Heritage Petroleum Company Limited (HPCL) is the newest operating oil and gas company in Trinidad and Tobago and was vested and entrusted with the operation and management of all the exploration and production assets of Petroleum Company of Trinidad and Tobago Limited ("Petrotrin"). Being driven by oil-based revenue meant that rig intervention projects had to be innovative, economically viable and practical to meet the company’s financial commitments. This paper presents the concepts and processes behind the development and implementation of HPCL’s Workover Scoping and Procurement Framework. The offshore team recognized the need to frame the well review and workover candidate selection process as well as a procurement process that was both operationally accommodating and in accordance with public procurement regulations. This process would also have to be tested, since it was a new concept that was not practiced by Petrotrin. The well review process involved defining reservoir deliverability and in-place volumes through static and dynamic modelling, establishing current well potential and deliverability via nodal analysis with installed completion designs, topside infrastructure conditions and flow restrictions. The procurement process was achieved by identifying local resources and generating framework agreements for services and equipment. Job specific resources were tendered to ensure a transparent selection and award. The process also involved ranking the risks of all candidates. Economic analyses were performed to determine whether the financial indicators were positive to ensure viability of the campaign. A scorpion plot was also used to manage the performance of this framework during the campaign. The result was a campaign consisting of 15 wells that was delivered on time and within the workover budget. Actual production gain was over 1700 BOPD as opposed to the expected gain of 1450 BOPD. Budgeted Net Present Value (NPV) and actual NPV was calculated to be US$ 9.42 million dollars and US$ 11.7 million dollars respectively. All resources were demobilized and removed from the offshore acreage to reduce risks and floating expense to the company at the end of the campaign.
Heritage Petroleum Company Limited (HPCL)是特立尼达和多巴哥最新运营的石油和天然气公司，被授予并受托经营和管理特立尼达和多巴哥有限公司(“Petrotrin”)的所有勘探和生产资产。受石油收入的驱动，钻井干预项目必须具有创新性、经济可行性和实用性，以满足公司的财务承诺。本文介绍了HPCL修井范围和采购框架开发和实施背后的概念和过程。海上团队认识到需要制定井评和修井候选选择流程，以及既能适应操作又符合公共采购法规的采购流程。由于这是Petrotrin没有实践过的新概念，这个过程也必须经过测试。井评过程包括通过静态和动态建模来确定储层的产能和原位体积，通过节点分析确定当前的井潜力和产能，并结合已安装的完井设计、上层基础设施条件和流动限制。采购过程是通过查明当地资源和拟订服务和设备框架协议来完成的。提供特定工作的资源，以确保甄选和授予透明。这个过程还包括对所有候选人的风险进行排名。进行了经济分析，以确定财务指标是否积极，以确保运动的可行性。在竞选期间，还使用了蝎子情节来管理该框架的性能。结果是，15口井的作业按时完成，并在修井预算范围内完成。实际产量增长超过1700桶/天，而不是预期的1450桶/天。预算净现值(NPV)和实际净现值分别为942万美元和1170万美元。在作业结束时，所有资源都被回收并从海上区域移除，以降低公司的风险和浮动费用。
{"title":"Development and Execution of Heritage Petroleum Company Limited’s First Offshore Workover Campaign - A Case History of Successful Implementation of Performance Management","authors":"Shazim K. Mohammed, D. Persad, K. Baksh","doi":"10.2118/200959-ms","DOIUrl":"https://doi.org/10.2118/200959-ms","url":null,"abstract":"\u0000 Heritage Petroleum Company Limited (HPCL) is the newest operating oil and gas company in Trinidad and Tobago and was vested and entrusted with the operation and management of all the exploration and production assets of Petroleum Company of Trinidad and Tobago Limited (\"Petrotrin\"). Being driven by oil-based revenue meant that rig intervention projects had to be innovative, economically viable and practical to meet the company’s financial commitments. This paper presents the concepts and processes behind the development and implementation of HPCL’s Workover Scoping and Procurement Framework.\u0000 The offshore team recognized the need to frame the well review and workover candidate selection process as well as a procurement process that was both operationally accommodating and in accordance with public procurement regulations. This process would also have to be tested, since it was a new concept that was not practiced by Petrotrin.\u0000 The well review process involved defining reservoir deliverability and in-place volumes through static and dynamic modelling, establishing current well potential and deliverability via nodal analysis with installed completion designs, topside infrastructure conditions and flow restrictions.\u0000 The procurement process was achieved by identifying local resources and generating framework agreements for services and equipment. Job specific resources were tendered to ensure a transparent selection and award. The process also involved ranking the risks of all candidates. Economic analyses were performed to determine whether the financial indicators were positive to ensure viability of the campaign. A scorpion plot was also used to manage the performance of this framework during the campaign.\u0000 The result was a campaign consisting of 15 wells that was delivered on time and within the workover budget. Actual production gain was over 1700 BOPD as opposed to the expected gain of 1450 BOPD. Budgeted Net Present Value (NPV) and actual NPV was calculated to be US$ 9.42 million dollars and US$ 11.7 million dollars respectively. All resources were demobilized and removed from the offshore acreage to reduce risks and floating expense to the company at the end of the campaign.","PeriodicalId":11142,"journal":{"name":"Day 3 Wed, June 30, 2021","volume":"8 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-06-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87850659","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 progressive cavity pump (PCP) well (S-648) remotely located in Heritage's offshore field was unable to produce since October 2018 due to high flowline pressures. This paper describes the approach that was taken to produce the well and initiatives undertaken to resolve challenges. Analysis of the fluid properties was conducted for input into a multiphase flow simulation software. The software was utilized to determine flowline restriction and a solution to reducing flowline pressures by viscosity reduction and flowline replacement. Since subsea flowline replacement is a costly and time-consuming exercise, a laboratory viscosity evaluation was done utilizing a chemical viscosity reducer. The results were inputted into the software to determine the percentage reduction in flowline pressure for producing the well. The chemical solution was applied despite multiple challenges. Infrastructure on the location was a challenge with no pneumatic or 110V electrical supply to operate the chemical injection pump, limited space on the well deck for a chemical tank and no access to refill the chemical tank. Initiatives were taken to resolve these challenges and commission the injection. Upon commissioning of the chemical injection system, the flowline pressure reduced by approximately 70% and the well was able to restart and sustain production until this day. The initial chemical injection rate was optimized downwards for reducing the operating costs for the well without increase in the flowline pressure. Testing facilities were not available for this well at start up to quantify production, however pump functionality checks were being done to assure that fluid was moving through the system. The pump is capable of a flowrate of 200 barrels per day. Assuming 80% pump efficiency, the initial estimate of production gain from this initiative was approximately 70 barrels of oil per day. When testing facilities became available in February 2020, the well tested production was 172 barrels of oil per day. This approach can be utilized to start up and produce wells with high flowline pressures in an offshore environment within a short timeframe, where restrictions are present and modifying/replacing flowlines is not possible or cost effective.
