 100−120 m. The bridge plug-perforating integrated technology with the 25 ℃ low-temperature soluble bridge plug was applied to facilitate high-pump-rate large-scale multi-stage fracturing. The perforating azimuth was optimized to avoid perforating the upper 120° range and lower sand production risks. The water-soluble temporary plugging agent was adopted for inter-layer/intra-layer temporary plugging, which led to a pressure rise of 5−8 MPa. The geological-engineering dual sweet spots were identified via long-distance sonic imaging, and the reservoir stimulation model featuring fewer stages and more clusters was formed. The presented fracturing technology was applied to 13 wells of the buried hill metamorphic rock reservoir in the Jihua-1 block, including 74 fracturing stages and 361 perforation clusters. Compared with the testing wells in early 2020, these wells presented the average fracturing stage reduction by 2 stages/well and the growth of initial post-fracturing daily oil production by 48%. By the end of June 2022, the cumulative liquid production exceeded 26600 tons and the cumulative oil production surpassed 24500 tons, which represents high-efficiency reservoir stimulation and recovery of the shallow metamorphic rock reservoir.
2022, 44(6): 740-745.
doi: 10.13639/j.odpt.2022.06.012
Abstract:
The He-1 Member, the main target of the Jin-30 well district of the Dongsheng gas field, is a tight sandstone gas reservoir with high heterogeneity. The hydraulic fracturing highlighting extended fractures is found with inferior reservoir stimulation performance. Under this background, the applicability evaluation of the stimulated reservoir volume (SRV)-oriented fracturing was performed, and the fracture propagation pattern was investigated using cores. The main control factors on the formation of complex fracture networks were clarified, and the fracturing treatment parameters were optimized via numerical simulation. The research showed that the He-1 Member reservoir of the Jin-30 well district is characterized by a high brittleness index, well-developed natural fractures and small horizontal principal stress difference, and therefore, complex fractures are expected in the case of fracturing using low-viscosity fluids and high pump rates. Moreover, the complexity of the resultant fracture network is high, and the SRV is rather expanded, under the conditions of the pump rate of 8−10 m3/min, injected liquid of 700−800 m3, the viscosity fracturing fluid combination of 10 mPa · s + 100 mPa · s, the proportions of prepad fluids of 50%−55% and the average proppant concentration of 20%−22%. The presented technology has been applied to 34 vertical/direction wells in the field. The average post-fracturing production reaches 1.85×104 m3/d, representing an increment of 68.2%, compared with that of the fracturing technology targeting long fractures. This validates the high applicability of SRV-oriented fracturing with viscosity-variable fracturing fluids to the Jin-30 well district and applications of this technology should be further promoted.
The He-1 Member, the main target of the Jin-30 well district of the Dongsheng gas field, is a tight sandstone gas reservoir with high heterogeneity. The hydraulic fracturing highlighting extended fractures is found with inferior reservoir stimulation performance. Under this background, the applicability evaluation of the stimulated reservoir volume (SRV)-oriented fracturing was performed, and the fracture propagation pattern was investigated using cores. The main control factors on the formation of complex fracture networks were clarified, and the fracturing treatment parameters were optimized via numerical simulation. The research showed that the He-1 Member reservoir of the Jin-30 well district is characterized by a high brittleness index, well-developed natural fractures and small horizontal principal stress difference, and therefore, complex fractures are expected in the case of fracturing using low-viscosity fluids and high pump rates. Moreover, the complexity of the resultant fracture network is high, and the SRV is rather expanded, under the conditions of the pump rate of 8−10 m3/min, injected liquid of 700−800 m3, the viscosity fracturing fluid combination of 10 mPa · s + 100 mPa · s, the proportions of prepad fluids of 50%−55% and the average proppant concentration of 20%−22%. The presented technology has been applied to 34 vertical/direction wells in the field. The average post-fracturing production reaches 1.85×104 m3/d, representing an increment of 68.2%, compared with that of the fracturing technology targeting long fractures. This validates the high applicability of SRV-oriented fracturing with viscosity-variable fracturing fluids to the Jin-30 well district and applications of this technology should be further promoted.
