Yibo Li, Tianshuang He, Jin-Zhou Zhao, Xiang Lin, Lin Sun, B. Wei, W. Pu
Foam flooding is a crucial enhanced oil recovery technique for profile control during the oil displacement process. The stability of the foam is the key factor for the success of foam flooding, but typical aqueous foams generally lose their stability in the presence of hydrocarbons because of their low oil tolerance. Non-aqueous foams possess outstanding stability in the presence of hydrocarbons as a result of their unique properties. However, few studies have been conducted on the stabilization mechanisms of non-aqueous foams in the presence of hydrocarbons. In this study, comparative experiments were performed to investigate differences in the stabilization mechanism between aqueous and non-aqueous foams. The results showed that a non-aqueous foam had excellent oil tolerance in a bulk foaming test. Then, the stabilization mechanisms of foams were investigated in terms of surface dilatational viscoelasticity and liquid film thinning. For a non-aqueous foam system, the maximum viscoelastic modulus of 55 mN/m occurred at a surfactant concentration of 5.0 wt%, which indicated that the foam was more stable. In a foam film thinning experiment, the thinning time of an aqueous foam system was shortened but the liquid film thickness was increased by crude oil, whereas crude oil increased the thinning time of a non-aqueous foam system but decreased its liquid film thickness. In a non-aqueous foam system, the film could remain stable for hours before rupturing, which indicated that its stability in the presence of an oil phase was excellent. These results are meaningful for the understanding of the stabilization mechanisms of oil-based foams and the employment of non-aqueous foams for enhanced oil recovery.
{"title":"Integrity Investigation of Macroscopic and Microscopic Properties of Non-Aqueous Foams for Enhanced Oil Recovery","authors":"Yibo Li, Tianshuang He, Jin-Zhou Zhao, Xiang Lin, Lin Sun, B. Wei, W. Pu","doi":"10.2523/iptc-22922-ms","DOIUrl":"https://doi.org/10.2523/iptc-22922-ms","url":null,"abstract":"\u0000 Foam flooding is a crucial enhanced oil recovery technique for profile control during the oil displacement process. The stability of the foam is the key factor for the success of foam flooding, but typical aqueous foams generally lose their stability in the presence of hydrocarbons because of their low oil tolerance. Non-aqueous foams possess outstanding stability in the presence of hydrocarbons as a result of their unique properties. However, few studies have been conducted on the stabilization mechanisms of non-aqueous foams in the presence of hydrocarbons. In this study, comparative experiments were performed to investigate differences in the stabilization mechanism between aqueous and non-aqueous foams. The results showed that a non-aqueous foam had excellent oil tolerance in a bulk foaming test. Then, the stabilization mechanisms of foams were investigated in terms of surface dilatational viscoelasticity and liquid film thinning. For a non-aqueous foam system, the maximum viscoelastic modulus of 55 mN/m occurred at a surfactant concentration of 5.0 wt%, which indicated that the foam was more stable. In a foam film thinning experiment, the thinning time of an aqueous foam system was shortened but the liquid film thickness was increased by crude oil, whereas crude oil increased the thinning time of a non-aqueous foam system but decreased its liquid film thickness. In a non-aqueous foam system, the film could remain stable for hours before rupturing, which indicated that its stability in the presence of an oil phase was excellent. These results are meaningful for the understanding of the stabilization mechanisms of oil-based foams and the employment of non-aqueous foams for enhanced oil recovery.","PeriodicalId":153269,"journal":{"name":"Day 2 Thu, March 02, 2023","volume":"11 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":"131634471","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}
C. Peerakham, Nopparerk Haripogepornkul, Natthapon Putthaworapoom, Suwit Direkmahamongkol, P. Thanasutives, Thaw Zin Ko Ko, Zin Lin Tun
Sand production has been highlighted as one of the critical challenges for Zawtika Project. Throughout the years of field experiences, sand production management has brought up many challenges, especially in terms of field potential sustaining, well productivity and investment justification. Alternative sand control technique is one of the keys to overcome these challenges with continuous improvements driven by lessons learnt. Chemical Sand Consolidation (CSC) is the chemical sand control technique using the resin to bond the formation grain and strengthen the formation strength whereas Thru-Tubing Gravel Pack (TTGP) is retrofit sand control method, which the sand control principle is similar to conventional Cased-Hole Gravel Pack (CHGP), but can be installed in a smaller completion size. In Zawtika existing development phases, almost 