Liang Tao, Y. Qi, M. Tang, Kai Ye, Deyu Wang, Mirinuer Halifu, Yuhang Zhao
The continental shale oil reservoirs usually have strong heterogeneity, which make the law of fracture propagation extremely complex, and the quantitative characterization of fracture network swept volume brings great challenges. In this paper, firstly, the grey correlation analysis method is used to calculate the correlation coefficient between different parameters and microseismic monitoring volume (SRV), and the key factors affecting SRV are identified. Secondly, the relationship between key geological engineering parameters and SRV is established by using the method of multiple linear regression, and the relationship is further corrected by productivity numerical simulation method, and the empirical formula for quantitative characterization of fracture network swept volume(FSV) is established. Finally, according to the field production of big data, the fitting chart of the accumulated oil production and the FSV is established, and the production of horizontal well is further predicted according to the fitting formula. The study results shown that the main factors affecting the SRV were fracturing fluid volume, fracture density, brittleness index, pump rate, horizontal stress difference, net pay thickness and proppant amount.The FSV in the study area was positively correlated with the cumulative oil production of the horizontal well. With the increase of the FSV, the accumulated oil production increased at first and then tended to be stable, and the optimal FSV was 760 ~ 850*104m3. The prediction method was verified by the typical platform in the field to be accurate and reliable. It can provide scientific basis for the productivity prediction of horizontal wells in shale oil reservoirs.
{"title":"A New Approach for Multi-Fractured Horizontal Wells Productivity Prediction in Shale Oil Reservoirs","authors":"Liang Tao, Y. Qi, M. Tang, Kai Ye, Deyu Wang, Mirinuer Halifu, Yuhang Zhao","doi":"10.2523/iptc-23019-ea","DOIUrl":"https://doi.org/10.2523/iptc-23019-ea","url":null,"abstract":"\u0000 The continental shale oil reservoirs usually have strong heterogeneity, which make the law of fracture propagation extremely complex, and the quantitative characterization of fracture network swept volume brings great challenges. In this paper, firstly, the grey correlation analysis method is used to calculate the correlation coefficient between different parameters and microseismic monitoring volume (SRV), and the key factors affecting SRV are identified. Secondly, the relationship between key geological engineering parameters and SRV is established by using the method of multiple linear regression, and the relationship is further corrected by productivity numerical simulation method, and the empirical formula for quantitative characterization of fracture network swept volume(FSV) is established. Finally, according to the field production of big data, the fitting chart of the accumulated oil production and the FSV is established, and the production of horizontal well is further predicted according to the fitting formula. The study results shown that the main factors affecting the SRV were fracturing fluid volume, fracture density, brittleness index, pump rate, horizontal stress difference, net pay thickness and proppant amount.The FSV in the study area was positively correlated with the cumulative oil production of the horizontal well. With the increase of the FSV, the accumulated oil production increased at first and then tended to be stable, and the optimal FSV was 760 ~ 850*104m3. The prediction method was verified by the typical platform in the field to be accurate and reliable. It can provide scientific basis for the productivity prediction of horizontal wells in shale oil reservoirs.","PeriodicalId":283978,"journal":{"name":"Day 1 Wed, March 01, 2023","volume":"74 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"115147256","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}
As one of the largest discovered gas fields in China, Kela 2 gas field has proven geological reserves of more than 200 billion cubic meters, with a maximum annual gas production of approximately 12 billion cubic meters. After 18 years development, Kela 2 gas field is now in the middle-late development period. At present, the gas field has experienced many development challenges, among which early water flooding and inhomogeneous water invasion are the main reasons for the production decline in Kela 2 gas field. Based on the abundant geological and performance data, a fine 3D geological modeling is built to accurately describe the structure, matrix properties and fracture in Kela 2 gas field, and then analyzes the characteristics and causes of water invasion. The research shows that faults, fractures, high permeability zone and interlayer are the main controlling factors of water invasion in Kela 2 gas field. And the water invasion can be divided into three patterns, (a) Vertical channeling-lateral invasion, (b) Edge water lateral invasion, (c) Bottom water coning. On the basis of water invasion study, development countermeasures are put forward to provide support for long-term stable production and efficient development of Kela 2 gas field.
