Most of the current prediction model of wellbore temperature for deep-water gas well does not consider the influence of natural convection in annulus on the heat dissipation of the system, resulting in a lower prediction accuracy of temperature. In this study, three-dimensional simulation on the heat transfer by natural convective of testing fluid in annulus was performed. The mechanism of heat transfer are studied for different values of Rayleigh number (Ra) and Bingham number (Bn). The results show that the occurrence of natural convection in the annulus can significantly increase the heat loss of the fluid in the tubing. With the increases in Ra or decreases in Bn, the convective transport in annulus gradually strengthens, and the heat transfer coefficient gradually increases. However, when the Bingham number increases to about 100, the heat transfer mode in annulus becomes a single heat conduction. Based on the simulation results, a new correlation of heat transfer coefficients in annulus was proposed. The introduction of this correlation can significantly improve the prediction accuracy of wellbore temperature during deep water gas well testing, and lay a foundation for the prevention and control of hydrate and wax formation in wellbore.
{"title":"Numerical Simulation of Natural Convection and Calculation of Heat Transfer Coefficient in Wellbore Annulus during Deep-Water Gas Well Testing","authors":"Hui Liu, Zhiyuan Wang, Baojiang Sun, Wenqiang Lou, Jianbo Zhang, Zheng Liu","doi":"10.2118/205822-ms","DOIUrl":"https://doi.org/10.2118/205822-ms","url":null,"abstract":"\u0000 Most of the current prediction model of wellbore temperature for deep-water gas well does not consider the influence of natural convection in annulus on the heat dissipation of the system, resulting in a lower prediction accuracy of temperature. In this study, three-dimensional simulation on the heat transfer by natural convective of testing fluid in annulus was performed. The mechanism of heat transfer are studied for different values of Rayleigh number (Ra) and Bingham number (Bn). The results show that the occurrence of natural convection in the annulus can significantly increase the heat loss of the fluid in the tubing. With the increases in Ra or decreases in Bn, the convective transport in annulus gradually strengthens, and the heat transfer coefficient gradually increases. However, when the Bingham number increases to about 100, the heat transfer mode in annulus becomes a single heat conduction. Based on the simulation results, a new correlation of heat transfer coefficients in annulus was proposed. The introduction of this correlation can significantly improve the prediction accuracy of wellbore temperature during deep water gas well testing, and lay a foundation for the prevention and control of hydrate and wax formation in wellbore.","PeriodicalId":10970,"journal":{"name":"Day 1 Tue, October 12, 2021","volume":"35 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-10-04","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80783566","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}
Fianti Ramadhani, S. Nurdin, M. Etuhoko, Yang Zhi, Sugeng Mulyono, Arvin Mintardja, Marc Dawson
Four high-pressure-high temperature (HPHT) and sour gas wells are currently operating at Madura offshore as the only productive assets for Husky-CNOOC Madura Limited (HCML). Each well performance is very crucial to fulfill the demand of the gas customers in East Java, Indonesia. Since starting production in 2017, the wells experienced two main well integrity challenges, high annulus pressure and wellhead growth. Both challenges are very dependent to the well flow rate and the flow duration. A continuous operation monitoring is highly required in order to keep the wells operating safely. To overcome the challenges, HCML established a Well Integrity Management System (WIMS) document that approached several international standards as its basis. As company grows, development plan challenged the WIMS to perform faster and more efficient as compared to the existing manual system. From there, the journey of WIMS digitalization began. The journey started with the alignment of the existing WIMS document to the ISO-16530-1 at Operational Phase with more stringent boundary to operate the wells safely. The alignment covers, but not limited to the organizational structure, well barriers and criteria, monitoring and surveillance, annulus pressure management, and maintenance. The document also covered risk assessment and management of well integrity failure, which was the backbone of the WIMS digitalization. The current digital solutions allow production data to be accessed and retrieved directly from the system for analysis purposes. It compares the recorded data with pre-determined rules and parameters set in the system. It triggers a notification to the responsible personnel to perform the required action should any anomaly occurs. It also can send a reminder to users to schedule and complete a well Integrity test to ensure that a well is always in compliance with the WIMS. All test reports and documentation are stored in the system as preparation for any future audit. A key requirement of the expert software system was access to future developments that can offer enhanced functionality of the well integrity platform through additional near time capabilities such as predictive erosion and corrosion for downhole flow wetted components. This is being developed to enhance workover scheduling for existing wells and material selection for new wells and is planned to update automatically critical well integrity criteria such as tubing burst, collapse and MAASP.
