The topic of carbon dioxide (CO2) enhanced oil recovery (EOR) has received increased attention since five decades for two main applications: Improvement of oil recovery in reservoirs, using miscible CO2 injection as tertiary oil recovery technique. Carbon dioxide can be injected into the reservoir using different injection strategies: injected by itself, simultaneously injected with water or as water-alternating-gas (WAG) mode. CO2 can be found in different phase states: liquid, gas or supercritical, depending on the reservoir conditions (pressure/temperature). CO2 sequestration (geologic storage) as a way to reduce CO2 emission. The realization of the CO2 sequestration into reservoir requires that long term stability of the reservoir seal is ensured. It is considered that measuring electric resistivity is useful to monitor CO2 migration in the reservoir. Resistivity shows a high sensitivity to fluids saturation in reservoirs. Therefore, it is considered that deep electromagnetic technologies (e.g., crosswell EM) can also be useful as a surveillance method in case of CO2 injection. The variation of resistivity due to CO2 injection into a carbonate reservoir is not thoroughly studied, especially in a mixed salinity environment. Thus, the study presented in this paper provides a better understanding of the resisitivity responses in a mixed-salinity carbonate cores during drainange, imbibtion and CO2 injection processes, which may aid in CO2 montiroing. The study addresses the following objectives: Conduct the flooding tests on one carbonate core plug, varying the brine salinity. Conduct the CO2 injection at reservoir conditions. Measure resistivity of cores at different injection rates of CO2 into a carbonate plug, already partially saturated with brine and oil. Monitor a change in the overall resistivity of the rock while CO2 is being injected at different rates and also at a constant rate. Investigate the frequency effect on resistivity response while injecting fluids.
{"title":"Subsurface CCUS Monitoring & Surveillance: Insights on CO2 Resistivity Measurements","authors":"Abdulaziz Alqasim, Deena Al-Tayyib, Klemens Katterbauer","doi":"10.2523/iptc-22986-ea","DOIUrl":"https://doi.org/10.2523/iptc-22986-ea","url":null,"abstract":"\u0000 The topic of carbon dioxide (CO2) enhanced oil recovery (EOR) has received increased attention since five decades for two main applications:\u0000 Improvement of oil recovery in reservoirs, using miscible CO2 injection as tertiary oil recovery technique. Carbon dioxide can be injected into the reservoir using different injection strategies: injected by itself, simultaneously injected with water or as water-alternating-gas (WAG) mode. CO2 can be found in different phase states: liquid, gas or supercritical, depending on the reservoir conditions (pressure/temperature). CO2 sequestration (geologic storage) as a way to reduce CO2 emission. The realization of the CO2 sequestration into reservoir requires that long term stability of the reservoir seal is ensured.\u0000 It is considered that measuring electric resistivity is useful to monitor CO2 migration in the reservoir. Resistivity shows a high sensitivity to fluids saturation in reservoirs. Therefore, it is considered that deep electromagnetic technologies (e.g., crosswell EM) can also be useful as a surveillance method in case of CO2 injection. The variation of resistivity due to CO2 injection into a carbonate reservoir is not thoroughly studied, especially in a mixed salinity environment. Thus, the study presented in this paper provides a better understanding of the resisitivity responses in a mixed-salinity carbonate cores during drainange, imbibtion and CO2 injection processes, which may aid in CO2 montiroing.\u0000 The study addresses the following objectives:\u0000 Conduct the flooding tests on one carbonate core plug, varying the brine salinity. Conduct the CO2 injection at reservoir conditions. Measure resistivity of cores at different injection rates of CO2 into a carbonate plug, already partially saturated with brine and oil. Monitor a change in the overall resistivity of the rock while CO2 is being injected at different rates and also at a constant rate. Investigate the frequency effect on resistivity response while injecting fluids.","PeriodicalId":283978,"journal":{"name":"Day 1 Wed, March 01, 2023","volume":"92 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"131870370","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
A Step Rate Test (SRT)‘s is frequently performed method used to accurately measure fracture propagation pressure (FPP) of a given geologic formation. The injection rates in the test are increased in steps from low rates below fracturing pressure to high rates above fracturing pressure, allowing each rate to stabilize, and noting the stabilized injection pressure for each rate. Then, as classic approach, pressure at the end of each injection step versus injection rate are plotted. The fracture propagation pressure occurs at the intersection of the two straight lines. Then main assumption of the classic approach is that there are "2 distinct different regions with constant properties (i.e. KH & skin)" during multi rate injection test and those regions are the one without "induced fracture" region and the one with "induced fracture" region (i.e. post frac region). However, post-frac region properties is not going be constant since fracture dimensions changes injection pressure. Therefore, the purpose of this paper is; To explore the pitfalls of the classic approach (pressure versus rate) by including derivation of the mathematic model for classic approach;To develop/provide other alternative SRT interpretation methods: "Pressure Transient Analysis (PTA) – detailed skin analysis" and "PTA– fall-off analysis"To define a holistic approach using Multiple SRT’s Interpretation methods in order to determine the FPPTo demonstrate the applicability of proposed approach for several SRT cases The proposed holistic approach was successfully applied to several SRT tests conducted in Brunei, commingled waterflood injector wells. Results showed that; Derived mathematical model demonstrated that "classic approach" is underestimating the FPP: Depending on the reservoir fracturing characteristics, expected 2 regions, which is the basis of classic approach, may not be fully developed. This was also demonstrated by actual SRT data.Classic approach might result in misleading FPP results: 2 out of 4 case has no definitive conclusive results up and there is up to 9 % error in FPP estimation (classic versus PTA approach)Classic approach even sometimes might not provide conclusive FPP results: 1 out of 4 case has no conclusive resultPTA approach (i.e. detailed skin analysis and/or prep & post-frac fall-off analysis) was successfully applied to estimate FPP pressure and it seems to be most reliable method since it has provided conclusive results for all cases.PTA analysis could be extended to determine the induced frac properties (fracture, the fracture length, width & frac properties) Recommendations on how to perform a holistic approach for SRT analysis & how to verify the results with standard PTA approach is provided. In addition, since there is no analytical model for induced fracture (i.e. pressure dependent frac), adopted PTA approach using hydraulic frac modelling to make an estimate for frac length size is also presented