{"title":"Main Controlling Factors of Water Invasion for Kela 2 Gas Field","authors":"Zhao-long Liu, Yongzhong Zhang","doi":"10.2523/iptc-23041-ea","DOIUrl":"https://doi.org/10.2523/iptc-23041-ea","url":null,"abstract":"\u0000 As one of the largest discovered gas fields in China, Kela 2 gas field has proven geological reserves of more than 200 billion cubic meters, with a maximum annual gas production of approximately 12 billion cubic meters. After 18 years development, Kela 2 gas field is now in the middle-late development period. At present, the gas field has experienced many development challenges, among which early water flooding and inhomogeneous water invasion are the main reasons for the production decline in Kela 2 gas field. Based on the abundant geological and performance data, a fine 3D geological modeling is built to accurately describe the structure, matrix properties and fracture in Kela 2 gas field, and then analyzes the characteristics and causes of water invasion. The research shows that faults, fractures, high permeability zone and interlayer are the main controlling factors of water invasion in Kela 2 gas field. And the water invasion can be divided into three patterns, (a) Vertical channeling-lateral invasion, (b) Edge water lateral invasion, (c) Bottom water coning. On the basis of water invasion study, development countermeasures are put forward to provide support for long-term stable production and efficient development of Kela 2 gas field.","PeriodicalId":283978,"journal":{"name":"Day 1 Wed, March 01, 2023","volume":"201 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"124399673","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}
Amir Irfan Mahra, Ryan Guillory, R. Islamov, Gurveen Singh Reekhi Satwant, Nurul Asyikin Mohd Radzuan, F. A. Salleh, Tunku Indra Tunku Abdul Muthalib
Field D (offshore Sarawak, Malaysia) first production was in 2012 from three wells, with a second phase of development in 2017 with the drilling of four wells. Severe productivity decline was seen in five of the seven wells, and numerous studies were completed to narrow in on the root causes. Several production enhancement techniques were executed on Phase 1 and Phase 2 wells, where learnings and results will be further shared. Prior to the drilling of six additional wells in Phase 3 (2020), additional detailed lab studies were undertaken, and new strategies were implemeted based on this were applied with encouraging results. The majority of the wells have downhole pressure gauges (PDG), and coupled with frequent well test data, PTA, and Nodal Analysis modeling Productivity Index, permeability thickness (kH), and Skin are able to be tracked over time. By trending these different productivity indicators, it became clear that formation damage was occurring in several wells with varying degrees of severity based on the performance of the reservoir layer being produced. Various formation damage mechanisms were assessed (scale, wax, asphaltenes, drilling & completion damage, fines migration), and based on the initial study it was determined that fines migration was likely the major issue. Historically, no sand was observed on the surface where monthly sand count reported has always been <1 pound per thousand bbl (pptb) which was supported by geomechanics, and sand failure tendency studies completed during development phase of the field. Hence, six of the seven Phase 1 and 2 wells were completed with cased and perforated strategy with no downhole sand control, with the other well completed as a highly deviated open hole standalone completion. The productivity declines were only experienced in the cased and perforated completions, which had much lower gross completed interval and thus experienced higher velocities near the wellbore. The main production enhancement strategy applied to date has been re-perforation (8 re-perforation jobs), with varying degrees of productivity improvement and duration of sustainability. Solid propellant technology was applied in one of the well and clearing of the perforation tunnels via through-tubing dynamic underbalance technique in two wells was applied and no major improvement in sustained production impact was observed. An acid stimulation was recently pumped for the first time in one well and the assessment details will be shared, and results of the pumping will be shared in detail. At the time of the paper, no post production results were available. Prior to the drilling of six Phase 3 wells in 2020, detailed lab studies to look at the impact of various drilling muds were assessed, and learnings were incorporated in the mud program. Critical velocity studies were completed, and learnings from this work such as well ramp-up strategy and normalized maximum production rates have been added to the well-by-well product
{"title":"History of Managing Productivity Issues Due to Fines Migration in a Malaysian Oil Field Offshore Sarawak","authors":"Amir Irfan Mahra, Ryan Guillory, R. Islamov, Gurveen Singh Reekhi Satwant, Nurul Asyikin Mohd Radzuan, F. A. Salleh, Tunku Indra Tunku Abdul Muthalib","doi":"10.2523/iptc-23060-ms","DOIUrl":"https://doi.org/10.2523/iptc-23060-ms","url":null,"abstract":"\u0000 Field D (offshore Sarawak, Malaysia) first production was in 2012 from three wells, with a second phase of development in 2017 with the drilling of four wells. Severe productivity decline was seen in five of the seven wells, and numerous studies were completed to narrow in on the root causes. Several production enhancement techniques were executed on Phase 1 and Phase 2 wells, where learnings and results will be further shared. Prior to the drilling of six additional wells in Phase 3 (2020), additional detailed lab studies were undertaken, and new strategies were implemeted based on this were applied with encouraging results. The majority of the wells have downhole pressure gauges (PDG), and coupled with frequent well test data, PTA, and Nodal Analysis modeling Productivity Index, permeability thickness (kH), and Skin are able to be tracked over time. By trending these different productivity indicators, it became clear that formation damage was occurring in several wells with varying degrees of severity based on the performance of the reservoir layer being produced. Various formation damage mechanisms were assessed (scale, wax, asphaltenes, drilling & completion damage, fines migration), and based on the initial study it was determined that fines migration was likely the major issue. Historically, no sand was observed on the surface where monthly sand count reported has always been <1 pound per thousand bbl (pptb) which was