{"title":"An Expert Software System has Accomplished Full Implementation of Well Integrity Management System WIMS Resulting to Excellent Safety and Production Sustainability for Critical Sour HPHT Field in Offshore Madura Strait, Indonesia","authors":"Fianti Ramadhani, S. Nurdin, M. Etuhoko, Yang Zhi, Sugeng Mulyono, Arvin Mintardja, Marc Dawson","doi":"10.2118/205697-ms","DOIUrl":"https://doi.org/10.2118/205697-ms","url":null,"abstract":"\u0000 Four high-pressure-high temperature (HPHT) and sour gas wells are currently operating at Madura offshore as the only productive assets for Husky-CNOOC Madura Limited (HCML). Each well performance is very crucial to fulfill the demand of the gas customers in East Java, Indonesia.\u0000 Since starting production in 2017, the wells experienced two main well integrity challenges, high annulus pressure and wellhead growth. Both challenges are very dependent to the well flow rate and the flow duration. A continuous operation monitoring is highly required in order to keep the wells operating safely.\u0000 To overcome the challenges, HCML established a Well Integrity Management System (WIMS) document that approached several international standards as its basis. As company grows, development plan challenged the WIMS to perform faster and more efficient as compared to the existing manual system. From there, the journey of WIMS digitalization began. The journey started with the alignment of the existing WIMS document to the ISO-16530-1 at Operational Phase with more stringent boundary to operate the wells safely. The alignment covers, but not limited to the organizational structure, well barriers and criteria, monitoring and surveillance, annulus pressure management, and maintenance. The document also covered risk assessment and management of well integrity failure, which was the backbone of the WIMS digitalization.\u0000 The current digital solutions allow production data to be accessed and retrieved directly from the system for analysis purposes. It compares the recorded data with pre-determined rules and parameters set in the system. It triggers a notification to the responsible personnel to perform the required action should any anomaly occurs. It also can send a reminder to users to schedule and complete a well Integrity test to ensure that a well is always in compliance with the WIMS. All test reports and documentation are stored in the system as preparation for any future audit.\u0000 A key requirement of the expert software system was access to future developments that can offer enhanced functionality of the well integrity platform through additional near time capabilities such as predictive erosion and corrosion for downhole flow wetted components. This is being developed to enhance workover scheduling for existing wells and material selection for new wells and is planned to update automatically critical well integrity criteria such as tubing burst, collapse and MAASP.","PeriodicalId":10970,"journal":{"name":"Day 1 Tue, October 12, 2021","volume":"72 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-10-04","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88474657","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. S. Alfarizi, Marja Dinata, R. Parulian, K. Hamzah, Tejo Sukotrihadiyono, D. Wijayanto, Farid Ghozali, Wahyuwono Wahyuwono, A. Sedayu, Ahmad Izzul Huda, Aryawan Bondan Jalasatriya, Aurora Juniarti, K.W.A. Kwartono, F. Baskaraputra, Dwi Hudya Febrianto
XJN field has implemented water injection as pressure maintenance since 1987, only one year after initial production. XJN is carbonate reservoir with weak aquifer underlying the oil zone. Initial reservoir pressure was 2,700 psi and peak production was 27,000 BOPD. Reservoir pressure was drop to 1,800 psi within 5 years of production. During 1991-2007, better injection management was performed to provide negative voidage. This action has managed to bring reservoir pressure back to its initial pressure, eventually enabling all wells to be converted from gaslift to naturalflow. In 2013, watercut has increased to 97% and several naturally flowing wells began to ceased-to-flow, then production mode was changed gradually from naturalflow to artificial lift using Electric Submersible Pump (ESP). In 2017-2020, there was rapid reservoir pressure decline around 300 psi/year while XJN water injection performance considered flawless. Voidage Replacement Ratio (VRR) was 1.3, but reservoir pressure was kept declining. This situation will cause ESP pump off on producer wells which in turn means big production loss. This paper will elaborate about the simple-uncommon-yet effective methods for problem detection and its solution to revive pressure and production. Analysis was began with observing the deviation of VRR and reservoir pressure, this was to estimate "leak" time of water injection. Next analysis was evaluation of injection rate leak off using material balance with reverse history matching. Reverse here means making reservoir pressure as main constraint rather than history matching goal. After that, it was continued with water injection flow path analysis. This was done by plotting production-injection-pressure data then make several small groups of injector-producer based on visible relationships. The purposes were to find key injector wells and to shut-in all inefficient ones. Furthermore, injection re-distribution was also performed based on VRR calculation on groups from previous step, water distribution priority was focused on key injector wells. These analysis have also paved the way for searching channeling possibility on injector wells. The results, XJN reservoir pressure showed an increasing trend of 100 psi/year after optimization was performed, with current pressure around 2000 psi. The increase in reservoir pressure has also made it possible to optimize ESP, field lifting has increased for 5000 BLPD. This project has also successfully secured XJN remaining oil. This project was racing with rapid pressure decline that will lead to early ESP pump off and production loss. The integrated subsurface analytical methods and actions being taken were simple but effective. Close monitoring on reservoir pressure, water injection and ESP parameters will be needed as field surveillance. Integrated analysis with surface facility engineering should also be carried out in the future in regards to surface network, injection rate and reservoir pressure.