{"title":"A Strategic Approach for Producing a PCP Well with High Flowline Pressures in a Restricted System","authors":"Melissa Persad, Nigel Ramkhalawan","doi":"10.2118/200964-ms","DOIUrl":"https://doi.org/10.2118/200964-ms","url":null,"abstract":"\u0000 A progressive cavity pump (PCP) well (S-648) remotely located in Heritage's offshore field was unable to produce since October 2018 due to high flowline pressures. This paper describes the approach that was taken to produce the well and initiatives undertaken to resolve challenges.\u0000 Analysis of the fluid properties was conducted for input into a multiphase flow simulation software. The software was utilized to determine flowline restriction and a solution to reducing flowline pressures by viscosity reduction and flowline replacement. Since subsea flowline replacement is a costly and time-consuming exercise, a laboratory viscosity evaluation was done utilizing a chemical viscosity reducer. The results were inputted into the software to determine the percentage reduction in flowline pressure for producing the well.\u0000 The chemical solution was applied despite multiple challenges. Infrastructure on the location was a challenge with no pneumatic or 110V electrical supply to operate the chemical injection pump, limited space on the well deck for a chemical tank and no access to refill the chemical tank. Initiatives were taken to resolve these challenges and commission the injection. Upon commissioning of the chemical injection system, the flowline pressure reduced by approximately 70% and the well was able to restart and sustain production until this day. The initial chemical injection rate was optimized downwards for reducing the operating costs for the well without increase in the flowline pressure.\u0000 Testing facilities were not available for this well at start up to quantify production, however pump functionality checks were being done to assure that fluid was moving through the system. The pump is capable of a flowrate of 200 barrels per day. Assuming 80% pump efficiency, the initial estimate of production gain from this initiative was approximately 70 barrels of oil per day. When testing facilities became available in February 2020, the well tested production was 172 barrels of oil per day.\u0000 This approach can be utilized to start up and produce wells with high flowline pressures in an offshore environment within a short timeframe, where restrictions are present and modifying/replacing flowlines is not possible or cost effective.","PeriodicalId":11142,"journal":{"name":"Day 3 Wed, June 30, 2021","volume":"93 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-06-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"91305563","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}
Frequent rod failures still occur in Progressive Cavity Pumped (PCP) wells with high dog-leg severities although they are fitted with adequate rod centralization. This results in well downtime and production deferrals. Offshore workovers are expensive and significantly affect operating cost (OPEX) of the operator. This study sought to evaluate the potential benefits of Electrica l Submersible Progressive Cavity Pumps (ESPCP) as an economic alternative for highly deviated wells in the offshore field in Trinidad. In this theoretical study, a screening criterion was established and four (4) candidates, all produced by surface driven PCPs, were selected. Models of ESPCP systems were developed using industry standard Progressive Cavity Pump software, parameters from the original PCP models as well as actual field well tests and production data. An economic evaluation, which integrated oil price and production rate sensitivities, was conducted using field data, including field reservoir characteristics and past well performance. The ESPCP model results suggest a cumulative increase of 567 BOPD is expected for all four wells. Using an oil price of US $45 per barrel, the analysis was conducted on all wells targeted for ESPCP conversion. Assuming a P50 oil rate, sensitivities were run to establish the minimum oil price for the project to be economically feasible. The operator's project economic success criteria were :(1) pay-out period of <2 years and (2) NPV of > US $0.15 Million considering a ten (10) year project. An integrated sensitivity analysis was performed for the entire project with varying expected production increases and fluctuating global oil prices. The simulations identified that the project will be uneconomic at a global oil price of US $20/bbl. Assuming a project life of 10 years and based on the expected production increase, the project is massively profitable, yielding an expected NPV of US $9.3 Million at US $45 per barrel with expected pay-out times between 0.63-1.8 years with investment of US $4 Million. Additional benefits anticipated include, increased well uptime and the corresponding reduction in workover costs. Another opportunity that results from the conversion to ESPCP, is the possibility of lowering the pump in the wellbore, thereby increasing the well producing life and increasing the recoverable reserves. Installation of ESPCPs, in theory, can be an economic success in an area where surface driven PCP experiences repetitive rod failures, leading to production deferrals and workover. Additionally, lowering the pump in the wellbore may be possible, thereby increasing the well producing life and increasing recoverable reserves which would not have been possible using traditional artificial lift methods.