supported by geomechanics, and sand failure tendency studies completed during development phase of the field. Hence, six of the seven Phase 1 and 2 wells were completed with cased and perforated strategy with no downhole sand control, with the other well completed as a highly deviated open hole standalone completion. The productivity declines were only experienced in the cased and perforated completions, which had much lower gross completed interval and thus experienced higher velocities near the wellbore. The main production enhancement strategy applied to date has been re-perforation (8 re-perforation jobs), with varying degrees of productivity improvement and duration of sustainability. Solid propellant technology was applied in one of the well and clearing of the perforation tunnels via through-tubing dynamic underbalance technique in two wells was applied and no major improvement in sustained production impact was observed. An acid stimulation was recently pumped for the first time in one well and the assessment details will be shared, and results of the pumping will be shared in detail. At the time of the paper, no post production results were available. Prior to the drilling of six Phase 3 wells in 2020, detailed lab studies to look at the impact of various drilling muds were assessed, and learnings were incorporated in the mud program. Critical velocity studies were completed, and learnings from this work such as well ramp-up strategy and normalized maximum production rates have been added to the well-by-well product","PeriodicalId":283978,"journal":{"name":"Day 1 Wed, March 01, 2023","volume":"52 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"115255355","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}
Haidar Husein Alfarisi, W. M. N. W M Yaakub, Syifaa Zukhri
Effective August 2021, Malaysia Assets Reset has launched Clustered Maintenance Planning and Execution (CMPE) department towards value focused asset management. To align with the department aspiration to continually generating optimum cashflow as well as staff upskilling, this study focuses on one of CMPE key result areas, with its main objective is to steer frontline maintenance work practice to value-generation perspective. Cost-Benefit Analysis (CBA) process is used in this study to analyze which maintenance tasks to proceed and which to forgo. It is performed by comparing the cost of frontline maintenance versus outsourcing for a maintenance task over a period of time. Elements taking into consideration for the cost calculation are materials, special tools, additional cost required to ensure internal resources competent to perform the job, outsourcing contract rate (on annual basis), and logistics associated costs. Currently, CBA assessment has been performed by CMPE on 15 potential maintenance tasks which was previously executed via outsourcing. Based on the cost saving/cost incurred derived from Frontline Maintenance versus outsourcing, 14 of the tasks are classified as cost-effective. Taking into consideration of clustered planning and scheduling, each planner are required to further assess on the perspective of manpower availability and re-strategize on manpower arrangement to execute the maintenance task via frontline maintenance. This CBA assessment not only resulted to an increase of 29% total planned frontline maintenance activities in 2022 versus pool of activities performed in 2021 but also contributed to additional technical skill sets to perform value-added maintenance tasks. The assessment via CBA has added value-generation perspective in identifying cost-effective and feasibility of the activities selected. By performing this study, it has supported towards achieving the company End State Aspiration.
{"title":"Frontline Maintenance Re-Strategy: Perspective of Cost-Benefit Analysis","authors":"Haidar Husein Alfarisi, W. M. N. W M Yaakub, Syifaa Zukhri","doi":"10.2523/iptc-22713-ms","DOIUrl":"https://doi.org/10.2523/iptc-22713-ms","url":null,"abstract":"\u0000 Effective August 2021, Malaysia Assets Reset has launched Clustered Maintenance Planning and Execution (CMPE) department towards value focused asset management. To align with the department aspiration to continually generating optimum cashflow as well as staff upskilling, this study focuses on one of CMPE key result areas, with its main objective is to steer frontline maintenance work practice to value-generation perspective.\u0000 Cost-Benefit Analysis (CBA) process is used in this study to analyze which maintenance tasks to proceed and which to forgo. It is performed by comparing the cost of frontline maintenance versus outsourcing for a maintenance task over a period of time. Elements taking into consideration for the cost calculation are materials, special tools, additional cost required to ensure internal resources competent to perform the job, outsourcing contract rate (on annual basis), and logistics associated costs.\u0000 Currently, CBA assessment has been performed by CMPE on 15 potential maintenance tasks which was previously executed via outsourcing. Based on the cost saving/cost incurred derived from Frontline Maintenance versus outsourcing, 14 of the tasks are classified as cost-effective. Taking into consideration of clustered planning and scheduling, each planner are required to further assess on the perspective of manpower availability and re-strategize on manpower arrangement to execute the maintenance task via frontline maintenance. This CBA assessment not only resulted to an increase of 29% total planned frontline maintenance activities in 2022 versus pool of activities performed in 2021 but also contributed to additional technical skill sets to perform value-added maintenance tasks.\u0000 The assessment via CBA has added value-generation perspective in identifying cost-effective and feasibility of the activities selected. By performing this study, it has supported towards achieving the company End State Aspiration.","PeriodicalId":283978,"journal":{"name":"Day 1 Wed, March 01, 2023","volume":"1 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"125124123","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}