{"title":"Ingenious Method for Water Injection Optimization on Mature Carbonate Reservoir with Rapid Pressure Decline Problem, Case Study: XJN Field - South Sumatra, Indonesia","authors":"M. S. Alfarizi, Marja Dinata, R. Parulian, K. Hamzah, Tejo Sukotrihadiyono, D. Wijayanto, Farid Ghozali, Wahyuwono Wahyuwono, A. Sedayu, Ahmad Izzul Huda, Aryawan Bondan Jalasatriya, Aurora Juniarti, K.W.A. Kwartono, F. Baskaraputra, Dwi Hudya Febrianto","doi":"10.2118/205615-ms","DOIUrl":"https://doi.org/10.2118/205615-ms","url":null,"abstract":"\u0000 XJN field has implemented water injection as pressure maintenance since 1987, only one year after initial production. XJN is carbonate reservoir with weak aquifer underlying the oil zone. Initial reservoir pressure was 2,700 psi and peak production was 27,000 BOPD. Reservoir pressure was drop to 1,800 psi within 5 years of production. During 1991-2007, better injection management was performed to provide negative voidage. This action has managed to bring reservoir pressure back to its initial pressure, eventually enabling all wells to be converted from gaslift to naturalflow. In 2013, watercut has increased to 97% and several naturally flowing wells began to ceased-to-flow, then production mode was changed gradually from naturalflow to artificial lift using Electric Submersible Pump (ESP). In 2017-2020, there was rapid reservoir pressure decline around 300 psi/year while XJN water injection performance considered flawless. Voidage Replacement Ratio (VRR) was 1.3, but reservoir pressure was kept declining. This situation will cause ESP pump off on producer wells which in turn means big production loss. This paper will elaborate about the simple-uncommon-yet effective methods for problem detection and its solution to revive pressure and production.\u0000 Analysis was began with observing the deviation of VRR and reservoir pressure, this was to estimate \"leak\" time of water injection. Next analysis was evaluation of injection rate leak off using material balance with reverse history matching. Reverse here means making reservoir pressure as main constraint rather than history matching goal. After that, it was continued with water injection flow path analysis. This was done by plotting production-injection-pressure data then make several small groups of injector-producer based on visible relationships. The purposes were to find key injector wells and to shut-in all inefficient ones. Furthermore, injection re-distribution was also performed based on VRR calculation on groups from previous step, water distribution priority was focused on key injector wells. These analysis have also paved the way for searching channeling possibility on injector wells.\u0000 The results, XJN reservoir pressure showed an increasing trend of 100 psi/year after optimization was performed, with current pressure around 2000 psi. The increase in reservoir pressure has also made it possible to optimize ESP, field lifting has increased for 5000 BLPD. This project has also successfully secured XJN remaining oil.\u0000 This project was racing with rapid pressure decline that will lead to early ESP pump off and production loss. The integrated subsurface analytical methods and actions being taken were simple but effective. Close monitoring on reservoir pressure, water injection and ESP parameters will be needed as field surveillance. Integrated analysis with surface facility engineering should also be carried out in the future in regards to surface network, injection rate and reservoir pressure.","PeriodicalId":10970,"journal":{"name":"Day 1 Tue, October 12, 2021","volume":"82 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-10-04","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75371806","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}
Karina Sari, H. Priwanza, Sandi Rizky Kharisma, Rangga Saputra
Mahakam is a mature gas and oil field that has been in operation since 1966, covering an area of approximately 1500 square kilometers. It is located in East Kalimantan Province, Indonesia and has 7 operating fields. Tunu, Tambora and Handil are fields within the swamp shallow water (Delta), whereas Bekapai, Peciko, Sisi Nubi and South Mahakam are offshore fields with water depths ranging from 45 to 80 meters. The diverse setting of environments requires different methods of site preparation, construction, drilling and logistic. The drilling industrialization necessitates agile and complex well preparation especially in the Deltaic environment, with around 70 wells drilled with three swamp barge rigs each year. In recent drilling development in both Tunu and Handil fields, more shallow wells were drilled. These wells were drilled in the swamp with heavy sedimentation and/or sand banks which necessitated a large amount of dredging and required months of preparation whereas the drilling operation took up to 3 days per wells. The entire well preparation process requires planning, monitoring, and the participation of many team in different entities. Each entity has its own version of well planning database, resulting in data disagreement and lack of data integrity. Thousands of emails are being send and meetings are being organized to guarantee that operations runs well. Due to lack of trustworthy data, personnel movement or team reorganization, it has become serious issues. In 2016, company decided to start the digitalization efforts, by approaching various service company who provides the well planning software. It needed customization to match the corporate needs. However since the digitalization has not yet commonly used by most company, it was then not user friendly, thus several individuals were hesitant to utilize it. An internal team created an application in early 2019. As the business requirement & working flowchart, the team decided to have a clean and mobile-ready yet less complicated form that also enables team collaboration during the design. This ensures that all users, employee from any generation (X, Y, and Z) able to use and enter valid information. Equipped with map visualization, the related entities will be able to have better quick analysis on the condition surrounding wellhead position. The application also implements an adjustable workflow system that able to follow the dynamic of organization structure, ensure each of well planning task is assigned to the correct team. Push notifications are also an important element in this application for keeping the entire team up to date. The application also featured a discussion board and file sharing function, allowing each team to exchange information or files. The manual email exchange has been minimized, and the meeting hour has been reduced significantly. The errors are simply identified and fixed in a single integrated database. The application is continuously improved from we