150 zones of sand producing intervals are handled by CHGP completion design. In addition to CHGP, these mentioned alternative sand control techniques have been successfully implemented in 3.5-inch-tubing monobore completion for selected deep reservoir intervals after some degree of depletion. Field trial of CSC and TTGP had been implemented during 2019-2020 with 5 reservoirs in 7 monobore completion wells (4 CSC wells and 3 TTGP wells). All wells showed positive results with no sand production from the post-job production; and with a reasonable increase in Maximum Allowable Sand Free Rate (MASR). Based on well performance monitoring until early of 2022, all 3 TTGP wells as well as 3 CSC wells no longer have any sand production issue. Nevertheless, only 1 CSC well with water production history record prior to CSC implementation shows poorer performance on sand production prevention. Following the positive results of TTGP from the previous campaign in term of sand production prevention and well life extension, 8 more TTGP well candidates have been implemented in early of 2022. At the early phase of production, sand free production has been observed for all wells with 51 mmscfd incremental MASR. With all aspects of technical and fiscal evaluation proven to be successful, sand retention and production performance of CSC and TTGP are continuously monitored to confirm long-term performance efficiency for full application in the future. Zawtika sand management strategy through alternative sand control completion has been improved upon accumulated lesson learns and production experiences. The lesson learns and experiences from both operation and well performance monitoring will be integrated for further improvement for the next implementation phases. Maximizing gas potential through alternative sand control methods is also believed to be the cost-effective approach which strengthens PTTEP's competitive performance.
{"title":"Chemical Sand Consolidation and Through-Tubing Gravel Pack, the Effective Alternative Sand Control Methods in Zawtika Field","authors":"C. Peerakham, Nopparerk Haripogepornkul, Natthapon Putthaworapoom, Suwit Direkmahamongkol, P. Thanasutives, Thaw Zin Ko Ko, Zin Lin Tun","doi":"10.2523/iptc-23097-ea","DOIUrl":"https://doi.org/10.2523/iptc-23097-ea","url":null,"abstract":"\u0000 Sand production has been highlighted as one of the critical challenges for Zawtika Project. Throughout the years of field experiences, sand production management has brought up many challenges, especially in terms of field potential sustaining, well productivity and investment justification. Alternative sand control technique is one of the keys to overcome these challenges with continuous improvements driven by lessons learnt.\u0000 Chemical Sand Consolidation (CSC) is the chemical sand control technique using the resin to bond the formation grain and strengthen the formation strength whereas Thru-Tubing Gravel Pack (TTGP) is retrofit sand control method, which the sand control principle is similar to conventional Cased-Hole Gravel Pack (CHGP), but can be installed in a smaller completion size. In Zawtika existing development phases, almost 150 zones of sand producing intervals are handled by CHGP completion design. In addition to CHGP, these mentioned alternative sand control techniques have been successfully implemented in 3.5-inch-tubing monobore completion for selected deep reservoir intervals after some degree of depletion.\u0000 Field trial of CSC and TTGP had been implemented during 2019-2020 with 5 reservoirs in 7 monobore completion wells (4 CSC wells and 3 TTGP wells). All wells showed positive results with no sand production from the post-job production; and with a reasonable increase in Maximum Allowable Sand Free Rate (MASR). Based on well performance monitoring until early of 2022, all 3 TTGP wells as well as 3 CSC wells no longer have any sand production issue. Nevertheless, only 1 CSC well with water production history record prior to CSC implementation shows poorer performance on sand production prevention.\u0000 Following the positive results of TTGP from the previous campaign in term of sand production prevention and well life extension, 8 more TTGP well candidates have been implemented in early of 2022. At the early phase of production, sand free production has been observed for all wells with 51 mmscfd incremental MASR.\u0000 With all aspects of technical and fiscal evaluation proven to be successful, sand retention and production performance of CSC and TTGP are continuously monitored to confirm long-term performance efficiency for full application in the future.\u0000 Zawtika sand management strategy through alternative sand control completion has been improved upon accumulated lesson learns and production experiences. The lesson learns and experiences from both operation and well performance monitoring will be integrated for further improvement for the next implementation phases. Maximizing gas potential through alternative sand control methods is also believed to be the cost-effective approach which strengthens PTTEP's competitive performance.","PeriodicalId":153269,"journal":{"name":"Day 2 Thu, March 02, 2023","volume":"8 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":"127103717","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}