For The Gulf of Thailand (GoT) projects, the bulk of investment goes in drilling development wells and the financial return is depending on how much reserve is effectively tapped by those wells. To improve project economics, both optimizing the well placements to access hydrocarbon and minimizing the number of wells are required. This study shows how proper well spacing used in development well planning is defined using the understanding of reservoir connectivity ratio at a given well spacing. Firstly, reservoir correlation panels of wells drilled within the same trapping fault were created and the reservoir connectivity ratio at a given well spacing were collected. Hence the cross-plot between various well spacing and reservoir connectivity ratio was constructed to establish relationship. New reserves were derived by new pay from the spacing-connectivity relationship and estimated ultimate recovery per metre (EUR/m). With the estimated reserves varied by well spacing, the proper well spacing can be defined by identifying the narrowest well spacing that yield new incremental reserves above economic cut-off. More than 100 cross-plots from Arthit project were conducted by using the existing wells information, the results suggest that a relationship between well spacing and reservoir connectivity ratio is varying depended on trap style, fault strike, channel width & oblique angle and hydrocarbon column height. A new/share pay ratio template is now available to illustrate an expected new/share pay ratio at a given well spacing (ranged from 100 m. to 1,500 m.) in each HC pay unit and subsurface geological trend. From the result, new pay ratio is in the range of 45%-60% at the current well spacing (400 m.) of Arthit Project. Based on the economic justification of Arthit project, there is the opportunity to narrow down well spacing for being economically viable in the future. The optimum well spacing together with an economic viability analysis in each project could be done efficiently. Shortly, the proper given well spacing will be proactively planned for both infill and new wellhead platform. The 2021 infill projects help to validate the current model, improve the prediction function and certainly narrow down those uncertainties for future development projects. Development planning would benefit greatly from proper well spacing so that the optimum number of wells is known upfront so project planning could be properly managed. If tighter well spacing could be applied, more wells could be filled into existing platforms. Then the big investment on new platforms could be deferred. Moreover, this method can be also broadened to other projects where GoT development model can be applied to achieve optimum commerciality.
{"title":"The Proper Well Spacings – A Supplementary Method to Maximize The Gulf of Thailand Development Project Value","authors":"Pitchaya Hotapavanon, Kasinee Suyacom, K. Chuachomsuk, Jiraphas Thapchim, Rutchanok Nasomsong, Metsai Chaipornkaew","doi":"10.2523/iptc-22990-ms","DOIUrl":"https://doi.org/10.2523/iptc-22990-ms","url":null,"abstract":"\u0000 For The Gulf of Thailand (GoT) projects, the bulk of investment goes in drilling development wells and the financial return is depending on how much reserve is effectively tapped by those wells. To improve project economics, both optimizing the well placements to access hydrocarbon and minimizing the number of wells are required. This study shows how proper well spacing used in development well planning is defined using the understanding of reservoir connectivity ratio at a given well spacing.\u0000 Firstly, reservoir correlation panels of wells drilled within the same trapping fault were created and the reservoir connectivity ratio at a given well spacing were collected. Hence the cross-plot between various well spacing and reservoir connectivity ratio was constructed to establish relationship. New reserves were derived by new pay from the spacing-connectivity relationship and estimated ultimate recovery per metre (EUR/m). With the estimated reserves varied by well spacing, the proper well spacing can be defined by identifying the narrowest well spacing that yield new incremental reserves above economic cut-off.\u0000 More than 100 cross-plots from Arthit project were conducted by using the existing wells information, the results suggest that a relationship between well spacing and reservoir connectivity ratio is varying depended on trap style, fault strike, channel width & oblique angle and hydrocarbon column height. A new/share pay ratio template is now available to illustrate an expected new/share pay ratio at a given well spacing (ranged from 100 m. to 1,500 m.) in each HC pay unit and subsurface geological trend. From the result, new pay ratio is in the range of 45%-60% at the current well spacing (400 m.) of Arthit Project. Based on the economic justification of Arthit project, there is the opportunity to narrow down well spacing for being economically viable in the future.\u0000 The optimum well spacing together with an economic viability analysis in each project could be done efficiently. Shortly, the proper given well spacing will be proactively planned for both infill and new wellhead platform. The 2021 infill projects help to validate the current model, improve the prediction function and certainly narrow down those uncertainties for future development projects.\u0000 Development planning would benefit greatly from proper well spacing so that the optimum number of wells is known upfront so project planning could be properly managed. If tighter well spacing could be applied, more wells could be filled into existing platforms. Then the big investment on new platforms could be deferred. Moreover, this method can be also broadened to other projects where GoT development model can be applied to achieve optimum commerciality.","PeriodicalId":283978,"journal":{"name":"Day 1 Wed, March 01, 2023","volume":" 32","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"113948798","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}
R. Masoudi, S. Nayak, A. Panting, M. A. B M Diah, Muhammad Nazam Samsuri, Ts. Hijreen Bt Ismail, M. J. Hoesni, M. S. Razak, Nur Asyikin Ahmad
High CO2 encountered in various wells throughout Sarawak basin have always been area of concern for both exploration and development. As the contaminants negatively impact economic value as well as hinders our commitment toward net zero carbon, understanding the source of these requires critical and urgent attention. This paper presents an integrated basin scale petroleum system modelling approach to understand source, generation, and distribution of CO2 in Sarawak offshore. A regional scale CO2 Model in Sarawak Basin is constructed covering West Luconia, Central Luconia, Tatau, and Balingian area. A comprehensive Petroleum System Model is generated integrating geophysical, geological and well data to predict concentration and risk of CO2 in Sarawak Basin. The model incorporates contribution from both organic and inorganic CO2 sources to understand generation and charge evolution histories.