{"title":"Holistic Approach to Determine the Fracture Propagation Pressure (FPP): Consistent Interpretation of Step Rate Tests Using Multiple Analysis Methods","authors":"M. Cobanoglu","doi":"10.2523/iptc-22993-ms","DOIUrl":"https://doi.org/10.2523/iptc-22993-ms","url":null,"abstract":"\u0000 A Step Rate Test (SRT)‘s is frequently performed method used to accurately measure fracture propagation pressure (FPP) of a given geologic formation. The injection rates in the test are increased in steps from low rates below fracturing pressure to high rates above fracturing pressure, allowing each rate to stabilize, and noting the stabilized injection pressure for each rate. Then, as classic approach, pressure at the end of each injection step versus injection rate are plotted. The fracture propagation pressure occurs at the intersection of the two straight lines. Then main assumption of the classic approach is that there are \"2 distinct different regions with constant properties (i.e. KH & skin)\" during multi rate injection test and those regions are the one without \"induced fracture\" region and the one with \"induced fracture\" region (i.e. post frac region). However, post-frac region properties is not going be constant since fracture dimensions changes injection pressure.\u0000 Therefore, the purpose of this paper is; To explore the pitfalls of the classic approach (pressure versus rate) by including derivation of the mathematic model for classic approach;To develop/provide other alternative SRT interpretation methods: \"Pressure Transient Analysis (PTA) – detailed skin analysis\" and \"PTA– fall-off analysis\"To define a holistic approach using Multiple SRT’s Interpretation methods in order to determine the FPPTo demonstrate the applicability of proposed approach for several SRT cases\u0000 The proposed holistic approach was successfully applied to several SRT tests conducted in Brunei, commingled waterflood injector wells. Results showed that; Derived mathematical model demonstrated that \"classic approach\" is underestimating the FPP: Depending on the reservoir fracturing characteristics, expected 2 regions, which is the basis of classic approach, may not be fully developed. This was also demonstrated by actual SRT data.Classic approach might result in misleading FPP results: 2 out of 4 case has no definitive conclusive results up and there is up to 9 % error in FPP estimation (classic versus PTA approach)Classic approach even sometimes might not provide conclusive FPP results: 1 out of 4 case has no conclusive resultPTA approach (i.e. detailed skin analysis and/or prep & post-frac fall-off analysis) was successfully applied to estimate FPP pressure and it seems to be most reliable method since it has provided conclusive results for all cases.PTA analysis could be extended to determine the induced frac properties (fracture, the fracture length, width & frac properties)\u0000 Recommendations on how to perform a holistic approach for SRT analysis & how to verify the results with standard PTA approach is provided. In addition, since there is no analytical model for induced fracture (i.e. pressure dependent frac), adopted PTA approach using hydraulic frac modelling to make an estimate for frac length size is also presented","PeriodicalId":283978,"journal":{"name":"Day 1 Wed, March 01, 2023","volume":"34 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"133217753","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
The hardness and high abrasiveness of shale formations pose great challenges for improving drilling performance with deeper and more complex unconventional gas-reservoir formations explored and developed in the Sichuan Basin of China. The work discussed a workflow of data-driven drilling-parameter optimization based on machine learning. The algorithm was used to construct the correlation among drilling parameters, lithology change, vibration, bit wear, and hole cleaning, dynamically optimize rock-breaking efficiency, and integrate with the rig control system. The data-driven drilling optimization workflow consisted of exploration mode, learning mode, and application mode. The exploration phase trained a linear model at a certain frequency during data collection and updates the increasing trend of rate of penetration (ROP) in real time after starting the workflow. Based on the trend, the direction for further exploration was given. The system entered the learning mode after sufficient exploration to learn the exact functional relationship between ROP/MSE (mechanical specific energy) and operation parameters in the current explored data queue. Current optimal operation parameters were presented based on the function relationship. Then the workflow entered the application mode, maintained the current optimal operating parameters, and kept the efficient rock-breaking state. The workflow constantly monitored the micro-interval ROP and bit energy output in the application mode. When drilling performance was under expectation, the workflow automatically evaluated new conditions (e.g., formation change, Bottom hole assembly (BHA) vibration, and cuttings bed) and switched to the learning mode or exploration mode to adapt to changes in the current drilling state. The algorithm has been integrated with the rig control system, and the field test was carried out in well Ning 209H71-3, a shale-gas horizontal well in the Sichuan Basin. The test showed that the random forest and support vector machine algorithm could fit the nonlinear function relationship among drilling parameters, hole cleaning, and bit working performance, with properly optimized parameters presented. Besides, the workflow could evaluate the trends of ROP, MSE, depth of cutting (DOC), and stick-slips (SS) to capture the limiters for drilling performance, such as bit wear and lithology changes. Two modes integrated with global and local recommendations, and the optimal parameters have been provided to drillers in time. The field performance showed about 20% of ROP improvement with the recommended parameters along the horizontal section, and a 3,100-m horizontal section has been achieved. Machine learning algorithms were applied to drilling parameter recommendations with lower manual intervention. The novel workflow is not limited to bit type, downhole tools, rig equipment, etc. It has shown an outstanding drilling improvement in complex unconventional gas wells, which led the conventional
{"title":"Maximising Drilling Rates with Real-Time Data-Driven Drilling Parameters Optimisation","authors":"M. Cui, Xin Ai, Jijun Li, Wenpeng Liu, Yan Ding","doi":"10.2523/iptc-22772-ms","DOIUrl":"https://doi.org/10.2523/iptc-22772-ms","url":null,"abstract":"\u0000 The hardness and high abrasiveness of shale formations pose great challenges for improving drilling performance with deeper and more complex unconventional gas-reservoir formations explored and developed in the Sichuan Basin of China. The work discussed a workflow of data-driven drilling-parameter optimization based on machine learning. The algorithm was used to construct the correlation among drilling parameters, lithology change, vibration, bit wear, and hole cleaning, dynamically optimize rock-breaking efficiency, and integrate with the rig control system.\u0000 The data-driven drilling optimization workflow consisted of exploration mode, learning mode, and application mode. The exploration phase trained a linear model at a certain frequency during data collection and updates the increasing trend of rate of penetration (ROP) in real time after starting the workflow. Based on the trend, the direction for further exploration was given. The system entered the learning mode after sufficient exploration to learn the exact functional relationship between ROP/MSE (mechanical specific energy) and operation parameters in the current explored data queue. Current optimal operation parameters were presented based on the function relationship. Then the workflow entered the application mode, maintained the current optimal operating parameters, and kept the efficient rock-breaking state. The workflow constantly monitored the micro-interval ROP and bit energy output in the application mode. When drilling performance was under expectation, the workflow automatically evaluated new conditions (e.g., formation change, Bottom hole assembly (BHA) vibration, and cuttings bed) and switched to the learning mode or exploration mode to adapt to changes in the current drilling state.