{"title":"Digitalization in Collaborative Framework : Maintain High Quality Drilling Performance in Mahakam's Complex Well Preparation","authors":"Karina Sari, H. Priwanza, Sandi Rizky Kharisma, Rangga Saputra","doi":"10.2118/205729-ms","DOIUrl":"https://doi.org/10.2118/205729-ms","url":null,"abstract":"\u0000 Mahakam is a mature gas and oil field that has been in operation since 1966, covering an area of approximately 1500 square kilometers. It is located in East Kalimantan Province, Indonesia and has 7 operating fields. Tunu, Tambora and Handil are fields within the swamp shallow water (Delta), whereas Bekapai, Peciko, Sisi Nubi and South Mahakam are offshore fields with water depths ranging from 45 to 80 meters. The diverse setting of environments requires different methods of site preparation, construction, drilling and logistic. The drilling industrialization necessitates agile and complex well preparation especially in the Deltaic environment, with around 70 wells drilled with three swamp barge rigs each year. In recent drilling development in both Tunu and Handil fields, more shallow wells were drilled. These wells were drilled in the swamp with heavy sedimentation and/or sand banks which necessitated a large amount of dredging and required months of preparation whereas the drilling operation took up to 3 days per wells.\u0000 The entire well preparation process requires planning, monitoring, and the participation of many team in different entities. Each entity has its own version of well planning database, resulting in data disagreement and lack of data integrity. Thousands of emails are being send and meetings are being organized to guarantee that operations runs well. Due to lack of trustworthy data, personnel movement or team reorganization, it has become serious issues. In 2016, company decided to start the digitalization efforts, by approaching various service company who provides the well planning software. It needed customization to match the corporate needs. However since the digitalization has not yet commonly used by most company, it was then not user friendly, thus several individuals were hesitant to utilize it.\u0000 An internal team created an application in early 2019. As the business requirement & working flowchart, the team decided to have a clean and mobile-ready yet less complicated form that also enables team collaboration during the design. This ensures that all users, employee from any generation (X, Y, and Z) able to use and enter valid information. Equipped with map visualization, the related entities will be able to have better quick analysis on the condition surrounding wellhead position. The application also implements an adjustable workflow system that able to follow the dynamic of organization structure, ensure each of well planning task is assigned to the correct team.\u0000 Push notifications are also an important element in this application for keeping the entire team up to date. The application also featured a discussion board and file sharing function, allowing each team to exchange information or files. The manual email exchange has been minimized, and the meeting hour has been reduced significantly. The errors are simply identified and fixed in a single integrated database. The application is continuously improved from we","PeriodicalId":10970,"journal":{"name":"Day 1 Tue, October 12, 2021","volume":"5 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-10-04","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87512212","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}
Yuzar Aryadi, Azis Hidayat, H. Lazuardi, S. Isnanto, Bonni Ariwibowo, A. Muklas, Ahmad Fathurachman, Ghalib Bima Gema Ramadhan, M. Kamil
SCADA optimization platform is implemented to monitor and evaluate well performance. For Sucker Rod Pump, SCADA Optimization Software can be used to monitor the unit balance and gearbox torque. In some ways, not all required well configuration data for SCADA Optimization Software to do a calculation of counterbalance torque (CBT) for pumping unit balance and gearbox torque evaluation are available. Standard field Counterbalance Effect (CBE) measurement might be performed to calculate the CBT value. However, this standard procedure is limited to well that run on balance condition. For well with unbalance condition, the measured CBE needs to be adjusted by a correction factor which the equation will be presented in this paper. The corrected CBE value from the new equation is then inputted to the SCADA Optimization software to perform day-to-day real-time monitoring of pumping unit balance and gearbox torque. Derivation of the CBE correction factor equation is presented. Validation upon this new equation is performed by comparing the result with electrical measurement on the pumping unit motor. Using the calculated CBT from the new equation, SCADA Optimization Software performs gearbox torque and pumping unit balance analysis based on every collected dynamometer card. Calculated CBT from the new equation provided results in gearbox torque distribution pattern that match with measured electrical parameter distribution along the stroke. This CBT value assists SCADA optimization software to calculate pumping unit balance and gearbox torque. Alarm in the SCADA optimization software that coming from an anomaly on pumping unit balance and gearbox torque help operator to do preventive maintenance so that pumping unit component especially the gearbox could have longer run life.