Ismaeel Musa I.M. El Barrasi, A. Hale, Ahmed Mohamed Ali, Mamdouh Atef El Mohandes, I. M. Ali
A high-density completion and workover fluid (18-20 ppg) was required for deep high-pressure gas wells. The traditional clear completion brines, which provide a solids-free environment to run and set downhole completion equipment were evaluated and were not approved as they came with an expensive price tag and, more importantly, they came with serious health, safety, and environmental concerns in addition to formation damage concerns. The available alternative barite weighed water-based mud (WBM) was used as completion fluid to set lower completion; however, due to the concentration and size of the solids contained in this system, serious issues became evident. These included leaks due to poor sealing, string plugging, and stuck completions due to barite settlement issues. Manganese tetroxide (Mn3O4) was evaluated as an alternative to barite as it has higher specific gravity and a much smaller particle size. To overcome all limitations of brines and barite WBM, and achieve the required density for well control purposes, to address this issue, rigorous lab work was performed to formulate a completion and workover fluid with viscous sodium chloride brine. Additional density was achieved with manganese tetroxide (Mn3O4). Manganese tetroxide has a very low SAG index due to its ultrafine particle size. The small size of manganese tetroxide (Mn3O4) eliminated the solids sag and settlement issues that were associated with barite weighed fluid and allowed for longer static fluid periods without the need to interrupt operations to circulate and condition the fluid saving significant time lost on sorting out all barite sagging related issues in previous completion and workover operations. This paper presents laboratory design data and comparative data where this type of high-density fluid is used to successfully run lower completions and perform successful workover operations in gas wells without any problems.
{"title":"High Specific Gravity, Ultrafine Particle Size and Acid Soluble Manganese Tetra Oxide Succeeds in Replacing Heavy Brines as Completion and Workover Fluid","authors":"Ismaeel Musa I.M. El Barrasi, A. Hale, Ahmed Mohamed Ali, Mamdouh Atef El Mohandes, I. M. Ali","doi":"10.2523/iptc-22888-ea","DOIUrl":"https://doi.org/10.2523/iptc-22888-ea","url":null,"abstract":"\u0000 \u0000 \u0000 A high-density completion and workover fluid (18-20 ppg) was required for deep high-pressure gas wells. The traditional clear completion brines, which provide a solids-free environment to run and set downhole completion equipment were evaluated and were not approved as they came with an expensive price tag and, more importantly, they came with serious health, safety, and environmental concerns in addition to formation damage concerns. The available alternative barite weighed water-based mud (WBM) was used as completion fluid to set lower completion; however, due to the concentration and size of the solids contained in this system, serious issues became evident. These included leaks due to poor sealing, string plugging, and stuck completions due to barite settlement issues. Manganese tetroxide (Mn3O4) was evaluated as an alternative to barite as it has higher specific gravity and a much smaller particle size.\u0000 \u0000 \u0000 \u0000 To overcome all limitations of brines and barite WBM, and achieve the required density for well control purposes, to address this issue, rigorous lab work was performed to formulate a completion and workover fluid with viscous sodium chloride brine. Additional density was achieved with manganese tetroxide (Mn3O4).\u0000 \u0000 \u0000 \u0000 Manganese tetroxide has a very low SAG index due to its ultrafine particle size. The small size of manganese tetroxide (Mn3O4) eliminated the solids sag and settlement issues that were associated with barite weighed fluid and allowed for longer static fluid periods without the need to interrupt operations to circulate and condition the fluid saving significant time lost on sorting out all barite sagging related issues in previous completion and workover operations.\u0000 \u0000 \u0000 \u0000 This paper presents laboratory design data and comparative data where this type of high-density fluid is used to successfully run lower completions and perform successful workover operations in gas wells without any problems.\u0000","PeriodicalId":153269,"journal":{"name":"Day 2 Thu, March 02, 2023","volume":"2 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":"131091761","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}