{"title":"An Integrated Petroleum System Modeling Approach to Investigate Origin and Distribution of CO2 off the Coast of Sarawak, Offshore Malaysia","authors":"R. Masoudi, S. Nayak, A. Panting, M. A. B M Diah, Muhammad Nazam Samsuri, Ts. Hijreen Bt Ismail, M. J. Hoesni, M. S. Razak, Nur Asyikin Ahmad","doi":"10.2523/iptc-22847-ea","DOIUrl":"https://doi.org/10.2523/iptc-22847-ea","url":null,"abstract":"\u0000 High CO2 encountered in various wells throughout Sarawak basin have always been area of concern for both exploration and development. As the contaminants negatively impact economic value as well as hinders our commitment toward net zero carbon, understanding the source of these requires critical and urgent attention. This paper presents an integrated basin scale petroleum system modelling approach to understand source, generation, and distribution of CO2 in Sarawak offshore.\u0000 A regional scale CO2 Model in Sarawak Basin is constructed covering West Luconia, Central Luconia, Tatau, and Balingian area. A comprehensive Petroleum System Model is generated integrating geophysical, geological and well data to predict concentration and risk of CO2 in Sarawak Basin. The model incorporates contribution from both organic and inorganic CO2 sources to understand generation and charge evolution histories.","PeriodicalId":283978,"journal":{"name":"Day 1 Wed, March 01, 2023","volume":"6 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"126448409","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
The world is currently facing one of the most critical challenges in the Earth’s history which is global warming. The major cause of global warming and climate change problems is the carbon dioxide emissions. This novel study addresses the concepts and design precautions for a proposed in-situ electricity generation project. The main goal of the study is to reduce the environmental pollution due to the combustion of fossil fuels and emitting carbon dioxide. This reduction will be attained through a smart gas well design and completions. The design is based on in-situ combustion for a gas flow in a downhole combustion chamber. Oxy-fuel combustion technique is the proposed combustion technique due to the ease of CO2 separation in this process. The proper well design will be analogous to the wells used for in-situ oil combustion to handle the high released temperature. Power generation design will combine the fundamentals of geothermal energy deployment for electricity generation. Finally, the produced CO2 from the combustion process will be reinjected downhole into an underground geological structure after being compressed and transferred to the supercritical phase. This process eliminates the CO2 production to the surface and hence reduce the environmental pollution.
{"title":"CO\u0000 2 Capturing and Storage From Oil Wells","authors":"Sultan A. Al-Aklubi, Mohammad A. Al-Rubaii","doi":"10.2523/iptc-23001-ms","DOIUrl":"https://doi.org/10.2523/iptc-23001-ms","url":null,"abstract":"\u0000 The world is currently facing one of the most critical challenges in the Earth’s history which is global warming. The major cause of global warming and climate change problems is the carbon dioxide emissions. This novel study addresses the concepts and design precautions for a proposed in-situ electricity generation project.\u0000 The main goal of the study is to reduce the environmental pollution due to the combustion of fossil fuels and emitting carbon dioxide. This reduction will be attained through a smart gas well design and completions. The design is based on in-situ combustion for a gas flow in a downhole combustion chamber. Oxy-fuel combustion technique is the proposed combustion technique due to the ease of CO2 separation in this process. The proper well design will be analogous to the wells used for in-situ oil combustion to handle the high released temperature. Power generation design will combine the fundamentals of geothermal energy deployment for electricity generation. Finally, the produced CO2 from the combustion process will be reinjected downhole into an underground geological structure after being compressed and transferred to the supercritical phase. This process eliminates the CO2 production to the surface and hence reduce the environmental pollution.","PeriodicalId":283978,"journal":{"name":"Day 1 Wed, March 01, 2023","volume":"79 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"132126599","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}
One of the most pressing environmental concerns in the Oil and Gas industry is greenhouse gas (GHG) emissions. Therefore, PTTEP (Company A) has committed Net Zero emissions by 2050. At the Arthit field in the Gulf of Thailand, the majority of hydrocarbon loss to flare is mainly from the CO2 membrane where the permeate stream is continuously and directly emitted via the acid gas flare. To align with our company's vision, the most practical approach to reduce GHG emissions at the Arthit field is to decrease the amount of hydrocarbon loss to flare by increasing %CO2 in the CO2 membrane permeate gas because CO2 contributes to greenhouse gas emissions much lower than hydrocarbon at the same emission flow rate. To minimize hydrocarbon loss, it is essential to maximize %CO2 in the permeate gas by optimizing the CO2 membrane performance. However, it has to ensure that the heating value of the permeate gas is sufficient for complete combustion. Thus, the more selective CO2 membrane model is required by adopting the newest technology. At the Arthit field, the new membrane product is selected as its selectivity is better than the existing models. With the new membrane, it