{"title":"ESPCP - An Economic Artificial Lift Method for an Offshore Field in Southwest Trinidad","authors":"Nigel Ramkhalawan, H. Hassanali","doi":"10.2118/200920-ms","DOIUrl":"https://doi.org/10.2118/200920-ms","url":null,"abstract":"\u0000 Frequent rod failures still occur in Progressive Cavity Pumped (PCP) wells with high dog-leg severities although they are fitted with adequate rod centralization. This results in well downtime and production deferrals. Offshore workovers are expensive and significantly affect operating cost (OPEX) of the operator. This study sought to evaluate the potential benefits of Electrica l Submersible Progressive Cavity Pumps (ESPCP) as an economic alternative for highly deviated wells in the offshore field in Trinidad.\u0000 In this theoretical study, a screening criterion was established and four (4) candidates, all produced by surface driven PCPs, were selected. Models of ESPCP systems were developed using industry standard Progressive Cavity Pump software, parameters from the original PCP models as well as actual field well tests and production data. An economic evaluation, which integrated oil price and production rate sensitivities, was conducted using field data, including field reservoir characteristics and past well performance.\u0000 The ESPCP model results suggest a cumulative increase of 567 BOPD is expected for all four wells. Using an oil price of US $45 per barrel, the analysis was conducted on all wells targeted for ESPCP conversion. Assuming a P50 oil rate, sensitivities were run to establish the minimum oil price for the project to be economically feasible. The operator's project economic success criteria were :(1) pay-out period of <2 years and (2) NPV of > US $0.15 Million considering a ten (10) year project. An integrated sensitivity analysis was performed for the entire project with varying expected production increases and fluctuating global oil prices. The simulations identified that the project will be uneconomic at a global oil price of US $20/bbl. Assuming a project life of 10 years and based on the expected production increase, the project is massively profitable, yielding an expected NPV of US $9.3 Million at US $45 per barrel with expected pay-out times between 0.63-1.8 years with investment of US $4 Million. Additional benefits anticipated include, increased well uptime and the corresponding reduction in workover costs. Another opportunity that results from the conversion to ESPCP, is the possibility of lowering the pump in the wellbore, thereby increasing the well producing life and increasing the recoverable reserves.\u0000 Installation of ESPCPs, in theory, can be an economic success in an area where surface driven PCP experiences repetitive rod failures, leading to production deferrals and workover. Additionally, lowering the pump in the wellbore may be possible, thereby increasing the well producing life and increasing recoverable reserves which would not have been possible using traditional artificial lift methods.","PeriodicalId":11142,"journal":{"name":"Day 3 Wed, June 30, 2021","volume":"33 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-06-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82438959","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. Khaja, S. Raturi, Abhijit Dutta, Hassan Z. Haddad, Rajinder P Singh, Basavaraj Kunchur, Khadar Hussain, Husain Nasir, Mustafa Ahmed, Musaed Al Shamali, Jené Rockwood, Victor Barsoum
A new and enhanced microfine cement system is presented in this paper which can be used in challenging cement squeeze applications. There are numerous cement squeeze jobs conducted during workover operations every year within the State of Kuwait to prevent water influx. A very common challenge encountered during these applications is either low or no injectivity scenarios. Conventional cement slurries at 15.8-lb/gal density have more often than not resulted in failures while performing post job positive and negative pressure tests, even when the pressure tests are repeated multiple times. These failures can often be attributed to the fact that effective squeezing is not possible due to the larger cement particle size across a limited number of perforations due to early bridging of the cement. Similarly, conventional microfine cement systems which have also been used in these applications have had only limited success. To overcome these challenges, an improved and enhanced microfine cement design has been developed which is able to obtain higher compressive strengths at lower slurry densities (e.g. 12.5 to 13.0 lb/gal) versus the 15.8-lb/gal conventional slurries. This microfine cement design can be further modified to be used in high, low, and zero injectivity scenarios. It possesses several unique features including thixotropic, expansion, anti-gas migration, and strength retrogression properties. Initial field trials of the system have been very successful. The application of conventional microfine slurry systems in low injectivity scenarios is relatively common in the industry; however the enhanced microfine slurry design can be utilized in a variety of injectivity scenarios, or even in loss situations across perforations, casing leaks, or across the casing shoe. The new microfine cement slurry design has the potential of avoiding multiple squeeze jobs by achieving successful positive and negative pressure test results in a minimum number of attempts.