Dat Le Quang, Dong Hoang Ngoc, Manisa Rangponsumrit, Phruettiphan Supalasate, Khanh Dong Ngo, Duy Hung Nguyen, Minh Dung Tran, Van Tam Ho, Chi Luong Van, Samad Ali, Sarjono Tasi Antoneus, O. H. Khan, Sing Kiet Hii
CNV field in offshore Vietnam is experiencing excessive surface back pressure due to extended production pipeline and increasing field gas-oil ratio (GOR), which not only constraints the production from existing wells but also creates a challenge in evaluating production gain from future development activities. Therefore, it is critical to properly account the back pressure effect to generate a reliable long term production forecast for further investment decision. This paper describes the details of integrating subsurface dynamic reservoir simulation model with surface network simulation model to holistically assess the impact of back pressure. The conventional method of using standalone dynamic simulation model is compared against the integrated model. The well control mode in the reservoir model is updated with the response of the network model, which consist of wells, topside piping, facility equipment and export pipelines. With this approach, the surface pressure constraints and responses will be captured, and the reservoir, well and network performance will be impacted accordingly. A unified field management is designed using an advanced orchestration engine to control the well operating conditions, schedule well activities and activation of equipment in the operational cycle. Thorough assessment can be performed with the inclusion of accounting interactions between reservoir and network parameters. This integrated modelling workflow allows multiple domains of reservoir engineering, production engineering and engineering contractors to collaborate and achieve a better understanding of the impact of surface back pressure by producing a representative forecast of production profile. To address the back pressure problem in the current facility, debottleneck the surface network and improve production was evaluated by installation of additional surface equipments such as booster pump and compressor. In general, the integrated model provides critical insights to the field development planning, evaluation for de-bottle necking surface system and production optimization. There is lack of publication on the successful usage of the integrated surface network with subsurface dynamic simulation as it is uncommon for this feature in conventional modelling workflows. This paper describes the successful case of the implementation of an integrated simulation modelling workflow to simulate long term surface back pressure effect, back pressure from additional production into the system, and benefits of new surface equipment installation. Highly efficient and accurate prediction tool was developed in the scope of this study.
{"title":"Production Optimisation and Surface Network Debottlenecking Using an Integrated Asset Model for Vietnam Offshore Field Development","authors":"Dat Le Quang, Dong Hoang Ngoc, Manisa Rangponsumrit, Phruettiphan Supalasate, Khanh Dong Ngo, Duy Hung Nguyen, Minh Dung Tran, Van Tam Ho, Chi Luong Van, Samad Ali, Sarjono Tasi Antoneus, O. H. Khan, Sing Kiet Hii","doi":"10.2523/iptc-22883-ms","DOIUrl":"https://doi.org/10.2523/iptc-22883-ms","url":null,"abstract":"\u0000 CNV field in offshore Vietnam is experiencing excessive surface back pressure due to extended production pipeline and increasing field gas-oil ratio (GOR), which not only constraints the production from existing wells but also creates a challenge in evaluating production gain from future development activities. Therefore, it is critical to properly account the back pressure effect to generate a reliable long term production forecast for further investment decision.\u0000 This paper describes the details of integrating subsurface dynamic reservoir simulation model with surface network simulation model to holistically assess the impact of back pressure. The conventional method of using standalone dynamic simulation model is compared against the integrated model. The well control mode in the reservoir model is updated with the response of the network model, which consist of wells, topside piping, facility equipment and export pipelines. With this approach, the surface pressure constraints and responses will be captured, and the reservoir, well and network performance will be impacted accordingly. A unified field management is designed using an advanced orchestration engine to control the well operating conditions, schedule well activities and activation of equipment in the operational cycle.\u0000 Thorough assessment can be performed with the inclusion of accounting interactions between reservoir and network parameters. This integrated modelling workflow allows multiple domains of reservoir engineering, production engineering and engineering contractors to collaborate and achieve a better understanding of the impact of surface back pressure by producing a representative forecast of production profile.