is a challenge to further investigate the optimal configuration, specifically to the Arthit field's current operating conditions, in terms of the feed flow rate, the permeate pressure, the inlet temperature, and the sequence of the preceding dehydration unit. The investigation to optimize the CO2 membrane is successful according to the results from the intensive trial tests as follows:"Flow Allocation Optimization" determines which CO2 membrane banks should be operated with the new membrane element product. The results indicate that hydrocarbon loss from the existing and the new membrane element models are dependent on the flow rate. Operating too low flow rate compounds hydrocarbon loss."Permeate Pressure Optimization" reveals that the lower permeate pressure results in the higher %CO2 in permeate, but the higher permeate flow. Too low and too high permeate pressures aggravate hydrocarbon loss."Inlet Temperature Optimization" indicates that increasing the feed temperature exacerbates hydrocarbon loss. It is necessary to keep the inlet temperature at the minimum, but the margin must be maintained to prevent hydrocarbon condensation."Dehydration Unit Sequence Adjustment" pinpoints that the extended cooling time attenuates GHG emissions as it reduces the spikes from the heating steps that worsen hydrocarbon loss from the high temperature. Auspiciously, hydrocarbon loss is reduced from 4.66 to 3.58 MMscfd and from 5.55 to 4.73 MMscfd for low and high nominations, respectively. In other words, 39,000 tCO2e/year of GHG reduction is achieved. Furthermore, the revenue of 33.40 MMUSD will be gained until the end of concession. In order to drive Company A one step closer its milestone, it is crucial to keep GHG emissions from each operating field at the minimum. Since both of the Arthit field
{"title":"Arthit CO2 Membrane Optimisation to Tackle Greenhouse Gas Emission Issue","authors":"Pimpisa Pechvijitra, Kantkanit Watanakun, Boonyakorn Assavanives, Mongkol Tantiviwattanawongsa, Sukit Rakdee, Eakamol Wuttikiangkaipol, Alawee Binhayeeniyi, Songwut Ammaro","doi":"10.2523/iptc-22721-ms","DOIUrl":"https://doi.org/10.2523/iptc-22721-ms","url":null,"abstract":"\u0000 One of the most pressing environmental concerns in the Oil and Gas industry is greenhouse gas (GHG) emissions. Therefore, PTTEP (Company A) has committed Net Zero emissions by 2050. At the Arthit field in the Gulf of Thailand, the majority of hydrocarbon loss to flare is mainly from the CO2 membrane where the permeate stream is continuously and directly emitted via the acid gas flare. To align with our company's vision, the most practical approach to reduce GHG emissions at the Arthit field is to decrease the amount of hydrocarbon loss to flare by increasing %CO2 in the CO2 membrane permeate gas because CO2 contributes to greenhouse gas emissions much lower than hydrocarbon at the same emission flow rate.\u0000 To minimize hydrocarbon loss, it is essential to maximize %CO2 in the permeate gas by optimizing the CO2 membrane performance. However, it has to ensure that the heating value of the permeate gas is sufficient for complete combustion. Thus, the more selective CO2 membrane model is required by adopting the newest technology. At the Arthit field, the new membrane product is selected as its selectivity is better than the existing models. With the new membrane, it is a challenge to further investigate the optimal configuration, specifically to the Arthit field's current operating conditions, in terms of the feed flow rate, the permeate pressure, the inlet temperature, and the sequence of the preceding dehydration unit.\u0000 The investigation to optimize the CO2 membrane is successful according to the results from the intensive trial tests as follows:\"Flow Allocation Optimization\" determines which CO2 membrane banks should be operated with the new membrane element product. The results indicate that hydrocarbon loss from the existing and the new membrane element models are dependent on the flow rate. Operating too low flow rate compounds hydrocarbon loss.\"Permeate Pressure Optimization\" reveals that the lower permeate pressure results in the higher %CO2 in permeate, but the higher permeate flow. Too low and too high permeate pressures aggravate hydrocarbon loss.\"Inlet Temperature Optimization\" indicates that increasing the feed temperature exacerbates hydrocarbon loss. It is necessary to keep the inlet temperature at the minimum, but the margin must be maintained to prevent hydrocarbon condensation.\"Dehydration Unit Sequence Adjustment\" pinpoints that the extended cooling time attenuates GHG emissions as it reduces the spikes from the heating steps that worsen hydrocarbon loss from the high temperature.\u0000 Auspiciously, hydrocarbon loss is reduced from 4.66 to 3.58 MMscfd and from 5.55 to 4.73 MMscfd for low and high nominations, respectively. In other words, 39,000 tCO2e/year of GHG reduction is achieved. Furthermore, the revenue of 33.40 MMUSD will be gained until the end of concession.\u0000 In order to drive Company A one step closer its milestone, it is crucial to keep GHG emissions from each operating field at the minimum. Since both of the Arthit field","PeriodicalId":283978,"journal":{"name":"Day 1 Wed, March 01, 2023","volume":"14 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"132581332","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}