2022, 44(6): 746-751.
doi: 10.13639/j.odpt.2022.00.013
Abstract:
To improve the fracturing efficiency and reduce the fracturing cost, the testing of dual-well simultaneous fracturing was performed for four-well pads of Mahu. Specifically, the fracturing operation was performed simultaneously using the same group of fracturing trucks for two wells of a multi-well pad containing four or more wells. Compared with the conventional zipper fracturing operation with the same hydraulic horsepower in the same block, the testing presents a time reduction of well completion by 45% and the growth of the daily average operation efficiency by 70%. However, geologic, engineering and equipment factors resulted in the failure to synchronize well fracturing, the design with only two perforation clusters in one fracturing stage led to perforation plugging and abrupt rising of operation pressure, and the failure and movement of bridge plugs caused sudden drops of treatment pressure. Analysis of the current challenges indicates that the practice of dual-well simultaneous fracturing requires more work in planning well placement and drilling operations, upgrading core equipment and optimizing the perforating scheme, to form a dual-well synchronous fracturing technology template suitable for domestic unconventional oil and gas development.
To improve the fracturing efficiency and reduce the fracturing cost, the testing of dual-well simultaneous fracturing was performed for four-well pads of Mahu. Specifically, the fracturing operation was performed simultaneously using the same group of fracturing trucks for two wells of a multi-well pad containing four or more wells. Compared with the conventional zipper fracturing operation with the same hydraulic horsepower in the same block, the testing presents a time reduction of well completion by 45% and the growth of the daily average operation efficiency by 70%. However, geologic, engineering and equipment factors resulted in the failure to synchronize well fracturing, the design with only two perforation clusters in one fracturing stage led to perforation plugging and abrupt rising of operation pressure, and the failure and movement of bridge plugs caused sudden drops of treatment pressure. Analysis of the current challenges indicates that the practice of dual-well simultaneous fracturing requires more work in planning well placement and drilling operations, upgrading core equipment and optimizing the perforating scheme, to form a dual-well synchronous fracturing technology template suitable for domestic unconventional oil and gas development.
2022, 44(6): 752-757.
doi: 10.13639/j.odpt.2022.06.014
Abstract:
The evaluation and analysis of well integrity were performed, considering the high risks of well sealing failure during the conversion of previous water injection wells to CO2 injection wells in the carbon capture, utilization and storage (CCUS) testing area of the Aonan oilfield, Daqing. Based on the analysis of conditions of existing water injection wells, the technical system of the well integrity evaluation was built, and the weights of indexes were determined via the analytical hierarchy process. Given that in the previous well integrity evaluation, the assessment of each index is solely based on the expert survey, an innovative numerical simulation approach was developed, and the determination principles for the single-factor risk evaluation index, such as casing and cement sheath, were clarified. Furthermore, the quantitative risk ranking method was proposed for the conversion of water injection wells to CO2 injection wells. This research showed that among 361 injection wells of the testing area, wells with medium risks and above account for 41%, requiring immediate treatment or abandonment; for wells with low risks, the casing should be inspected and monitoring should be strengthened. It is suggested that the risk evaluation method and management strategy should be promoted across major CCUS testing areas in China to ensure safe operations of existing water injection wells.
The evaluation and analysis of well integrity were performed, considering the high risks of well sealing failure during the conversion of previous water injection wells to CO2 injection wells in the carbon capture, utilization and storage (CCUS) testing area of the Aonan oilfield, Daqing. Based on the analysis of conditions of existing water injection wells, the technical system of the well integrity evaluation was built, and the weights of indexes were determined via the analytical hierarchy process. Given that in the previous well integrity evaluation, the assessment of each index is solely based on the expert survey, an innovative numerical simulation approach was developed, and the determination principles for the single-factor risk evaluation index, such as casing and cement sheath, were clarified. Furthermore, the quantitative risk ranking method was proposed for the conversion of water injection wells to CO2 injection wells. This research showed that among 361 injection wells of the testing area, wells with medium risks and above account for 41%, requiring immediate treatment or abandonment; for wells with low risks, the casing should be inspected and monitoring should be strengthened. It is suggested that the risk evaluation method and management strategy should be promoted across major CCUS testing areas in China to ensure safe operations of existing water injection wells.