\u0000 The algorithm has been integrated with the rig control system, and the field test was carried out in well Ning 209H71-3, a shale-gas horizontal well in the Sichuan Basin. The test showed that the random forest and support vector machine algorithm could fit the nonlinear function relationship among drilling parameters, hole cleaning, and bit working performance, with properly optimized parameters presented. Besides, the workflow could evaluate the trends of ROP, MSE, depth of cutting (DOC), and stick-slips (SS) to capture the limiters for drilling performance, such as bit wear and lithology changes. Two modes integrated with global and local recommendations, and the optimal parameters have been provided to drillers in time. The field performance showed about 20% of ROP improvement with the recommended parameters along the horizontal section, and a 3,100-m horizontal section has been achieved.\u0000 Machine learning algorithms were applied to drilling parameter recommendations with lower manual intervention. The novel workflow is not limited to bit type, downhole tools, rig equipment, etc. It has shown an outstanding drilling improvement in complex unconventional gas wells, which led the conventional","PeriodicalId":283978,"journal":{"name":"Day 1 Wed, March 01, 2023","volume":"46 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"125911958","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
A. Ghallab, Farriz Ijaz Noordin, Siti Nur Mahirah Mohd Zain, Mohd Syaza Abdul Shukor, S. Mohd, Mya Thuzar, Sylvia Mavis Ak James Berok, Agnes Tan, Jennie Chin, N. F. Mosar, Gladson Joe Barretto
The original lower completion strategy for the 13 oil producer wells in X Field was open hole standalone screens (OHSAS). The lower completion string comprised 6⅝-in. premium mesh screens inside the 8½-in. open hole. On the basis of updated predrill well data, stakeholders decided to change the well design to a cased hole gravel pack (CHGP). This paper discusses the feasibility study that was conducted to switch the design, the justification used to maintain the original strategy but with an increased use of swell packers for better compartmentalization in the OHSAS design, and the production results of the completed wells. Based on the most-recent data, maintaining the original design would increase the risk of water breakthrough and subsequently lead to a loss of production. Furthermore, all past campaigns in X Field were completions with CHGPs. To address these concerns, additional studies were performed to evaluate the potential of using the existing inventory combined with the concept of mounting shunt tubes onto the 6⅝-in. mesh screens for CHGP and to evaluate increasing the quantity of swell packers using different swelling materials for OHSAS completions. The assumption was that with a sufficient number of swell packers placed in the open hole with the sand screens, which would create a higher differential pressure, zonal isolation could be achieved in an open hole similar to the effect of having a bypass barrier in a cemented cased hole completion. Studies have showed that installing shunt tubes for 6⅝-in. screens for CHGP poses additional risks because of the tight clearance inside 9⅝-in. casing, and they can only be mounted with two shunt tubes. Isolation between zones is achieved by means of multizone shunted cup packers. However, as a result of the long lead procurement time for the multizone shunted cup packers, this option requires expediting to meet the project timeline. However, simulations performed on the enhanced OHSAS design using an increased number of swell packers became a promising solution to overcome the water breakthrough problem. The challenges were to determine the optimal quantity of swell packers required and the precise placement along the open hole. Other challenges are increasing drag effect on high dogleg well to accommodate the large quantity of swell packers. Sensitivity analysis of swell packer quantity had been run and compare with existing successful track record to further optimize the completion design. To meet the budget and schedule for the campaign, OHSASs with swell packers were successfully installed in Q4 2021 to isolate the water contact zone in the first three wells. Additional swell packers and short screens were used to mitigate the water-production risk and enable the completion and isolation of thin zones. Well unloading was performed immediately following the completions, with positive results in terms of water production in two of the three wells. The production performance of these th
{"title":"Case History: Alternative Application of Casedhole Gravel Pack with Openhole Standalone Screen and Water Contact Isolation Using Swell Packers","authors":"A. Ghallab, Farriz Ijaz Noordin, Siti Nur Mahirah Mohd Zain, Mohd Syaza Abdul Shukor, S. Mohd, Mya Thuzar, Sylvia Mavis Ak James Berok, Agnes Tan, Jennie Chin, N. F. Mosar, Gladson Joe Barretto","doi":"10.2523/iptc-22781-ms","DOIUrl":"https://doi.org/10.2523/iptc-22781-ms","url":null,"abstract":"\u0000 The original lower completion strategy for the 13 oil producer wells in X Field was open hole standalone screens (OHSAS). The lower completion string comprised 6⅝-in. premium mesh screens inside the 8½-in. open hole. On the basis of updated predrill well data, stakeholders decided to change the well design to a cased hole gravel pack (CHGP). This paper discusses the feasibility study that was conducted to switch the design, the justification used to maintain the original strategy but with an increased use of swell packers for better compartmentalization in the OHSAS design, and the production results of the completed wells.\u0000 Based on the most-recent data, maintaining the original design would increase the risk of water breakthrough and subsequently lead to a loss of production. Furthermore, all past campaigns in X Field were completions with CHGPs. To address these concerns, additional studies were performed to evaluate the potential of using the existing inventory combined with the concept of mounting shunt tubes onto the 6⅝-in. mesh screens for CHGP and to evaluate increasing the quantity of swell packers using different swelling materials for OHSAS completions. The assumption was that with a sufficient number of swell packers placed in the open hole with the sand screens, which would create a higher differential pressure, zonal isolation could be achieved in an open hole similar to the effect of having a bypass barrier in a cemented cased hole completion.\u0000 Studies have showed that installing shunt tubes for 6⅝-in. screens for CHGP poses additional risks because of the tight clearance inside 9⅝-in. casing, and they can only be mounted with two shunt tubes. Isolation between zones is achieved by means of multizone shunted cup packers. However, as a result of the long lead procurement time for the multizone shunted cup packers, this option requires expediting to meet the project timeline. However, simulations performed on the enhanced OHSAS design using an increased number of swell packers became a promising solution to overcome the water breakthrough problem. The challenges were to determine the optimal quantity of swell packers required and the precise placement along the open hole. Other challenges are increasing drag effect on high dogleg well to accommodate the large quantity of swell packers. Sensitivity analysis of swell packer quantity had been run and compare with existing successful track record to further optimize the completion design.