{"title":"An Enhanced Microfine Cement Design for Special Squeeze Applications","authors":"M. Khaja, S. Raturi, Abhijit Dutta, Hassan Z. Haddad, Rajinder P Singh, Basavaraj Kunchur, Khadar Hussain, Husain Nasir, Mustafa Ahmed, Musaed Al Shamali, Jené Rockwood, Victor Barsoum","doi":"10.2118/200946-ms","DOIUrl":"https://doi.org/10.2118/200946-ms","url":null,"abstract":"\u0000 A new and enhanced microfine cement system is presented in this paper which can be used in challenging cement squeeze applications.\u0000 There are numerous cement squeeze jobs conducted during workover operations every year within the State of Kuwait to prevent water influx. A very common challenge encountered during these applications is either low or no injectivity scenarios. Conventional cement slurries at 15.8-lb/gal density have more often than not resulted in failures while performing post job positive and negative pressure tests, even when the pressure tests are repeated multiple times. These failures can often be attributed to the fact that effective squeezing is not possible due to the larger cement particle size across a limited number of perforations due to early bridging of the cement. Similarly, conventional microfine cement systems which have also been used in these applications have had only limited success.\u0000 To overcome these challenges, an improved and enhanced microfine cement design has been developed which is able to obtain higher compressive strengths at lower slurry densities (e.g. 12.5 to 13.0 lb/gal) versus the 15.8-lb/gal conventional slurries. This microfine cement design can be further modified to be used in high, low, and zero injectivity scenarios. It possesses several unique features including thixotropic, expansion, anti-gas migration, and strength retrogression properties. Initial field trials of the system have been very successful.\u0000 The application of conventional microfine slurry systems in low injectivity scenarios is relatively common in the industry; however the enhanced microfine slurry design can be utilized in a variety of injectivity scenarios, or even in loss situations across perforations, casing leaks, or across the casing shoe.\u0000 The new microfine cement slurry design has the potential of avoiding multiple squeeze jobs by achieving successful positive and negative pressure test results in a minimum number of attempts.","PeriodicalId":11142,"journal":{"name":"Day 3 Wed, June 30, 2021","volume":"46 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-06-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89938522","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 publication presents how 4D seismic and reservoir simulation techniques were used to optimise the trajectory of an infill production well in a producing oil field. The A6 infill well target in Field X offshore Nigeria was planned as a 12000 feet horizontal drill well with a 4900 feet gravel pack completion in the reservoir formation. The initial well trajectory delivered early water breakthrough and low oil recovery. The well planning team resolved the issue by reconciling the well trajectory and completion data in the geologic and reservoir simulation models, and used 4D seismic difference maps to validate the infill drilling target. Alternative well trajectories were then simulated to improve reservoir penetration and to place the well up-structure and away from the current oil water contact. The optimised well trajectory increased the incremental oil recovery from 1.8 MMSTB to 3.0 MMSTB, and significantly boosted the project economics. The well came online in 2016, and delivered higher oil rates than the forecast. 4D seismic and reservoir simulation techniques optimised the infill well trajectory, delayed water breakthrough, and maximised oil recovery. Nearby wells can be shut in during drilling operations to minimise the risk of drilling losses and well integrity failures. Oil asset net present value can also be preserved and boosted with water injection performance monitoring, zonal testing, short circuit diagnosis and remediation, and water shut off work-overs. This paper presents a case study of an infill production well placement optimised with 4D seismic and reservoir simulation tools, and simplifies the infill well placement value creation process.
{"title":"Maximising Infill Well Oil Recovery with 4D Seismic and Reservoir Simulation","authors":"B. Daramola","doi":"10.2118/200969-ms","DOIUrl":"https://doi.org/10.2118/200969-ms","url":null,"abstract":"\u0000 This publication presents how 4D seismic and reservoir simulation techniques were used to optimise the trajectory of an infill production well in a producing oil field. The A6 infill well target in Field X offshore Nigeria was planned as a 12000 feet horizontal drill well with a 4900 feet gravel pack completion in the reservoir formation. The initial well trajectory delivered early water breakthrough and low oil recovery. The well planning team resolved the issue by reconciling the well trajectory and completion data in the geologic and reservoir simulation models, and used 4D seismic difference maps to validate the infill drilling target. Alternative well trajectories were then simulated to improve reservoir penetration and to place the well up-structure and away from the current oil water contact.\u0000 The optimised well trajectory increased the incremental oil recovery from 1.8 MMSTB to 3.0 MMSTB, and significantly boosted the project economics. The well came online in 2016, and delivered higher oil rates than the forecast. 4D seismic and reservoir simulation techniques optimised the infill well trajectory, delayed water breakthrough, and maximised oil recovery. Nearby wells can be shut in during drilling operations to minimise the risk of drilling losses and well integrity failures. Oil asset net present value can also be preserved and boosted with water injection performance monitoring, zonal testing, short circuit diagnosis and remediation, and water shut off work-overs. This paper presents a case study of an infill production well placement optimised with 4D seismic and reservoir simulation tools, and simplifies the infill well placement value creation process.","PeriodicalId":11142,"journal":{"name":"Day 3 Wed, June 30, 2021","volume":"70 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-06-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85900616","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}
An attempt was made to independently verify the proposed performance of the Liza 1 field using only data available in the public domain. The data used in modelling was sourced from news reports, company disclosures and the analogue Jubilee field in Ghana. Reservoir rock and fluid data from Jubilee Field was deemed an appropriate fit because of the corroboration provided by the Atlantic Drift Theory. A major challenge in creating the model, was determining the aerial extent of the field. According to Yang and Escalona (2011), the subsurface can be reasonably approximated using the surface topography which is possible via the use of GIS software. Google Earth Pro software was used to estimate the coordinates and areal extent of the Liza 1 reservoir. A scaled image of the field location showing the Guyana coastline was re-sized to fit the coastline in Google Pro and then the coordinates for the Liza field and wildcat well locations were estimated. This was used to create the isopach map and set reservoir boundaries to create the static and dynamic models in Schlumberger's Petrel E & P Software Platform (2017) and Computer Modelling Group IMEX Black Oil and Unconventional Simulator CMG IMEX (2016). The initialized model investigated the reservoir performance with and without pressure maintenance over a twenty (20) year period. The original oil in place (OOIP) estimated by the model was 7% larger than the OOIP estimated by ExxonMobil for Liza field. The model produced 35% of the OOIP compared to 50% of OOIP as forecasted by the operators. (See Table 1). The factors that strongly influenced this outcome were, the well positioning and the water injection rates. A significant percentage of the oil remained unproduced in the lower layers of the model after the 20-year period. Time did not permit further modelling to improve the performance of the model. Table 1 Comparison of The Created Model and ExxonMobil's Proposal for Liza. Property ExxonMobil's statement on Liza field Modelled field Result Original Oil in Place (MMbbl) 896 967 Oil Recovery Factor (%) 50 35 Gas production from the model would be used as gas injection from three injector wells and as fuel for the proposed 200 MW power plant for Guyana. Even so, significant volumes of natural gas remained unallocated and subsequently a valuable resource may have to be flared.