{"title":"Novel Approach of Sucker Rod Pump Unit Balance Determination and Monitoring","authors":"Yuzar Aryadi, Azis Hidayat, H. Lazuardi, S. Isnanto, Bonni Ariwibowo, A. Muklas, Ahmad Fathurachman, Ghalib Bima Gema Ramadhan, M. Kamil","doi":"10.2118/205579-ms","DOIUrl":"https://doi.org/10.2118/205579-ms","url":null,"abstract":"\u0000 SCADA optimization platform is implemented to monitor and evaluate well performance. For Sucker Rod Pump, SCADA Optimization Software can be used to monitor the unit balance and gearbox torque. In some ways, not all required well configuration data for SCADA Optimization Software to do a calculation of counterbalance torque (CBT) for pumping unit balance and gearbox torque evaluation are available. Standard field Counterbalance Effect (CBE) measurement might be performed to calculate the CBT value. However, this standard procedure is limited to well that run on balance condition. For well with unbalance condition, the measured CBE needs to be adjusted by a correction factor which the equation will be presented in this paper. The corrected CBE value from the new equation is then inputted to the SCADA Optimization software to perform day-to-day real-time monitoring of pumping unit balance and gearbox torque.\u0000 Derivation of the CBE correction factor equation is presented. Validation upon this new equation is performed by comparing the result with electrical measurement on the pumping unit motor. Using the calculated CBT from the new equation, SCADA Optimization Software performs gearbox torque and pumping unit balance analysis based on every collected dynamometer card.\u0000 Calculated CBT from the new equation provided results in gearbox torque distribution pattern that match with measured electrical parameter distribution along the stroke. This CBT value assists SCADA optimization software to calculate pumping unit balance and gearbox torque. Alarm in the SCADA optimization software that coming from an anomaly on pumping unit balance and gearbox torque help operator to do preventive maintenance so that pumping unit component especially the gearbox could have longer run life.","PeriodicalId":10970,"journal":{"name":"Day 1 Tue, October 12, 2021","volume":"16 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-10-04","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84728154","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}
This technical paper presents the offshore installation execution work of Conductor Supported Platforms (CSP) at ‘X’ field. The knowledge sharing was based on the successful installation of three (3) numbers of CSP for ‘X’ development project. The platforms were installed at approximately of 70m water depth and encountered technical challenges during offshore execution. ‘X’ field is located about approximately 45km North West of Miri, Sarawak. The CSPs were installed by Derrick Barge (DB) via double blocks crane upending method for the substructures and conventional lifting method for the topsides. The CSP was designed for 70 meters water depth with four (4) numbers of vertical legs, four (4) numbers of skirt piles, and one (1) number of pin pile. The weight of the topside was about 600MT, meanwhile the substructure was about 1100MT respectively. These CSPs marked as a pioneer in the installation of its kinds at 70m water depth in COMPANY. The concept required high accuracy of detailed offshore installation engineering. This configuration however had caused some challenges during installation. Among the major challenges were issues on the pin-pile verticality, substructure levelness and upending activities via double blocks crane upending method. The effective strategies were adopted to improve the on-bottom stability by installing pin pile prior to substructure set down. The pin pile was installed by utilizing Subsea Fast Frame (SFF), in order to achieve pin pile's verticality. The crucial part during pin pile installation was to ensure meeting the verticality accuracy and minimum tolerance may high potentially impact the substructure install ability and meeting level requirement. However, due to a big annulus gap at pin pile sleeve of the substructure had caused prolong in levelling operation. In order to improve subsequent platforms levelling operations, a set of centralizers were introduced and installed after confirming the pin pile verticality result, in order to reduce the annulus gap. Despite all the challenges aforementioned, the installation of CSPs were completed successfully and most importantly with Zero Lost Time Injury (LTI).
{"title":"Installation of Conductor Supported Platform CSP at X Field","authors":"Helmi Ngadiman","doi":"10.2118/205727-ms","DOIUrl":"https://doi.org/10.2118/205727-ms","url":null,"abstract":"\u0000 This technical paper presents the offshore installation execution work of Conductor Supported Platforms (CSP) at ‘X’ field. The knowledge sharing was based on the successful installation of three (3) numbers of CSP for ‘X’ development project. The platforms were installed at approximately of 70m water depth and encountered technical challenges during offshore execution.\u0000 ‘X’ field is located about approximately 45km North West of Miri, Sarawak. The CSPs were installed by Derrick Barge (DB) via double blocks crane upending method for the substructures and conventional lifting method for the topsides. The CSP was designed for 70 meters water depth with four (4) numbers of vertical legs, four (4) numbers of skirt piles, and one (1) number of pin pile. The weight of the topside was about 600MT, meanwhile the substructure was about 1100MT respectively.\u0000 These CSPs marked as a pioneer in the installation of its kinds at 70m water depth in COMPANY. The concept required high accuracy of detailed offshore installation engineering. This configuration however had caused some challenges during installation. Among the major challenges were issues on the pin-pile verticality, substructure levelness and upending activities via double blocks crane upending method.\u0000 The effective strategies were adopted to improve the on-bottom stability by installing pin pile prior to substructure set down. The pin pile was installed by utilizing Subsea Fast Frame (SFF), in order to achieve pin pile's verticality. The crucial part during pin pile installation was to ensure meeting the verticality accuracy and minimum tolerance may high potentially impact the substructure install ability and meeting level requirement.\u0000 However, due to a big annulus gap at pin pile sleeve of the substructure had caused prolong in levelling operation. In order to improve subsequent platforms levelling operations, a set of centralizers were introduced and installed after confirming the pin pile verticality result, in order to reduce the annulus gap. Despite all the challenges aforementioned, the installation of CSPs were completed successfully and most importantly with Zero Lost Time Injury (LTI).","PeriodicalId":10970,"journal":{"name":"Day 1 Tue, October 12, 2021","volume":"9 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-10-04","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84164022","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}
Hydraulic fracturing is the process by which many unconventional shale reservoirs are produced from. During this process, a highly pressurized fluid, usually water, is injected into the formation with a proppant. The fracturing fluid breaks the formation thus increasing its permeability, and the proppant ensures that the formation remains open. Although highly effective, hydraulic fracturing has several limitations including relying on a highly valuable commodity such as water. This research investigates the applicability of carbon dioxide as a fracturing fluid instead of water, and studies the main advantages and limitation of such a procedure. The main properties that could have a strong impact on the applicability of carbon dioxide based hydraulic fracturing are studied; these factors include carbon dioxide properties, proppant properties, and reservoir rock, fluid, and thermodynamic properties. This research aims to function as an initial introduction and roadmap to future research investigating the applicability of carbon dioxide as a fracturing fluid in unconventional oil and gas reservoirs.