\u0000 To meet the budget and schedule for the campaign, OHSASs with swell packers were successfully installed in Q4 2021 to isolate the water contact zone in the first three wells. Additional swell packers and short screens were used to mitigate the water-production risk and enable the completion and isolation of thin zones. Well unloading was performed immediately following the completions, with positive results in terms of water production in two of the three wells. The production performance of these th","PeriodicalId":283978,"journal":{"name":"Day 1 Wed, March 01, 2023","volume":"19 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"123888910","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Multi-component thermal fluid stimulation has been conducted in Bohai Oilfield for about ten years and at the early stage of the pilot, the corrosion of the thermal fluid injection tubing is severe with the existence of the oxygen and the carbon dioxide under high temperature conditions, which result in damage of the insulation tubing, increase of the production cost and even unwanted workover. For solving the corrosion problem and extending the working life of the tubing, the corrosion mechanisms is researched and analyzed at the first place. XRD and SEM is applied for analyzing the corrosion product. The results show that the corrosion is mainly caused by the high temperature carbon dioxide and vestigial oxygen. The high fluid flowing velocity and variable inner diameter of the insulation tubing also accelerate the corrosion process. Then, further study of corrosion behavior and corrosion prevention technology are proceeded. Corrosion behavior study is carried out through indoor experiment. The results indicate that steel corrosion rate would reach the maximum value at the temperature of about 80 centigrade. At low temperature range, the corrosion is mainly dominated by CO2, and at high temperature range, the corrosion is mainly dominated by O2. For O2 corrosion at the conditions of about 370 centigrade and 15MPa, if the O2 concentration is below 1000 ppm, the corrosion rate would be lower than 0.076mm/a and when the concentration reaches about 1%, the corrosion rate would rapidly increase to be about 2.38mm/a. Based on the analysis above, high temperature corrosion inhibitor is researched and selected. The inhibition efficiency of the optimized inhibitor could be higher than 90% which could meet the technical requirement for corrosion prevention. For further increasing the efficiency of the corrosion prevention, tubing with higher corrosion resistance is used. For the existence of the CO2 and O2 in the inner tubing during the injection process, the selected corrosion inhibitor is injected before the thermal fluid for forming the protective film at the inner side. And for the annular space, high purity Nitrogen which is higher than 99.9% is injected for lowering its O2 concentration. Till now, the comprehensive corrosion prevention technology has been applied for field test for nearly 30 well times. The corrosion problem has been greatly solved, the corrosion rate is lower than 0.1mm/a and no severe corrosion occurs during the thermal fluid injection process. Its successful application would provide a guidance and technical support for the subsequent offshore thermal exploitation.
{"title":"Research and Application of the Comprehensive Corrosion Prevention Technology for Offshore Thermal Wells in Bohai Oilfield","authors":"Hongyu Wang, Xiaodong Han, Qiuxia Wang, Hongwen Zhang, Hao Liu, Cheng Wang, Hua Zhang, Peng Dou, Jia Wen","doi":"10.2523/iptc-23014-ea","DOIUrl":"https://doi.org/10.2523/iptc-23014-ea","url":null,"abstract":"\u0000 Multi-component thermal fluid stimulation has been conducted in Bohai Oilfield for about ten years and at the early stage of the pilot, the corrosion of the thermal fluid injection tubing is severe with the existence of the oxygen and the carbon dioxide under high temperature conditions, which result in damage of the insulation tubing, increase of the production cost and even unwanted workover.\u0000 For solving the corrosion problem and extending the working life of the tubing, the corrosion mechanisms is researched and analyzed at the first place. XRD and SEM is applied for analyzing the corrosion product. The results show that the corrosion is mainly caused by the high temperature carbon dioxide and vestigial oxygen. The high fluid flowing velocity and variable inner diameter of the insulation tubing also accelerate the corrosion process. Then, further study of corrosion behavior and corrosion prevention technology are proceeded.\u0000 Corrosion behavior study is carried out through indoor experiment. The results indicate that steel corrosion rate would reach the maximum value at the temperature of about 80 centigrade. At low temperature range, the corrosion is mainly dominated by CO2, and at high temperature range, the corrosion is mainly dominated by O2. For O2 corrosion at the conditions of about 370 centigrade and 15MPa, if the O2 concentration is below 1000 ppm, the corrosion rate would be lower than 0.076mm/a and when the concentration reaches about 1%, the corrosion rate would rapidly increase to be about 2.38mm/a. Based on the analysis above, high temperature corrosion inhibitor is researched and selected. The inhibition efficiency of the optimized inhibitor could be higher than 90% which could meet the technical requirement for corrosion prevention. For further increasing the efficiency of the corrosion prevention, tubing with higher corrosion resistance is used. For the existence of the CO2 and O2 in the inner tubing during the injection process, the selected corrosion inhibitor is injected before the thermal fluid for forming the protective film at the inner side. And for the annular space, high purity Nitrogen which is higher than 99.9% is injected for lowering its O2 concentration.\u0000 Till now, the comprehensive corrosion prevention technology has been applied for field test for nearly 30 well times. The corrosion problem has been greatly solved, the corrosion rate is lower than 0.1mm/a and no severe corrosion occurs during the thermal fluid injection process. Its successful application would provide a guidance and technical support for the subsequent offshore thermal exploitation.","PeriodicalId":283978,"journal":{"name":"Day 1 Wed, March 01, 2023","volume":"23 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"125955207","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
S. H. Khor, Thanat Limpasurat, Michael Q Zhang, I. Graa
Pore-to-process solutions using the integrated asset modeling approach have been successfully developed and implemented to unlock the ultimate real values of a complex gas-condensate light-oil asset in the Middle East. The studied asset was complex, involving multiple reservoirs with dual porosity that required expertise from different domains from subsurface to surface facilities to collaborate and fully understand the complexity of fluid properties, geological properties, network backpressures, and operational constraints of the existing process facilities to recognize any opportunities of optimizing the current field development plan, thereby unlocking the true value of the studied asset. Integrated asset modeling was adopted for pore-to-process solutions that enable better management of asset operation and identification of optimal field development strategy, where seven black-oil subsurface reservoir models were integrated to six compositional wells, pipelines networks, and subsequently to six process facility models. Black-oil delumping and compositional fluid delumping were implemented to ensure fluid fidelity from pore to process. This approach established the fundamentals of effective modeling solutions that enabled multiple interdependent models to be integrated into a single production model while preserving the fidelity