{"title":"An Independent Analysis of the Performance Characteristics and Economic Outcomes of the Liza Phase 1 Development Offshore Guyana Using Public Domain Data","authors":"S. Paul, Kadija Dyall, Quinn Gabriel","doi":"10.2118/200951-ms","DOIUrl":"https://doi.org/10.2118/200951-ms","url":null,"abstract":"\u0000 An attempt was made to independently verify the proposed performance of the Liza 1 field using only data available in the public domain. The data used in modelling was sourced from news reports, company disclosures and the analogue Jubilee field in Ghana. Reservoir rock and fluid data from Jubilee Field was deemed an appropriate fit because of the corroboration provided by the Atlantic Drift Theory.\u0000 A major challenge in creating the model, was determining the aerial extent of the field. According to Yang and Escalona (2011), the subsurface can be reasonably approximated using the surface topography which is possible via the use of GIS software. Google Earth Pro software was used to estimate the coordinates and areal extent of the Liza 1 reservoir. A scaled image of the field location showing the Guyana coastline was re-sized to fit the coastline in Google Pro and then the coordinates for the Liza field and wildcat well locations were estimated. This was used to create the isopach map and set reservoir boundaries to create the static and dynamic models in Schlumberger's Petrel E & P Software Platform (2017) and Computer Modelling Group IMEX Black Oil and Unconventional Simulator CMG IMEX (2016).\u0000 The initialized model investigated the reservoir performance with and without pressure maintenance over a twenty (20) year period. The original oil in place (OOIP) estimated by the model was 7% larger than the OOIP estimated by ExxonMobil for Liza field. The model produced 35% of the OOIP compared to 50% of OOIP as forecasted by the operators. (See Table 1). The factors that strongly influenced this outcome were, the well positioning and the water injection rates. A significant percentage of the oil remained unproduced in the lower layers of the model after the 20-year period. Time did not permit further modelling to improve the performance of the model.\u0000 Table 1 Comparison of The Created Model and ExxonMobil's Proposal for Liza. Property ExxonMobil's statement on Liza field Modelled field Result Original Oil in Place (MMbbl) 896 967 Oil Recovery Factor (%) 50 35\u0000 Gas production from the model would be used as gas injection from three injector wells and as fuel for the proposed 200 MW power plant for Guyana. Even so, significant volumes of natural gas remained unallocated and subsequently a valuable resource may have to be flared.","PeriodicalId":11142,"journal":{"name":"Day 3 Wed, June 30, 2021","volume":"33 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-06-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84570494","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}
Reservoir management best practices originate from efficient well operations. The fluid flow profile from individual wells can change over time, sometimes unpredictably; as the reservoirs become depleted, changes in hydrocarbon properties occur, and water cut begins to increase. During primary, secondary, and tertiary recovery from conventional and unconventional wells, production surveillance is pivotal for optimum reservoir management. Determining the downhole production flow profile from multiple zones helps to manage drawdown pressure, regulate surface choke settings, and mitigate excessive water production. This paper presents a rigorous mechanistic analysis of the heat transfer and fluid flow around the wellbore to aid in determining a generalized wellbore flow profile. The approach enables the calculation of multiphase rates independently of downhole spinner data and is based almost solely on temperature measurements. Because temperature measurements are reliable and more commonly available, the method provides a robust technique to determine flow contributions across a broad spectrum of surveillance applications. The technique is shown to work with other logs, such as capacitance, fluid density, and gas holdup tool, to relay more refined information about fluid phases during production. The methodology presents an application of transient-temperature modeling for computing flow rates from temperature data obtained during a wireline run. The approach includes an analytical wellbore fluid transient-temperature model. Temperature calculations depend on mass flow rate and flow duration; therefore, an inversion technique is applied to match the measured temperature and calculated temperature for a given time duration to estimate flow rate. The model is observed to depend on determining an accurate geothermal gradient, particularly in cases of early time flow. The various heat transfer resistances in the system are calculated based on the completion mechanics. The method also accounts for the effect of friction and pressure drop in the wellbore on fluid temperature. The case study included demonstrates the utility and value of the transient model. The transient nature of the model also facilitates multiple applications. Real-time flow rate monitoring, zonal contributions, flow behind casing, quantitative determination of leaks, and completion integrity are all potential applications of the proposed method. The transient-temperature modeling methodology can be used with production logging spinners to calibrate the model and provide a permanent downhole monitoring tool to help avoid costly logging reruns. The study provides a foundation for various applications arising from conventional production logging measurements and could be particularly useful in cases, such as offshore fields, where more evolved unconventional techniques can be difficult and costly to apply.