{"title":"Investigating the Use of CO2 as a Hydraulic Fracturing Fluid for Water Sustainability and Environmental Friendliness","authors":"Sherif Fakher, Abdulaziz Fakher","doi":"10.2118/205555-ms","DOIUrl":"https://doi.org/10.2118/205555-ms","url":null,"abstract":"\u0000 Hydraulic fracturing is the process by which many unconventional shale reservoirs are produced from. During this process, a highly pressurized fluid, usually water, is injected into the formation with a proppant. The fracturing fluid breaks the formation thus increasing its permeability, and the proppant ensures that the formation remains open. Although highly effective, hydraulic fracturing has several limitations including relying on a highly valuable commodity such as water. This research investigates the applicability of carbon dioxide as a fracturing fluid instead of water, and studies the main advantages and limitation of such a procedure. The main properties that could have a strong impact on the applicability of carbon dioxide based hydraulic fracturing are studied; these factors include carbon dioxide properties, proppant properties, and reservoir rock, fluid, and thermodynamic properties. This research aims to function as an initial introduction and roadmap to future research investigating the applicability of carbon dioxide as a fracturing fluid in unconventional oil and gas reservoirs.","PeriodicalId":10970,"journal":{"name":"Day 1 Tue, October 12, 2021","volume":"46 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-10-04","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85463994","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}
Tunu is one of the biggest gas fields in Indonesia with 1400 km2 area in Mahakam Delta, East Kalimantan. This field has been producing since 1990 with cumulative production of more than 9.5 tcf and 190 mbbl condensate by the end of 2020 from over 1000 operating wells. Today, Tunu field contributes for approximately 40% of Mahakam production. After 30 years of production, Tunu production level is currently in declining phase, shown by its yearly production profile which exhibits a declining trend since 2008. Furthermore, Tunu well development project was considered marginally economical due to depleting reserve per well. Thus, an integrated study was conducted in order to reduce surface expenditure cost of Tunu pipeline based on current operating parameters. The study consisted of WHSIP history matching to determine new pipeline design pressure, evaluation of future wells production lifetime, and adjustment of pipeline corrosion allowance based on actual corrosion rate observed in Tunu field. Results show that most of future Tunu wells are predicted to have WHSIP below 200 barg and 1.5 to 3 years’ production lifetime. Corrosion rate in Tunu field as measured using corrosion coupon in piping with corrosion inhibitor injection is found to be less than 1 mm/20 years. Therefore, corrosion allowance for Tunu pipeline is optimized from 5 to 3 mm for 10-years design lifetime. For exceptional circumstances where actual well WHSIP > 200 barg, other method of producing the well will be implemented. Hence, by integrating recent subsurface behavior (WHSIP and well lifetime) with surface understanding (corrosion rate), it was then proposed new pipeline design for Tunu development. This study has generated USD 13 million cost saving for pipeline procurement in 2020. Moreover, implementation of the new pipeline design reduces 40% of pipeline unit cost for future pipeline procurement. This study has become the basis for future well development projects in Tunu field which significantly prolong Mahakam's production sustainability.