of individual models to reduce uncertainties and to increase confidence in the simulation results with consideration of various component model interactions, system constraints, and backpressure effects. The integrated subsurface reservoir models, compositional surface network, and process facility models brought insights and a better understanding of flow assurance, well, and pipeline integrity issues that may arise. Simulation results displayed on the asset overview dashboard helped to validate production operation strategy and suitability of the process designs. The pore-to-process solutions empowered comprehensive assessment of various field development plans to minimize uncertainties, mitigate risks; and optimize the overall production performance and reservoir recovery via an evergreen integrated model with the ability to account for the complete system constraints, interactions, and backpressure effects between various models in one integrated simulation platform. Integration of subsurface to process facility models have assisted in determining the optimum distribution of fluids per facility and surveillance of facilities performance. This project has delivered some key asset-level decisions; for example, the possibility of increased recoverable reserves by making changes to the existing process equipment (capacity and/or operational), and flow paths of producing wells, in addition to improved forecast accuracy, capital expenditure prediction, and optimal operational efficiency. The developed pore-to-process solutions confirmed that the integrated asset modeling approach could effectively validate various f
{"title":"Unlocking Ultimate Values of a Complex Gas-Condensate Light-Oil Asset in the Middle East with Integrated Pore-to-Process Solutions","authors":"S. H. Khor, Thanat Limpasurat, Michael Q Zhang, I. Graa","doi":"10.2523/iptc-23062-ms","DOIUrl":"https://doi.org/10.2523/iptc-23062-ms","url":null,"abstract":"\u0000 Pore-to-process solutions using the integrated asset modeling approach have been successfully developed and implemented to unlock the ultimate real values of a complex gas-condensate light-oil asset in the Middle East. The studied asset was complex, involving multiple reservoirs with dual porosity that required expertise from different domains from subsurface to surface facilities to collaborate and fully understand the complexity of fluid properties, geological properties, network backpressures, and operational constraints of the existing process facilities to recognize any opportunities of optimizing the current field development plan, thereby unlocking the true value of the studied asset.\u0000 Integrated asset modeling was adopted for pore-to-process solutions that enable better management of asset operation and identification of optimal field development strategy, where seven black-oil subsurface reservoir models were integrated to six compositional wells, pipelines networks, and subsequently to six process facility models. Black-oil delumping and compositional fluid delumping were implemented to ensure fluid fidelity from pore to process. This approach established the fundamentals of effective modeling solutions that enabled multiple interdependent models to be integrated into a single production model while preserving the fidelity of individual models to reduce uncertainties and to increase confidence in the simulation results with consideration of various component model interactions, system constraints, and backpressure effects.\u0000 The integrated subsurface reservoir models, compositional surface network, and process facility models brought insights and a better understanding of flow assurance, well, and pipeline integrity issues that may arise. Simulation results displayed on the asset overview dashboard helped to validate production operation strategy and suitability of the process designs. The pore-to-process solutions empowered comprehensive assessment of various field development plans to minimize uncertainties, mitigate risks; and optimize the overall production performance and reservoir recovery via an evergreen integrated model with the ability to account for the complete system constraints, interactions, and backpressure effects between various models in one integrated simulation platform. Integration of subsurface to process facility models have assisted in determining the optimum distribution of fluids per facility and surveillance of facilities performance. This project has delivered some key asset-level decisions; for example, the possibility of increased recoverable reserves by making changes to the existing process equipment (capacity and/or operational), and flow paths of producing wells, in addition to improved forecast accuracy, capital expenditure prediction, and optimal operational efficiency.\u0000 The developed pore-to-process solutions confirmed that the integrated asset modeling approach could effectively validate various f","PeriodicalId":283978,"journal":{"name":"Day 1 Wed, March 01, 2023","volume":"114 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"130797583","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
M. Yudhy, Muhammad Pratama, R. Wibawa, Ardiyansyah Lubis, P. Pujihatma
Electrical power supply reliability is a key enabler in supporting massive and aggressive exploration and exploitation campaigns in the upstream sector. For a certain complex oilfield asset, a total of more than 3,000 km of power transmission and distribution lines are operated and maintained to support its massive operation. All these power lines shall be monitored and inspected regularly to ensure it is free of operational threat that could reduce their reliability. From historical data, there are two main threats in power line operations, vegetation risk (trees and animals) and broken insulators. The current method of manual inspection and monitoring through Operator Routine Duties Check (ORDC) is not very effective since it took a considerably long period to complete and can only cover a limited area for each inspection activity session whereas the area to be inspected is vast. As a result, the inspection and monitoring program was sub-optimal to detecting the operational threat earlier. The advances in digital technology, particularly computer vision, cloud computing, and artificial intelligence, enable every device with a camera and internet connection to become additional "eyes" that monitor, inspect and analyze everything in sight. One of the optical devices with high potential for utilization in power system inspection is the Unmanned Aerial Vehicle (UAV) or best known as the drone. Drone enhanced with computer vision will have the optimal capability for inspection and surveillance of vegetation risk and broken insulators for larger areas in each inspection round. Hence, we could automate the inspection and surveillance activities and even improve their effectiveness and efficiency compared with the manual method. In this paper, we will discuss the successful pilot implementation of drones, computer vision, and artificial intelligence technology in power system operations that have improved the effectiveness of the surveillance program at a lower cost. The pilot implementation has been proven to reduce the number of power outages caused by vegetation risk and broken insulators by 50% and bring verified financial benefit of USD 7,619 per month from avoiding loss of production opportunities due to power outages related to vegetation risk and broken insulators. The financial benefit can pay off the implementation cost in 4 months of continuous operation. As a path forward, the pilot implementation will be expanded further to several other areas with a high risk of vegetation threat and broken insulators to assess its applicability in other locations before full-scale implementation.