Integrating the inversions of simultaneously acquired deep and ultra-deep logging while drilling (LWD) azimuthal resistivity measurements can improve the resolution of the overlapping volume under investigation and reduce uncertainty in the far field volume model reconstruction. Both are key tools for precise placement of horizontal wells, the recent enhancements in the downhole tools include surface processing algorithms and advanced visualization techniques that allow higher confidence in well placement decisions through improved understanding of subsurface geology and orientation of sand channels in real-time. The high-definition multi-layer inversion capability of a new generation deep resistivity tool has been utilized along with the 1D and 3D ultra-deep resistivity inversion for a separate established tool, providing detailed visualization of formations both near wellbore and in the far field. Both technologies were compared in reservoirs with varying resistivity profiles and thicknesses. In addition, the resistivity anisotropy analysis from ultra-deep 3D inversion was utilized to confirm lithology around the wellbore differentiating anisotropic shale zones from other lithologies of similar low resistivity. Ultra-deep 3D inversions were processed with fine scale cell sizes and then used to validate the high-resolution deep resistivity inversion results. The integration of multiple inversions with varying capabilities enabled resolving thin reservoir layers in a low-resistivity, low-contrast environment, providing superior resolution within the overlapping volumes of investigation of the deep and ultra-deep resistivities. Customization of the ultra-deep 3D inversion successfully enabled geo-mapping of 1-2 ft thick layers and was used to validate the high-resolution deep resistivity 1D inversion. The increasingly challenging geo-steering decision-making process in a complex drilling environment was addressed by employing the advancement in LWD technologies providing higher signal to noise ratios, multiple frequencies and transmitter-receiver spacings augmented with customized inversions providing superior results. This paper demonstrates the added value, to identify, map and navigate thin reservoir zones. A novel workflow has been developed to improve resolution in deep and ultra-deep resistivity mapping, enabling the identification of thin laminations around the wellbore capitalizing on the latest advancements in LWD geo-steering technologies.
{"title":"Integration of Deep Resistivity High Definition and Ultra-Deep Resistivity 3D Inversion Enables Geo-Steering in Thin Laminated Reservoirs","authors":"A. Elkhamry, M. Fouda, A. Taher, E. Bikchandaev","doi":"10.2523/iptc-23017-ea","DOIUrl":"https://doi.org/10.2523/iptc-23017-ea","url":null,"abstract":"\u0000 Integrating the inversions of simultaneously acquired deep and ultra-deep logging while drilling (LWD) azimuthal resistivity measurements can improve the resolution of the overlapping volume under investigation and reduce uncertainty in the far field volume model reconstruction. Both are key tools for precise placement of horizontal wells, the recent enhancements in the downhole tools include surface processing algorithms and advanced visualization techniques that allow higher confidence in well placement decisions through improved understanding of subsurface geology and orientation of sand channels in real-time.\u0000 The high-definition multi-layer inversion capability of a new generation deep resistivity tool has been utilized along with the 1D and 3D ultra-deep resistivity inversion for a separate established tool, providing detailed visualization of formations both near wellbore and in the far field. Both technologies were compared in reservoirs with varying resistivity profiles and thicknesses. In addition, the resistivity anisotropy analysis from ultra-deep 3D inversion was utilized to confirm lithology around the wellbore differentiating anisotropic shale zones from other lithologies of similar low resistivity. Ultra-deep 3D inversions were processed with fine scale cell sizes and then used to validate the high-resolution deep resistivity inversion results.\u0000 The integration of multiple inversions with varying capabilities enabled resolving thin reservoir layers in a low-resistivity, low-contrast environment, providing superior resolution within the overlapping volumes of investigation of the deep and ultra-deep resistivities. Customization of the ultra-deep 3D inversion successfully enabled geo-mapping of 1-2 ft thick layers and was used to validate the high-resolution deep resistivity 1D inversion. The increasingly challenging geo-steering decision-making process in a complex drilling environment was addressed by employing the advancement in LWD technologies providing higher signal to noise ratios, multiple frequencies and transmitter-receiver spacings augmented with customized inversions providing superior results.\u0000 This paper demonstrates the added value, to identify, map and navigate thin reservoir zones. A novel workflow has been developed to improve resolution in deep and ultra-deep resistivity mapping, enabling the identification of thin laminations around the wellbore capitalizing on the latest advancements in LWD geo-steering technologies.","PeriodicalId":283978,"journal":{"name":"Day 1 Wed, March 01, 2023","volume":"1 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"127052439","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}