{"title":"Simulating Downhole Temperature Logging Data for Optimum Downhole Production Surveillance","authors":"G. M. Hashmi, Farrukh Hamza, M. Azari","doi":"10.2118/200914-ms","DOIUrl":"https://doi.org/10.2118/200914-ms","url":null,"abstract":"\u0000 Reservoir management best practices originate from efficient well operations. The fluid flow profile from individual wells can change over time, sometimes unpredictably; as the reservoirs become depleted, changes in hydrocarbon properties occur, and water cut begins to increase. During primary, secondary, and tertiary recovery from conventional and unconventional wells, production surveillance is pivotal for optimum reservoir management. Determining the downhole production flow profile from multiple zones helps to manage drawdown pressure, regulate surface choke settings, and mitigate excessive water production.\u0000 This paper presents a rigorous mechanistic analysis of the heat transfer and fluid flow around the wellbore to aid in determining a generalized wellbore flow profile. The approach enables the calculation of multiphase rates independently of downhole spinner data and is based almost solely on temperature measurements. Because temperature measurements are reliable and more commonly available, the method provides a robust technique to determine flow contributions across a broad spectrum of surveillance applications. The technique is shown to work with other logs, such as capacitance, fluid density, and gas holdup tool, to relay more refined information about fluid phases during production.\u0000 The methodology presents an application of transient-temperature modeling for computing flow rates from temperature data obtained during a wireline run. The approach includes an analytical wellbore fluid transient-temperature model. Temperature calculations depend on mass flow rate and flow duration; therefore, an inversion technique is applied to match the measured temperature and calculated temperature for a given time duration to estimate flow rate. The model is observed to depend on determining an accurate geothermal gradient, particularly in cases of early time flow. The various heat transfer resistances in the system are calculated based on the completion mechanics. The method also accounts for the effect of friction and pressure drop in the wellbore on fluid temperature. The case study included demonstrates the utility and value of the transient model. The transient nature of the model also facilitates multiple applications. Real-time flow rate monitoring, zonal contributions, flow behind casing, quantitative determination of leaks, and completion integrity are all potential applications of the proposed method.\u0000 The transient-temperature modeling methodology can be used with production logging spinners to calibrate the model and provide a permanent downhole monitoring tool to help avoid costly logging reruns. The study provides a foundation for various applications arising from conventional production logging measurements and could be particularly useful in cases, such as offshore fields, where more evolved unconventional techniques can be difficult and costly to apply.","PeriodicalId":11142,"journal":{"name":"Day 3 Wed, June 30, 2021","volume":"62 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-06-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90854497","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}
L. Liebana, Lee J. Thomas, T. Wood, Liyun Lao, Graeme Rogerson
Pseudo Dry Gas (PDG) technology is proposed as an alternative concept for transporting multiphase fluids (gas, condensate and water) for long deep-water subsea tieback developments (Ref 1 - OTC-28949-MS) (Ref 2 - IPTC-19440-MS). Using PDG technology, subsea pipeline networks can be extended to excess of 200 km total length and considerably reduce the backpressure on the wells. This allows improved recovery of the reserves and the ability to reach currently stranded fields, especially deep-water lower-pressure gas fields. The basis of the PDG system is to remove the liquid of the main pipeline system using Piggable Liquid Removal Units. With the removal of the liquid, the gravitational pressure losses in the system are eliminated allowing the pipeline to operate like a "Pseudo" Dry Gas system. The liquid phase is transported back to shore using a second smaller pipeline running in parallel to the main pipeline by means of subsea liquid pumps (Ref 3 - OTC-29332-MS). After techno-economic reports were completed for a known basin of stranded gas in the West of Shetland, an Oil and Gas Technology Centre (OGTC) experimental project was established to determine the operation performance of the element within the PDG technology with lowest Technology Readiness Level (TRL). Currently the liquid removal unit has a TRL2 and a TRL4 will be achieved after the experimental testing programme has been fully completed. This paper assesses the separation performance (Efficiency) of the Piggable Liquid Units or PDG unit. Previous Flow Assurance and Computational Fluid Dynamics (CFD) established expected efficiencies between 84-99% depending on the gas and liquid flow rates and other factors such as unit orientation, liquid type, operating pressure and temperature. Each PDG unit has two modules which allow for gas-liquid separation of the multiphase fluid in the pipeline. A PDG unit prototype has been built and a testing programme has been developed and undertaken in collaboration with Cranfield University (CU) using the large scale Inclinable Multip hase Flow Loop facilities. The testing programme has two test matrices: Matrix 1 which studies the performance of a single module of the PDG unit and Matrix 2 which investigates the efficienc y of the entire PDG unit (two separation modules). Matrix 1 of the testing programme allows to characterise the system varying the flow conditions (flow regime, liquid and gas flow rates), drop out liquid level and size, effect of sand and the inclination and orientation of the unit as would be expected once installed. This paper focuses on the results obtained from Matrix 1 testing programme and compares them with the initia l PDG unit estimated efficiency values used in previous studies to demonstrate the prove of concept of the PDG technology. The overall conclusion is that the performance of the PDG liquid removal unit is greater than the ones originally used in technology assessment reports.