{"title":"Success Stories and Lessons Learned from Pilot Implementation of Unmanned Air Vehicle and Computer Vision to Improve Transmission & Distribution Reliability in Complex Oilfield","authors":"M. Yudhy, Muhammad Pratama, R. Wibawa, Ardiyansyah Lubis, P. Pujihatma","doi":"10.2523/iptc-22811-ea","DOIUrl":"https://doi.org/10.2523/iptc-22811-ea","url":null,"abstract":"\u0000 Electrical power supply reliability is a key enabler in supporting massive and aggressive exploration and exploitation campaigns in the upstream sector. For a certain complex oilfield asset, a total of more than 3,000 km of power transmission and distribution lines are operated and maintained to support its massive operation. All these power lines shall be monitored and inspected regularly to ensure it is free of operational threat that could reduce their reliability. From historical data, there are two main threats in power line operations, vegetation risk (trees and animals) and broken insulators. The current method of manual inspection and monitoring through Operator Routine Duties Check (ORDC) is not very effective since it took a considerably long period to complete and can only cover a limited area for each inspection activity session whereas the area to be inspected is vast. As a result, the inspection and monitoring program was sub-optimal to detecting the operational threat earlier.\u0000 The advances in digital technology, particularly computer vision, cloud computing, and artificial intelligence, enable every device with a camera and internet connection to become additional \"eyes\" that monitor, inspect and analyze everything in sight. One of the optical devices with high potential for utilization in power system inspection is the Unmanned Aerial Vehicle (UAV) or best known as the drone. Drone enhanced with computer vision will have the optimal capability for inspection and surveillance of vegetation risk and broken insulators for larger areas in each inspection round. Hence, we could automate the inspection and surveillance activities and even improve their effectiveness and efficiency compared with the manual method.\u0000 In this paper, we will discuss the successful pilot implementation of drones, computer vision, and artificial intelligence technology in power system operations that have improved the effectiveness of the surveillance program at a lower cost. The pilot implementation has been proven to reduce the number of power outages caused by vegetation risk and broken insulators by 50% and bring verified financial benefit of USD 7,619 per month from avoiding loss of production opportunities due to power outages related to vegetation risk and broken insulators. The financial benefit can pay off the implementation cost in 4 months of continuous operation. As a path forward, the pilot implementation will be expanded further to several other areas with a high risk of vegetation threat and broken insulators to assess its applicability in other locations before full-scale implementation.","PeriodicalId":283978,"journal":{"name":"Day 1 Wed, March 01, 2023","volume":"94 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"131154021","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Wei Guo Zhang, Zhi Hua Rao, Hong Lei, Yue He, L. Zhang, Ying Huo, Kjell Revheim, Umer Shafiq, Geng Zhao, Hua Jing Yu, Peng Cao, Dong Zhang, Jin Wei Bian
A Technology Advancement of Multi-Laterals (TAML) level-4 completion was installed in the South China Sea in 2022. The unique design of this multilateral completion system increased efficiency and reliability in drilling and completing the well and enabled selective production from the main bore, the laterals, or both. It also incorporated a safe way of combining an openhole gravel pack job with a multilateral application. The main bore was completed with 9.625-in. casing. An 8.5-in. sidetrack was drilled and completed by the TAML level-4 junction and 7-in. liner was cemented in place. The key components of this multilateral completion system are an anchor packer system to temporarily isolate the main bore; a sidetrack whipstock and milling system to drill through 9.625-in. casing for 8.5-in. lateral bore; a robust 9.625 in. × 7 in. TAML level-4 junction system that combines a main bore production tieback assembly, main bore junction assembly, lateral bore junction assembly, and a junction drilling diverter isolation system. A 6-in. horizontal lateral bore was drilled through junction. An anti-swab openhole gravel pack system was installed in the 6-in. horizontal section to prevent sand production. For selective production from target zones in each lateral, a 3.5-in. intermediate string was installed. A specially designed multilateral well shrouded shearable tieback seal assembly was run back into the lateral bore. A standard sliding sleeve (SSD) and landing nipple were installed above the tieback assembly. Comingled production is achieved by leaving the SSD open, and selective production is achieved from the lateral bore by closing the SSD. Selective production from the main bore is achieved by leaving the SSD open and setting an intervention plug into the landing nipple. The upper production string was completed with an electrical submersible pump system. In early 2022, the full system was successfully installed for the first time in the region with zero health, safety, or environmental incidents and zero non-productive time. The lateral bore 7-in. liner and TAML level-4 multilateral junction were installed in a single trip, and the 7-in. liner cementing operation and excess cement cleanout were completed efficiently in that same trip. The 6-in. slim-hole drilling tool and openhole gravel pack sand control system both passed the multilateral junction with no hang up issues. The intermediate tieback string was successfully run back into lateral bore. The successful installation of entire well completion verified the high reliability and efficiency of this robust 9.625-in. ×7-in. multilateral well completion system. A traditional multilateral junction only hangs one 7-in. liner inside the 9.625-in. main bore casing. In contrast, this robust new TAML level-4 junction system enables designing the main bore junction assembly and the lateral bore junction assembly separately; the two assemblies can be installed in the same single trip together w