2022, 44(6): 758-762.
doi: 10.13639/j.odpt.2022.06.015
Abstract:
The current sand control tubing fishing technology has less consideration for the effects of the cutting position, well inclination and bottomhole assembly on the cutting operation. This research focused on two key points of fishing sand control tubing—cutting and milling and identified the cutting positions of the hydraulic mechanical cutting tool. The force on cutters during cutting was calculated, the factors affecting cutting were investigated, and the key technology for milling of sand control tubing was clarified. The research showed that with well inclination less than 12°, extra drill collars are required to improve the BHA rotation stability; with well inclination of 12°−55°, the reduction of cutting pressure, increase of drill collars, and prolonged cutting time should be adopted; with well inclination above 55°, it is required to reduce the cutting pressure, decrease drill collars, and place extra centralizers or torque reducers to improve the cutting power. Over 60 sand control tubing fishing operations using the presented technology were performed in the Liaodong, Bonan, and Boxi blocks of the Bohai Bay oilfield, which greatly enhances the fishing efficiency of sand control tubing and well intervention time-efficiency.
The current sand control tubing fishing technology has less consideration for the effects of the cutting position, well inclination and bottomhole assembly on the cutting operation. This research focused on two key points of fishing sand control tubing—cutting and milling and identified the cutting positions of the hydraulic mechanical cutting tool. The force on cutters during cutting was calculated, the factors affecting cutting were investigated, and the key technology for milling of sand control tubing was clarified. The research showed that with well inclination less than 12°, extra drill collars are required to improve the BHA rotation stability; with well inclination of 12°−55°, the reduction of cutting pressure, increase of drill collars, and prolonged cutting time should be adopted; with well inclination above 55°, it is required to reduce the cutting pressure, decrease drill collars, and place extra centralizers or torque reducers to improve the cutting power. Over 60 sand control tubing fishing operations using the presented technology were performed in the Liaodong, Bonan, and Boxi blocks of the Bohai Bay oilfield, which greatly enhances the fishing efficiency of sand control tubing and well intervention time-efficiency.
2022, 44(6): 763-768, 790.
doi: 10.13639/j.odpt.2022.06.016
Abstract:
In order to ensure the intensive injection, production and safe operation of the Shuang 6 storage in Liaohe Oilfield during the peak shaving period, taking Well SL1 as an example, the injection-production capacity of the Shuang 6 storage was evaluated by considering three factors including safe formation pressure of 10−24 MPa, erosion resistance of injection-production string, and formation liquid-carrying capacity. During the period of “four injections and four productions” from 2017 to 2020, the tests for determining well productivity were carried out continuously, the flow pressure and gas injection-production volume were monitored, and the binomial productivity equation was established to calculate the limit gas injection-production volume under different formation pressures. The critical erosion flow rate and critical liquid-carrying flow rate of the Ø114.3 mm gas-sealed injection-production string was calculated, and the safe injection-production system of a single well was determined. Summarizing the change law of formation pressure in Well SL1 with the cumulative gas injection (production) volume, it is predicted that the safe cumulative gas injection volume of the well ranges from 0.942×108 m3 to 2.713×108 m3. After the storage area is connected and reaches a unified pressure system, it is predicted that only when the safe storage capacity of the Shuang 6 storage ranges from 7.623×108 m3 to 34.510×108 m3, can the formation pressure and gas injection-production capacity meet the safe operation requirements of the storage.
In order to ensure the intensive injection, production and safe operation of the Shuang 6 storage in Liaohe Oilfield during the peak shaving period, taking Well SL1 as an example, the injection-production capacity of the Shuang 6 storage was evaluated by considering three factors including safe formation pressure of 10−24 MPa, erosion resistance of injection-production string, and formation liquid-carrying capacity. During the period of “four injections and four productions” from 2017 to 2020, the tests for determining well productivity were carried out continuously, the flow pressure and gas injection-production volume were monitored, and the binomial productivity equation was established to calculate the limit gas injection-production volume under different formation pressures. The critical erosion flow rate and critical liquid-carrying flow rate of the Ø114.3 mm gas-sealed injection-production string was calculated, and the safe injection-production system of a single well was determined. Summarizing the change law of formation pressure in Well SL1 with the cumulative gas injection (production) volume, it is predicted that the safe cumulative gas injection volume of the well ranges from 0.942×108 m3 to 2.713×108 m3. After the storage area is connected and reaches a unified pressure system, it is predicted that only when the safe storage capacity of the Shuang 6 storage ranges from 7.623×108 m3 to 34.510×108 m3, can the formation pressure and gas injection-production capacity meet the safe operation requirements of the storage.