{"title":"Unlocking Marginal Resources through Synergy between Subsurface and Surface Entities","authors":"Roger Atasi, Albertino Prabowo, Mitterank Siboro","doi":"10.2118/205672-ms","DOIUrl":"https://doi.org/10.2118/205672-ms","url":null,"abstract":"\u0000 Tunu is one of the biggest gas fields in Indonesia with 1400 km2 area in Mahakam Delta, East Kalimantan. This field has been producing since 1990 with cumulative production of more than 9.5 tcf and 190 mbbl condensate by the end of 2020 from over 1000 operating wells. Today, Tunu field contributes for approximately 40% of Mahakam production. After 30 years of production, Tunu production level is currently in declining phase, shown by its yearly production profile which exhibits a declining trend since 2008. Furthermore, Tunu well development project was considered marginally economical due to depleting reserve per well. Thus, an integrated study was conducted in order to reduce surface expenditure cost of Tunu pipeline based on current operating parameters. The study consisted of WHSIP history matching to determine new pipeline design pressure, evaluation of future wells production lifetime, and adjustment of pipeline corrosion allowance based on actual corrosion rate observed in Tunu field. Results show that most of future Tunu wells are predicted to have WHSIP below 200 barg and 1.5 to 3 years’ production lifetime. Corrosion rate in Tunu field as measured using corrosion coupon in piping with corrosion inhibitor injection is found to be less than 1 mm/20 years. Therefore, corrosion allowance for Tunu pipeline is optimized from 5 to 3 mm for 10-years design lifetime. For exceptional circumstances where actual well WHSIP > 200 barg, other method of producing the well will be implemented. Hence, by integrating recent subsurface behavior (WHSIP and well lifetime) with surface understanding (corrosion rate), it was then proposed new pipeline design for Tunu development. This study has generated USD 13 million cost saving for pipeline procurement in 2020. Moreover, implementation of the new pipeline design reduces 40% of pipeline unit cost for future pipeline procurement. This study has become the basis for future well development projects in Tunu field which significantly prolong Mahakam's production sustainability.","PeriodicalId":10970,"journal":{"name":"Day 1 Tue, October 12, 2021","volume":"93 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-10-04","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83477757","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}
Arthur Cheng Ho Ngan, A. Sinha, Harnee Bt Saad, Juhaidi Jaafar
Strategic vision and long-term view of upstream development plan is one of the key directives entrusted to Malaysia Petroleum Management (MPM) to secure sustainable production for the nation. The Sarawak Area Development Planning (SK ADP) is one such critical study aimed at identifying the inventory of hydrocarbon resources, potential outlook on projects' commercial viability, as well as shaping the portfolio mix strategy to deliver the long-term business growth. This SK ADP study also keeps Petroliam Nasional Berhad (PETRONAS) well-positioned to steer Petroleum Arrangement Contractors (PACs) in developing and maximizing the full value of resources. This includes outlining opportunities to collaborate in project sequencing and cost optimization efforts. This paper illustrates the methodology, process workflow and key takeaways from the SK ADP study. The SK ADP study was conducted to establish a development blueprint based on overall available resources and projects' first hydrocarbon sequencing for the short-term and long-term development planning in the Sarawak region. The key objective of the study was to identify the most optimum and technically viable integrated development plans, whilst also incorporating the agreed commitments and existing limitations inclusive of technology application and replications. The process workflow consisted of identifying six focus areas to further enhance the Sarawak Portfolio, maximizing the assets' value and ultimately meeting overall supply and demand requirements. These focus areas act as guiding principles to mature the overall development plan for the area, relating to generating an inventory basket, facilities optimization, clustering strategy, technology evaluation, contaminant management and risk assessment. Cross-discipline integration plays a pivotal role in shaping the final roadmap for each of the focus areas coupled with holistic validation. With the SK ADP in place, it can function as a key reference document and kept updated with the latest developments to maintain PETRONAS' agility in the pursuit of both business sustainability and continuous growth in the region. Key deliverables from this ADP can be turned into actionable insights for field implementation and help boost overall resource management in the region for long-term production delivery. This paper presents the best practices adopted for region level development planning in alignment with strategic vision for business growth.
{"title":"Driving Resource Stewardship to Secure Hydrocarbon Resource Development for Sustainability and Growth in Sarawak Region","authors":"Arthur Cheng Ho Ngan, A. Sinha, Harnee Bt Saad, Juhaidi Jaafar","doi":"10.2118/205743-ms","DOIUrl":"https://doi.org/10.2118/205743-ms","url":null,"abstract":"\u0000 Strategic vision and long-term view of upstream development plan is one of the key directives entrusted to Malaysia Petroleum Management (MPM) to secure sustainable production for the nation. The Sarawak Area Development Planning (SK ADP) is one such critical study aimed at identifying the inventory of hydrocarbon resources, potential outlook on projects' commercial viability, as well as shaping the portfolio mix strategy to deliver the long-term business growth. This SK ADP study also keeps Petroliam Nasional Berhad (PETRONAS) well-positioned to steer Petroleum Arrangement Contractors (PACs) in developing and maximizing the full value of resources. This includes outlining opportunities to collaborate in project sequencing and cost optimization efforts. This paper illustrates the methodology, process workflow and key takeaways from the SK ADP study.