{"title":"Horizontal Lateral Drilling and Completion with Openhole Gravel Pack through a Unique TAML Level-4 Multilateral Junction System: The Installation Case Study from South China Sea","authors":"Wei Guo Zhang, Zhi Hua Rao, Hong Lei, Yue He, L. Zhang, Ying Huo, Kjell Revheim, Umer Shafiq, Geng Zhao, Hua Jing Yu, Peng Cao, Dong Zhang, Jin Wei Bian","doi":"10.2523/iptc-22860-ms","DOIUrl":"https://doi.org/10.2523/iptc-22860-ms","url":null,"abstract":"\u0000 A Technology Advancement of Multi-Laterals (TAML) level-4 completion was installed in the South China Sea in 2022. The unique design of this multilateral completion system increased efficiency and reliability in drilling and completing the well and enabled selective production from the main bore, the laterals, or both. It also incorporated a safe way of combining an openhole gravel pack job with a multilateral application.\u0000 The main bore was completed with 9.625-in. casing. An 8.5-in. sidetrack was drilled and completed by the TAML level-4 junction and 7-in. liner was cemented in place. The key components of this multilateral completion system are an anchor packer system to temporarily isolate the main bore; a sidetrack whipstock and milling system to drill through 9.625-in. casing for 8.5-in. lateral bore; a robust 9.625 in. × 7 in. TAML level-4 junction system that combines a main bore production tieback assembly, main bore junction assembly, lateral bore junction assembly, and a junction drilling diverter isolation system. A 6-in. horizontal lateral bore was drilled through junction. An anti-swab openhole gravel pack system was installed in the 6-in. horizontal section to prevent sand production. For selective production from target zones in each lateral, a 3.5-in. intermediate string was installed. A specially designed multilateral well shrouded shearable tieback seal assembly was run back into the lateral bore. A standard sliding sleeve (SSD) and landing nipple were installed above the tieback assembly. Comingled production is achieved by leaving the SSD open, and selective production is achieved from the lateral bore by closing the SSD. Selective production from the main bore is achieved by leaving the SSD open and setting an intervention plug into the landing nipple. The upper production string was completed with an electrical submersible pump system.\u0000 In early 2022, the full system was successfully installed for the first time in the region with zero health, safety, or environmental incidents and zero non-productive time. The lateral bore 7-in. liner and TAML level-4 multilateral junction were installed in a single trip, and the 7-in. liner cementing operation and excess cement cleanout were completed efficiently in that same trip. The 6-in. slim-hole drilling tool and openhole gravel pack sand control system both passed the multilateral junction with no hang up issues. The intermediate tieback string was successfully run back into lateral bore. The successful installation of entire well completion verified the high reliability and efficiency of this robust 9.625-in. ×7-in. multilateral well completion system.\u0000 A traditional multilateral junction only hangs one 7-in. liner inside the 9.625-in. main bore casing. In contrast, this robust new TAML level-4 junction system enables designing the main bore junction assembly and the lateral bore junction assembly separately; the two assemblies can be installed in the same single trip together w","PeriodicalId":283978,"journal":{"name":"Day 1 Wed, March 01, 2023","volume":"97 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"115314167","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
F. Cracolici, V. Iorio, F. Parrozza, L. Sabatino, Elisabetta Previde Massara, A. Consonni, A. Viareggio, Cristiano William Altimare, S. Gori, Luigi Colombo, S. Racca, R. Poloni
Underground Hydrogen Storage (UHS) is a method to store a large amount of energy to manage its seasonal fluctuations. The selection of proper well materials is a critical aspect, considering the small size of the molecule of H2 and its strong diffusivity. Its impact on materials shall be deeply evaluated and investigated. The work described in this document analyzes the interaction of standard cement slurries used in oil and gas fields with hydrogen at standard reservoir conditions. The cement-hydrogen interaction tests were designed and conducted using the methodological approach typical of the materials/fluids compatibility tests; an autoclave was used as key instrumentation to simulate reservoir temperature and pressure conditions. The samples were left inside the autoclave in contact with hydrogen, at reservoir temperature and pressure condition (90 °C and 150 bar), for 8 weeks. In parallel to the aging in hydrogen, twin samples were aged in an inert atmosphere (nitrogen) for comparison. The effects of the long exposure of the cement to H2 have been analyzed by observing the changes in the chemical-physical properties of the cement itself. To give evidence of the goodness of the cement as a well sealant material in the UHS, compressive strength, saturation and permeability, chemistry of the cement were measured/analyzed pre- and post-hydrogen exposure. In addition to the tests, a theoretical analysis performed using thermodynamic modeling software was also conducted to validate test results. The thermodynamic analysis was focused on the specific interaction of the species, hydrate and not-, constituting the cement and the hydrogen, investigating the spontaneity of the redox reactions that could take place. Preliminary autoclave experimentation results show that hydrogen does not alter overly chemical and physical characteristics of cement samples. This compatibility study of Hydrogen with cement is the first important step to further de-risk any UHS activity. The engineered and adopted testing protocol reported in this paper proved to be effective for the purpose of the study and could be applied for the validation of specific cement slurries in the UHS contexts.