2022, 44(6): 769-776.
doi: 10.13639/j.odpt.2022.06.017
Abstract:
The development of drilling and well completion engineering over the past one hundred years can be divided into four stages, namely conceptual, empirical, scientific and automatic stages, during which the drilling and well completion technical system, guided by technical principles and methodology of drilling and well completion and armed by equipment, tools, and software. At present, a vision of global carbon neutrality greatly is expected to cause a great reduction in petroleum demand and investment in hydrocarbon exploration and development. Accordingly, oilfield service companies are subjected to increasing pressure for carbon footprint control and commitments to safety and environment protection, and the profit space of engineering technical services is compressed. The green and low-carbon transformation is inevitable for petroleum drilling. Digitalization and intelligentization are the destined routes for petroleum drilling to carbon peak and carbon neutrality and facilitate high-quality development. The status of petroleum drilling digitalization and intelligetization was reviewed, and the challenges facing the drilling technology development were identified. It was proposed that the upgrading and leap-forward of conventional engineering technology should be delivered via three aspects of intelligent drilling and well completion. Also, the intelligent surface equipment should coordinate with intelligent downhole tools, with intelligent software serving as interactive systems, to deliver closed-loop drilling optimization. By doing so, the synergistic ecology of drilling and well completion digitalization is formed, which promotes the upgrading and greatly enhances the operation efficiency and safety assurance of drilling and well completion.
The development of drilling and well completion engineering over the past one hundred years can be divided into four stages, namely conceptual, empirical, scientific and automatic stages, during which the drilling and well completion technical system, guided by technical principles and methodology of drilling and well completion and armed by equipment, tools, and software. At present, a vision of global carbon neutrality greatly is expected to cause a great reduction in petroleum demand and investment in hydrocarbon exploration and development. Accordingly, oilfield service companies are subjected to increasing pressure for carbon footprint control and commitments to safety and environment protection, and the profit space of engineering technical services is compressed. The green and low-carbon transformation is inevitable for petroleum drilling. Digitalization and intelligentization are the destined routes for petroleum drilling to carbon peak and carbon neutrality and facilitate high-quality development. The status of petroleum drilling digitalization and intelligetization was reviewed, and the challenges facing the drilling technology development were identified. It was proposed that the upgrading and leap-forward of conventional engineering technology should be delivered via three aspects of intelligent drilling and well completion. Also, the intelligent surface equipment should coordinate with intelligent downhole tools, with intelligent software serving as interactive systems, to deliver closed-loop drilling optimization. By doing so, the synergistic ecology of drilling and well completion digitalization is formed, which promotes the upgrading and greatly enhances the operation efficiency and safety assurance of drilling and well completion.
2022, 44(6): 777-783.
doi: 10.13639/j.odpt.2022.06.018
Abstract:
Occurring of steam channeling during cyclic steam injection of heavy oil reservoirs is attributed to both geological and engineering factors. The current methods for identifying steam channeling are limited to the reservoir engineering approach and numerical simulation, which fail to capture the uncertainty and correlation between factors. Nevertheless, machine learning can recognize implicit correlations among massive data and has high accuracy and low maintenance. This research investigated the factors affecting steam channeling and performed the feature engineering processing after building the base dataset, including data reconstruction, dealing with missing values, dimension transformation and similarity analysis to build the feature attribute set for steam channeling. Subsequently, the dimensionality reduction of the dataset was carried out via the Wrapper method, Embedded method and principal component analysis to deliver three schemes of feature combinations. The steam channeling prediction models were built using the random forest, support vector machine (SVM), neural network, and XGBoost algorithms, respectively, of which the prediction accuracies and predicted steam channeling pathway distributions were presented. The research showed that the steam injection intensity, permeability extreme value of layers and well spacing have the largest influences on steam channeling. The data-algorithm combination with the best performance is the PCA dataset with the XGBoost model, which precisely predicts steam channeling with an accuracy of 97.20% for the training set and 96.11% for the validation set.