\u0000 The SK ADP study was conducted to establish a development blueprint based on overall available resources and projects' first hydrocarbon sequencing for the short-term and long-term development planning in the Sarawak region. The key objective of the study was to identify the most optimum and technically viable integrated development plans, whilst also incorporating the agreed commitments and existing limitations inclusive of technology application and replications. The process workflow consisted of identifying six focus areas to further enhance the Sarawak Portfolio, maximizing the assets' value and ultimately meeting overall supply and demand requirements. These focus areas act as guiding principles to mature the overall development plan for the area, relating to generating an inventory basket, facilities optimization, clustering strategy, technology evaluation, contaminant management and risk assessment. Cross-discipline integration plays a pivotal role in shaping the final roadmap for each of the focus areas coupled with holistic validation.\u0000 With the SK ADP in place, it can function as a key reference document and kept updated with the latest developments to maintain PETRONAS' agility in the pursuit of both business sustainability and continuous growth in the region. Key deliverables from this ADP can be turned into actionable insights for field implementation and help boost overall resource management in the region for long-term production delivery. This paper presents the best practices adopted for region level development planning in alignment with strategic vision for business growth.","PeriodicalId":10970,"journal":{"name":"Day 1 Tue, October 12, 2021","volume":"34 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-10-04","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76623073","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}
Meng Wang, Ming-guang Che, B. Zeng, Yi Song, Yun Jiang, Meng Fan, Yonghui Wang, Xin Wang, G. Zhu, Wei Guo
Application of diversion agents in temporarily plugging fracturing of horizontal wells of shale has becoming more and more popular. Nevertheless, the studies on determining the diverter dosage are below adequacy. A novel approach based on laboratory experiments, logging data, rock mechanics tests and fracture simulation was proposed to optimizing the dosage of diversion agents. The optimization model is based on the classic Darcy Law. A pair of 3D-printed rock plates with rugged faces was combined to simulate the coarse hydraulic fractures with the width of 2.0 ~ 7.0 mm. The mixture of the diversion agents and slickwater was dynamically injected to simulate the fracture in Temco fracture conductivity system to mimic the practical treatment to temporarily plugging the fracture. The permeability of the temporary plugging zone in the 3D-printed fractures was measured in order to optimize the dosage of the selected diversion agents. The value of Pnet (also the value of ΔP in Darcy Formula) required for creation of new branched fractures was determined using the Warpinski-Teufel Failure Rules. The hydraulic fractures of target stages were simulated to obtain the widths and heights. The experimental results proved that the selected suite of the diversion agents can temporarily plug the 3D-printed fractures of 2.0 ~ 7.0 mm with blocking pressure up to 15 MPa. The measured permeability of the resulting plugging zones was 0.724 ~ 0.933 D (averaging 0.837 D). The value of Pnet required for creation of branched fractures in shale of WY area (main shale gas payzone of China) was determined as 0.4 ~ 15.6 MPa (averaging 7.9 MPa) which means the natural fractures and/or weak planes with approaching angle less than 70° could be opened to increase the SRV. The typical dosage of the diversion agents used for one stage of the horizontal wells (averaging TVD 3600 m) was calculated as 232 ~ 310 kg. The optimization method was applied to the design job of temporarily plugging fracturing of two shale gas wells. The observed surface pressure rise after injection of diversion agents was 0.6 ~ 11.7 MPa (averaging 4.7 MPa) and the monitored microseismic events of the test stages were 37% more than those of the offset stages.
{"title":"A Novel Design Method for Optimizing the Diverter Dosage in Hydraulic Fracturing Using Three-Dimensionally Printed Fractures","authors":"Meng Wang, Ming-guang Che, B. Zeng, Yi Song, Yun Jiang, Meng Fan, Yonghui Wang, Xin Wang, G. Zhu, Wei Guo","doi":"10.2118/205779-ms","DOIUrl":"https://doi.org/10.2118/205779-ms","url":null,"abstract":"\u0000 Application of diversion agents in temporarily plugging fracturing of horizontal wells of shale has becoming more and more popular. Nevertheless, the studies on determining the diverter dosage are below adequacy. A novel approach based on laboratory experiments, logging data, rock mechanics tests and fracture simulation was proposed to optimizing the dosage of diversion agents. The optimization model is based on the classic Darcy Law. A pair of 3D-printed rock plates with rugged faces was combined to simulate the coarse hydraulic fractures with the width of 2.0 ~ 7.0 mm. The mixture of the diversion agents and slickwater was dynamically injected to simulate the fracture in Temco fracture conductivity system to mimic the practical treatment to temporarily plugging the fracture. The permeability of the temporary plugging zone in the 3D-printed fractures was measured in order to optimize the dosage of the selected diversion agents. The value of Pnet (also the value of ΔP in Darcy Formula) required for creation of new branched fractures was determined using the Warpinski-Teufel Failure Rules. The hydraulic fractures of target stages were simulated to obtain the widths and heights. The experimental results proved that the selected suite of the diversion agents can temporarily plug the 3D-printed fractures of 2.0 ~ 7.0 mm with blocking pressure up to 15 MPa. The measured permeability of the resulting plugging zones was 0.724 ~ 0.933 D (averaging 0.837 D). The value of Pnet required for creation of branched fractures in shale of WY area (main shale gas payzone of China) was determined as 0.4 ~ 15.6 MPa (averaging 7.9 MPa) which means the natural fractures and/or weak planes with approaching angle less than 70° could be opened to increase the SRV. The typical dosage of the diversion agents used for one stage of the horizontal wells (averaging TVD 3600 m) was calculated as 232 ~ 310 kg. The optimization method was applied to the design job of temporarily plugging fracturing of two shale gas wells. The observed surface pressure rise after injection of diversion agents was 0.6 ~ 11.7 MPa (averaging 4.7 MPa) and the monitored microseismic events of the test stages were 37% more than those of the offset stages.","PeriodicalId":10970,"journal":{"name":"Day 1 Tue, October 12, 2021","volume":"98 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-10-04","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"73075865","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}
京公网安备 11010802042870号
京ICP备2023020795号-1
扫码关注我们
求助内容：
应助结果提醒方式：