{"title":"Experimental Separation Performance of In-Line Piggable Liquid Removal Unit – Pseudo Dry Gas Systems","authors":"L. Liebana, Lee J. Thomas, T. Wood, Liyun Lao, Graeme Rogerson","doi":"10.2118/200917-ms","DOIUrl":"https://doi.org/10.2118/200917-ms","url":null,"abstract":"\u0000 Pseudo Dry Gas (PDG) technology is proposed as an alternative concept for transporting multiphase fluids (gas, condensate and water) for long deep-water subsea tieback developments (Ref 1 - OTC-28949-MS) (Ref 2 - IPTC-19440-MS). Using PDG technology, subsea pipeline networks can be extended to excess of 200 km total length and considerably reduce the backpressure on the wells. This allows improved recovery of the reserves and the ability to reach currently stranded fields, especially deep-water lower-pressure gas fields.\u0000 The basis of the PDG system is to remove the liquid of the main pipeline system using Piggable Liquid Removal Units. With the removal of the liquid, the gravitational pressure losses in the system are eliminated allowing the pipeline to operate like a \"Pseudo\" Dry Gas system. The liquid phase is transported back to shore using a second smaller pipeline running in parallel to the main pipeline by means of subsea liquid pumps (Ref 3 - OTC-29332-MS).\u0000 After techno-economic reports were completed for a known basin of stranded gas in the West of Shetland, an Oil and Gas Technology Centre (OGTC) experimental project was established to determine the operation performance of the element within the PDG technology with lowest Technology Readiness Level (TRL). Currently the liquid removal unit has a TRL2 and a TRL4 will be achieved after the experimental testing programme has been fully completed. This paper assesses the separation performance (Efficiency) of the Piggable Liquid Units or PDG unit. Previous Flow Assurance and Computational Fluid Dynamics (CFD) established expected efficiencies between 84-99% depending on the gas and liquid flow rates and other factors such as unit orientation, liquid type, operating pressure and temperature.\u0000 Each PDG unit has two modules which allow for gas-liquid separation of the multiphase fluid in the pipeline. A PDG unit prototype has been built and a testing programme has been developed and undertaken in collaboration with Cranfield University (CU) using the large scale Inclinable Multip hase Flow Loop facilities. The testing programme has two test matrices: Matrix 1 which studies the performance of a single module of the PDG unit and Matrix 2 which investigates the efficienc y of the entire PDG unit (two separation modules). Matrix 1 of the testing programme allows to characterise the system varying the flow conditions (flow regime, liquid and gas flow rates), drop out liquid level and size, effect of sand and the inclination and orientation of the unit as would be expected once installed. This paper focuses on the results obtained from Matrix 1 testing programme and compares them with the initia l PDG unit estimated efficiency values used in previous studies to demonstrate the prove of concept of the PDG technology. The overall conclusion is that the performance of the PDG liquid removal unit is greater than the ones originally used in technology assessment reports.","PeriodicalId":11142,"journal":{"name":"Day 3 Wed, June 30, 2021","volume":"25 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-06-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"72789141","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}
Global warming is one of the most significant issues the world is facing. Capturing carbon dioxide from the atmosphere or industrial processes and storing it in geological formations (carbon capture and storage, CCS) can help counteract climate change. Nevertheless, the interaction between well barrier elements such as cement, casing, tubulars, packers, and valves can lead to possible leakages. To accomplish successful carbon dioxide sequestration, injecting the carbon dioxide in its supercritical state is necessary. The supercritical carbon dioxide can corrode steel and elastomers and react with the calcium compounds in the cement, dissolving them and forming calcium carbonate and bicarbonate in the process. This carbonation can lead to channels forming on the cement-to-rock interface or cracking due to the carbonate precipitation, resulting in a loss of well integrity. This study focusses on finding ways that enable the continuous monitoring of cement integrity, under in-situ conditions, in a lab setup. The construction of an autoclave, capable of withstanding supercritical conditions of carbon dioxide, facilitates the in-situ monitoring. This autoclave also makes CT-scans of the pressurized sample possible, as well as acoustic measurements, using state-of-the-art piezo elements. The first tests will establish a baseline using neat Class G Portland cement to verify the design and sensors. The set up consists of a rock core in the middle of the autoclave surrounded by a cement sheath. A prepared channel in the center of the core expedites the distribution of the carbon dioxide. Once the ability of the sensors to monitor the integrity is verified, different cement compositions and their interaction with supercritical carbon dioxide can be studied. The experimental setup and the procedure discussed here closely simulate the downhole condition. Hence, the results obtained using this setup and procedure is representative of what could be observed downhole. The direction is not to remove the sample from the autoclave for analysis, as is the current industry practice, but to measure cement integrity under in-situ conditions over an extended period of time. Digitalization is powering the in-situ analysis in these tests. The first two tests of this study, using the afore mentioned autoclave, investigated the carbonation behaviour of two Class G Portland cement slurrys, one with a low and one with a high slurry-density. The low-density slurry showed extensive degradation and even the high-density slurry showed carbonation, but only close to the sandstone core. The results from this study can lead to the prevention of leakage of carbon dioxide to the environment and other formations, which defeats the purpose of carbon dioxide sequestration. These results should improve the economics of these wells as well as the health, safety, and environmental aspects.