Occurring of steam channeling during cyclic steam injection of heavy oil reservoirs is attributed to both geological and engineering factors. The current methods for identifying steam channeling are limited to the reservoir engineering approach and numerical simulation, which fail to capture the uncertainty and correlation between factors. Nevertheless, machine learning can recognize implicit correlations among massive data and has high accuracy and low maintenance. This research investigated the factors affecting steam channeling and performed the feature engineering processing after building the base dataset, including data reconstruction, dealing with missing values, dimension transformation and similarity analysis to build the feature attribute set for steam channeling. Subsequently, the dimensionality reduction of the dataset was carried out via the Wrapper method, Embedded method and principal component analysis to deliver three schemes of feature combinations. The steam channeling prediction models were built using the random forest, support vector machine (SVM), neural network, and XGBoost algorithms, respectively, of which the prediction accuracies and predicted steam channeling pathway distributions were presented. The research showed that the steam injection intensity, permeability extreme value of layers and well spacing have the largest influences on steam channeling. The data-algorithm combination with the best performance is the PCA dataset with the XGBoost model, which precisely predicts steam channeling with an accuracy of 97.20% for the training set and 96.11% for the validation set.
2022, 44(6): 784-790.
doi: 10.13639/j.odpt.2022.06.019
Abstract:
To improve the prediction accuracy and consistency of liquid production virtual metering of electric submersible progressive cavity pumps (ESPCPs), a hybrid model (CNN-BiGRU) integrating convolution neural network (CNN) and bidirectional gate recurrent unit (GRU) was proposed, which also incorporated the dual attention mechanism. This production forecast of oil wells is subjected to tubing pressure, casing pressure and pump conditions. First, the dimensionality reduction of data was performed using Pearson’s correlation coefficient and principal component analysis, and the main influential factors were identified. Subsequently, the local connecting and global sharing of the CNN network was used to extract spatial features of liquid production data of oil wells. The extracted features were then fed to the GRU network to extract the temporal features of the data. Finally, the weights were assigned corresponding features via the dual attention mechanism to improve the prediction accuracy of the model. The presented method has been applied to 50000 data samples of liquid production. The root-mean-square error (RMSE) and mean absolute percentage error (MAPE) of the model were 5.24% and 3.17%, respectively. Compared with the GRU and CNN-GRU models, the presented method delivers excellent prediction performance and greatly improves the prediction accuracy, which marks its high value for engineering applications.
To improve the prediction accuracy and consistency of liquid production virtual metering of electric submersible progressive cavity pumps (ESPCPs), a hybrid model (CNN-BiGRU) integrating convolution neural network (CNN) and bidirectional gate recurrent unit (GRU) was proposed, which also incorporated the dual attention mechanism. This production forecast of oil wells is subjected to tubing pressure, casing pressure and pump conditions. First, the dimensionality reduction of data was performed using Pearson’s correlation coefficient and principal component analysis, and the main influential factors were identified. Subsequently, the local connecting and global sharing of the CNN network was used to extract spatial features of liquid production data of oil wells. The extracted features were then fed to the GRU network to extract the temporal features of the data. Finally, the weights were assigned corresponding features via the dual attention mechanism to improve the prediction accuracy of the model. The presented method has been applied to 50000 data samples of liquid production. The root-mean-square error (RMSE) and mean absolute percentage error (MAPE) of the model were 5.24% and 3.17%, respectively. Compared with the GRU and CNN-GRU models, the presented method delivers excellent prediction performance and greatly improves the prediction accuracy, which marks its high value for engineering applications.
2014, 36(1): 1-5.
2015, 37(4): 105-112.
doi: 10.13639/j.odpt.2015.04.027
2015, 37(1): 13-18.
doi: 10.13639/j.odpt.2015.01.004
2015, 37(4): 58-62.
doi: 10.13639/j.odpt.2015.04.016
2019, 41(1): 101-115.
doi: 10.13639/j.odpt.2019.01.017
2016, 38(3): 277-285.
doi: 10.13639/j.odpt.2016.03.001
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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