Gas lift is the major artificial lift method for the wells of brownfields in the Upper Assam Shelf Basin. It is the best suited method for maintaining and extending the current production rate of the fields. In this gas lift optimization endeavour, we have selected Hapjan field, one of the brownfields of the Upper Assam Shelf Basin. This study comprises problem troubleshooting and optimization of 15 intermittent gas lift wells. In the Hapjan field, intermittent gas lift wells operate with surface intermitters, as well as choke control intermittent lift in a closed rotative gas lift system. During the course of this project, all surface and subsurface diagnostic tools suitable for intermittent gas lift well optimization are utilized with special emphasis on pressure and temperature surveys. Tools and methodologies used are as follows: Surface recordings of tubing and casing pressures.Acoustic well sounding devices.Determination of optimal gas-lift gas injection rate.Multi-rate test interpretation.Gas lift surveillance software.Subsurface pressure and temperature surveys. Subsurface pressure and temperature survey allows pinpointing of many malfunctions and provides a complete evaluation of how the well performs. This paper presents an exceptionally detailed procedure for performing and analyzing a subsurface pressure and temperature survey in intermittent gas lift wells. In this type of subsurface survey, tandem Electronic Memory Gauges (EMG) are run in the well under flowing conditions while the well is being tested. In addition, static measurements are conducted where, once the EMG is run to depth, it remains there until the bottom hole pressure approaches the static value. When dynamic and static downhole surveys are correctly performed and analyzed, the following engineering considerations about gas lift wells can be gathered: Point of operation.Multi-point injection.Operating valve performance.Optimum cycle time.Productivity index.True fluid gradient in the production tubing.Dynamic fallback.Static Fluid Level.Static reservoir pressure and other reservoir properties. The paper emphasizes the results of the surveys and the detailed adjustments to the wells operating mode based on well performance analysis. A 11% increase in production was obtained by implementing the survey results in 15 wells in the Hapjan gas lift field. A great potential for low investment and rapidly increasing production and development of the reserve lies in the optimization of gas lift wells. As a result of this project, we have gathered valuable engineering experience that shows gas lift well optimization can substantially increase production in brownfields in the Upper Assam Shelf Basin and also other exploration and production (E&P) companies throughout the world.
{"title":"Subsurface Pressure and Temperature Survey Analysis for Wells on Intermittent Gas Lift: A Field Optimisation Case Study in Upper Assam Shelf Basin","authors":"Partha Protim Maut, Yerra Prakash","doi":"10.2523/iptc-23094-ms","DOIUrl":"https://doi.org/10.2523/iptc-23094-ms","url":null,"abstract":"\u0000 Gas lift is the major artificial lift method for the wells of brownfields in the Upper Assam Shelf Basin. It is the best suited method for maintaining and extending the current production rate of the fields. In this gas lift optimization endeavour, we have selected Hapjan field, one of the brownfields of the Upper Assam Shelf Basin. This study comprises problem troubleshooting and optimization of 15 intermittent gas lift wells.\u0000 In the Hapjan field, intermittent gas lift wells operate with surface intermitters, as well as choke control intermittent lift in a closed rotative gas lift system. During the course of this project, all surface and subsurface diagnostic tools suitable for intermittent gas lift well optimization are utilized with special emphasis on pressure and temperature surveys. Tools and methodologies used are as follows: Surface recordings of tubing and casing pressures.Acoustic well sounding devices.Determination of optimal gas-lift gas injection rate.Multi-rate test interpretation.Gas lift surveillance software.Subsurface pressure and temperature surveys.\u0000 Subsurface pressure and temperature survey allows pinpointing of many malfunctions and provides a complete evaluation of how the well performs.\u0000 This paper presents an exceptionally detailed procedure for performing and analyzing a subsurface pressure and temperature survey in intermittent gas lift wells. In this type of subsurface survey, tandem Electronic Memory Gauges (EMG) are run in the well under flowing conditions while the well is being tested. In addition, static measurements are conducted where, once the EMG is run to depth, it remains there until the bottom hole pressure approaches the static value. When dynamic and static downhole surveys are correctly performed and analyzed, the following engineering considerations about gas lift wells can be gathered: Point of operation.Multi-point injection.Operating valve performance.Optimum cycle time.Productivity index.True fluid gradient in the production tubing.Dynamic fallback.Static Fluid Level.Static reservoir pressure and other reservoir properties.\u0000 The paper emphasizes the results of the surveys and the detailed adjustments to the wells operating mode based on well performance analysis. A 11% increase in production was obtained by implementing the survey results in 15 wells in the Hapjan gas lift field.\u0000 A great potential for low investment and rapidly increasing production and development of the reserve lies in the optimization of gas lift wells. As a result of this project, we have gathered valuable engineering experience that shows gas lift well optimization can substantially increase production in brownfields in the Upper Assam Shelf Basin and also other exploration and production (E&P) companies throughout the world.","PeriodicalId":283978,"journal":{"name":"Day 1 Wed, March 01, 2023","volume":"56 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"121933285","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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