{"title":"Real-Time Monitoring of the Effect of CO2 on the Cement Sheath","authors":"P. Wagner, K. Ravi, M. Prohaska","doi":"10.2118/200931-ms","DOIUrl":"https://doi.org/10.2118/200931-ms","url":null,"abstract":"\u0000 Global warming is one of the most significant issues the world is facing. Capturing carbon dioxide from the atmosphere or industrial processes and storing it in geological formations (carbon capture and storage, CCS) can help counteract climate change. Nevertheless, the interaction between well barrier elements such as cement, casing, tubulars, packers, and valves can lead to possible leakages. To accomplish successful carbon dioxide sequestration, injecting the carbon dioxide in its supercritical state is necessary. The supercritical carbon dioxide can corrode steel and elastomers and react with the calcium compounds in the cement, dissolving them and forming calcium carbonate and bicarbonate in the process. This carbonation can lead to channels forming on the cement-to-rock interface or cracking due to the carbonate precipitation, resulting in a loss of well integrity.\u0000 This study focusses on finding ways that enable the continuous monitoring of cement integrity, under in-situ conditions, in a lab setup. The construction of an autoclave, capable of withstanding supercritical conditions of carbon dioxide, facilitates the in-situ monitoring. This autoclave also makes CT-scans of the pressurized sample possible, as well as acoustic measurements, using state-of-the-art piezo elements. The first tests will establish a baseline using neat Class G Portland cement to verify the design and sensors. The set up consists of a rock core in the middle of the autoclave surrounded by a cement sheath. A prepared channel in the center of the core expedites the distribution of the carbon dioxide. Once the ability of the sensors to monitor the integrity is verified, different cement compositions and their interaction with supercritical carbon dioxide can be studied.\u0000 The experimental setup and the procedure discussed here closely simulate the downhole condition. Hence, the results obtained using this setup and procedure is representative of what could be observed downhole. The direction is not to remove the sample from the autoclave for analysis, as is the current industry practice, but to measure cement integrity under in-situ conditions over an extended period of time. Digitalization is powering the in-situ analysis in these tests.\u0000 The first two tests of this study, using the afore mentioned autoclave, investigated the carbonation behaviour of two Class G Portland cement slurrys, one with a low and one with a high slurry-density. The low-density slurry showed extensive degradation and even the high-density slurry showed carbonation, but only close to the sandstone core.\u0000 The results from this study can lead to the prevention of leakage of carbon dioxide to the environment and other formations, which defeats the purpose of carbon dioxide sequestration. These results should improve the economics of these wells as well as the health, safety, and environmental aspects.","PeriodicalId":11142,"journal":{"name":"Day 3 Wed, June 30, 2021","volume":"338 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-06-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90476674","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}
Oswaldo Espinola Gonzalez, Laura Paola Vazquez Macedo, Julio Cesar Villanueva Alonso, Julieta Alvarez Martínez
The proper exploitation for a gas condensate reservoir requires an integrated collaboration and management strategy capable to provide detailed insight about future behavior of the reservoir. When a development plan is generated for a field, the reservoir management is not performed integrally, this is, different domains: geology, reservoir, drilling, production, economics, etc., work separately, and therefore, an adequate understanding of the main challenges, leading to issues such as an over dimensioning of surface facilities, excessive costs, among others. Through this paper, a methodology to improve the conventional field development plan is described, which contains 4 main pillars: Collaborative approach, Integrated analysis, engineering optimization and monitoring & surveillance. The methodology involves the description of a hybrid workflow based on the integration of multiple domains, technologies and recommendations to consider all the phenomena and compositional changes over time in the whole production system, aiming to define the optimum reservoir management strategy, facilities and operational philosophy as part of the Field Development Plan (FDP). Conventionally, the used of simplistic models most of times do not allow seeing phenomena in the adequate resolution (near wellbore and porous media effects, multiphase flow in pipelines, etc.), that occur with high interdependency in the Integrated Production System. With this methodology, the goal pursued is to support oil and gas companies to increase the recovery factor of gas condensate fields through the enhancement in the development and exploitation process and therefore, reducing associated costs and seizing available time and resources.
{"title":"Novel Approach to Enhance Field Development Plan Process and Reservoir Management to Maximize the Recovery Factor of Gas Condensate Reservoirs Through Integrated Asset Modeling","authors":"Oswaldo Espinola Gonzalez, Laura Paola Vazquez Macedo, Julio Cesar Villanueva Alonso, Julieta Alvarez Martínez","doi":"10.2118/200895-ms","DOIUrl":"https://doi.org/10.2118/200895-ms","url":null,"abstract":"\u0000 The proper exploitation for a gas condensate reservoir requires an integrated collaboration and management strategy capable to provide detailed insight about future behavior of the reservoir.\u0000 When a development plan is generated for a field, the reservoir management is not performed integrally, this is, different domains: geology, reservoir, drilling, production, economics, etc., work separately, and therefore, an adequate understanding of the main challenges, leading to issues such as an over dimensioning of surface facilities, excessive costs, among others.\u0000 Through this paper, a methodology to improve the conventional field development plan is described, which contains 4 main pillars: Collaborative approach, Integrated analysis, engineering optimization and monitoring & surveillance.\u0000 The methodology involves the description of a hybrid workflow based on the integration of multiple domains, technologies and recommendations to consider all the phenomena and compositional changes over time in the whole production system, aiming to define the optimum reservoir management strategy, facilities and operational philosophy as part of the Field Development Plan (FDP). Conventionally, the used of simplistic models most of times do not allow seeing phenomena in the adequate resolution (near wellbore and porous media effects, multiphase flow in pipelines, etc.), that occur with high interdependency in the Integrated Production System.\u0000 With this methodology, the goal pursued is to support oil and gas companies to increase the recovery factor of gas condensate fields through the enhancement in the development and exploitation process and therefore, reducing associated costs and seizing available time and resources.","PeriodicalId":11142,"journal":{"name":"Day 3 Wed, June 30, 2021","volume":"31 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2021-06-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87418449","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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