{"title":"Experimental Investigation of Cement Compatibility in Underground Hydrogen Storage in Depleted Reservoir","authors":"F. Cracolici, V. Iorio, F. Parrozza, L. Sabatino, Elisabetta Previde Massara, A. Consonni, A. Viareggio, Cristiano William Altimare, S. Gori, Luigi Colombo, S. Racca, R. Poloni","doi":"10.2523/iptc-22797-ms","DOIUrl":"https://doi.org/10.2523/iptc-22797-ms","url":null,"abstract":"\u0000 Underground Hydrogen Storage (UHS) is a method to store a large amount of energy to manage its seasonal fluctuations. The selection of proper well materials is a critical aspect, considering the small size of the molecule of H2 and its strong diffusivity. Its impact on materials shall be deeply evaluated and investigated.\u0000 The work described in this document analyzes the interaction of standard cement slurries used in oil and gas fields with hydrogen at standard reservoir conditions.\u0000 The cement-hydrogen interaction tests were designed and conducted using the methodological approach typical of the materials/fluids compatibility tests; an autoclave was used as key instrumentation to simulate reservoir temperature and pressure conditions.\u0000 The samples were left inside the autoclave in contact with hydrogen, at reservoir temperature and pressure condition (90 °C and 150 bar), for 8 weeks. In parallel to the aging in hydrogen, twin samples were aged in an inert atmosphere (nitrogen) for comparison.\u0000 The effects of the long exposure of the cement to H2 have been analyzed by observing the changes in the chemical-physical properties of the cement itself.\u0000 To give evidence of the goodness of the cement as a well sealant material in the UHS, compressive strength, saturation and permeability, chemistry of the cement were measured/analyzed pre- and post-hydrogen exposure.\u0000 In addition to the tests, a theoretical analysis performed using thermodynamic modeling software was also conducted to validate test results. The thermodynamic analysis was focused on the specific interaction of the species, hydrate and not-, constituting the cement and the hydrogen, investigating the spontaneity of the redox reactions that could take place.\u0000 Preliminary autoclave experimentation results show that hydrogen does not alter overly chemical and physical characteristics of cement samples.\u0000 This compatibility study of Hydrogen with cement is the first important step to further de-risk any UHS activity.\u0000 The engineered and adopted testing protocol reported in this paper proved to be effective for the purpose of the study and could be applied for the validation of specific cement slurries in the UHS contexts.","PeriodicalId":283978,"journal":{"name":"Day 1 Wed, March 01, 2023","volume":"108 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"115487165","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
Guangming Pan, Xianbo Luo, Lei Zhang, Hao-lin Li, Jifeng Qu
The target heavy oil reservoir was developed by horizontal wells with large well spacing (250 m ~ 450 m) during the early huff and puff stage. However, more than 70% of the reserves was left in the reservoir after stimulation development because of its small heating radius, and required further enhanced oil recovery through subsequent steam flooding for inter-well reserves extraction. Different from traditional vertical well, a special hot-water condensate zone developed at the reservoir bottom due to vertical radial flow during horizontal well steam flooding was demonstrated in our previous work. Inhibiting the development of hot-water condensate zone became the design key for horizontal well steam flooding. Based on laboratory physical experiments and numerical simulation method with 13 years of huff and puff development history match, the first offshore steam flooding scheme was studied to optimize and obtain the main heat injection parameters. Finally, field practice was carried out 30 months ago to verify project design. Results showed that, compared with mature vertical well steam flooding designed for suppressing the overlap in top steam zone, the horizontal steam flooding was designed to suppress channeling flow caused by weak stability of hot-water displacement oil front in bottom condensate zone. Therefore, the heat injection well was designed in the low structure position for horizontal well steam flooding, while designed heat injection well for vertical well steam flooding located in the high structure position. Meanwhile, to ensure effective expansion of steam zone, the production/injection ratio was optimized as high as 1.4 to 1.6 for horizontal well steam flooding, rather than low production/injection ratio of 1.2 to 1.4 for conventional vertical well. Also, it was demonstrated that foam can effectively prevent steam channeling under high oil saturation conditions, especially in the high superheated temperature. So the profile control timing for horizontal well was advanced in the early thermal connection stage, instead of the late steam breakthrough phase for vertical well. The field practice has been carried out for 30 months, the daily oil production of well group increased from 180 m3 to 250 m3, and the instantaneous oil/gas ratio was developed as high as 0.8 to 1.0. It was suggested to pay special attention for the additional hot-water condensate zone at the reservoir bottom for horizontal well steam flooding. The proven development strategy, inhibiting condensate zones at reservoir bottom and promoting steam zones at reservoir top, customized for horizontal well can also be applied in offshore similar thin heavy oil reservoirs with large well spacing.
{"title":"The First Steam Flooding Design and Application for Thin Heavy Oil Reservoir in Bohai Bay by Horizontal Well","authors":"Guangming Pan, Xianbo Luo, Lei Zhang, Hao-lin Li, Jifeng Qu","doi":"10.2523/iptc-22735-ms","DOIUrl":"https://doi.org/10.2523/iptc-22735-ms","url":null,"abstract":"\u0000 The target heavy oil reservoir was developed by horizontal wells with large well spacing (250 m ~ 450 m) during the early huff and puff stage. However, more than 70% of the reserves was left in the reservoir after stimulation development because of its small heating radius, and required further enhanced oil recovery through subsequent steam flooding for inter-well reserves extraction.\u0000 Different from traditional vertical well, a special hot-water condensate zone developed at the reservoir bottom due to vertical radial flow during horizontal well steam flooding was demonstrated in our previous work. Inhibiting the development of hot-water condensate zone became the design key for horizontal well steam flooding. Based on laboratory physical experiments and numerical simulation method with 13 years of huff and puff development history match, the first offshore steam flooding scheme was studied to optimize and obtain the main heat injection parameters. Finally, field practice was carried out 30 months ago to verify project design.\u0000 Results showed that, compared with mature vertical well steam flooding designed for suppressing the overlap in top steam zone, the horizontal steam flooding was designed to suppress channeling flow caused by weak stability of hot-water displacement oil front in bottom condensate zone. Therefore, the heat injection well was designed in the low structure position for horizontal well steam flooding, while designed heat injection well for vertical well steam flooding located in the high structure position. Meanwhile, to ensure effective expansion of steam zone, the production/injection ratio was optimized as high as 1.4 to 1.6 for horizontal well steam flooding, rather than low production/injection ratio of 1.2 to 1.4 for conventional vertical well. Also, it was demonstrated that foam can effectively prevent steam channeling under high oil saturation conditions, especially in the high superheated temperature. So the profile control timing for horizontal well was advanced in the early thermal connection stage, instead of the late steam breakthrough phase for vertical well. The field practice has been carried out for 30 months, the daily oil production of well group increased from 180 m3 to 250 m3, and the instantaneous oil/gas ratio was developed as high as 0.8 to 1.0.\u0000 It was suggested to pay special attention for the additional hot-water condensate zone at the reservoir bottom for horizontal well steam flooding. The proven development strategy, inhibiting condensate zones at reservoir bottom and promoting steam zones at reservoir top, customized for horizontal well can also be applied in offshore similar thin heavy oil reservoirs with large well spacing.","PeriodicalId":283978,"journal":{"name":"Day 1 Wed, March 01, 2023","volume":"23 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"124802106","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
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