\u0000 To address the back pressure problem in the current facility, debottleneck the surface network and improve production was evaluated by installation of additional surface equipments such as booster pump and compressor. In general, the integrated model provides critical insights to the field development planning, evaluation for de-bottle necking surface system and production optimization.\u0000 There is lack of publication on the successful usage of the integrated surface network with subsurface dynamic simulation as it is uncommon for this feature in conventional modelling workflows. This paper describes the successful case of the implementation of an integrated simulation modelling workflow to simulate long term surface back pressure effect, back pressure from additional production into the system, and benefits of new surface equipment installation. Highly efficient and accurate prediction tool was developed in the scope of this study.","PeriodicalId":153269,"journal":{"name":"Day 2 Thu, March 02, 2023","volume":"41 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":"130742914","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}
Tariq Almubarak, J. H. Ng, Majed Almubarak, F. Alotaibi
Corrosion inhibitors used in the petroleum industry are a necessity to include in any acid job. When corrosion occurs to downhole tubulars and equipment, huge expenses are required to maintain the integrity and performance of the well. Unfortunately, commonly used corrosion inhibitors are accompanied with extreme environmental concerns and risk to human health. The recent developments in corrosion inhibitors have resolved the environmental aspect by focusing on biodegradability of these compounds, however, these inhibitors still struggle with issues of toxicity and high temperature stability. The project aims to develop new green, non-toxic, environmentally friendly corrosion inhibitors capable of performing well at high temperature conditions faced in the oil and gas industry. To achieve this goal, 13 commonly available flowers were screened for corrosion inhibition properties. The tests involved using low carbon steel (N-80) coupons and exposing them to 15 wt.% HCl solutions at temperatures between room temperature and 250 °F using a HPHT corrosion reactor to imitate oilfield conditions. A concentration of 0.2-2 wt.% grounded flowers were used to prevent corrosion. Moreover, a control solution containing no corrosion inhibitor was used to establish a corrosion rate for a base case. Upon identifying high performing flowers, extracts of these flowers were subsequently tested to save cost by minimizing quantity needed while achieving acceptable performance. The corrosion inhibition efficiency of the different flowers was compared at various concentrations and temperatures as well as the effect of adding corrosion inhibitor intensifiers. The results revealed that one new inhibitor can be developed from the 13 flower samples tested. The corrosion rate of the flower extract after 6 hours at 150°F was 0.0398 lb/ft2. Additionally, this flower extract was assessed at 200°F and 250°F with the addition of 1 wt.% corrosion inhibitor intensifier and exhibited a corrosion rate of 0.00823 lb/ft2 and 0.0141 lb/ft2, respectively. The results in this work share one new naturally occurring, green, non-toxic, high-temperature stable corrosion inhibitors that can be developed from flowers and can successfully protect the tubular during acid treatments achieving rates below the industry standard of 0.05 lb/ft2 for 6 hours at temperatures up to 250°F.
{"title":"Fragrant Flower Extracts as Corrosion Inhibitors in the Oil and Gas Industry","authors":"Tariq Almubarak, J. H. Ng, Majed Almubarak, F. Alotaibi","doi":"10.2523/iptc-22877-ms","DOIUrl":"https://doi.org/10.2523/iptc-22877-ms","url":null,"abstract":"\u0000 Corrosion inhibitors used in the petroleum industry are a necessity to include in any acid job. When corrosion occurs to downhole tubulars and equipment, huge expenses are required to maintain the integrity and performance of the well. Unfortunately, commonly used corrosion inhibitors are accompanied with extreme environmental concerns and risk to human health. The recent developments in corrosion inhibitors have resolved the environmental aspect by focusing on biodegradability of these compounds, however, these inhibitors still struggle with issues of toxicity and high temperature stability. The project aims to develop new green, non-toxic, environmentally friendly corrosion inhibitors capable of performing well at high temperature conditions faced in the oil and gas industry.\u0000 To achieve this goal, 13 commonly available flowers were screened for corrosion inhibition properties. The tests involved using low carbon steel (N-80) coupons and exposing them to 15 wt.% HCl solutions at temperatures between room temperature and 250 °F using a HPHT corrosion reactor to imitate oilfield conditions. A concentration of 0.2-2 wt.% grounded flowers were used to prevent corrosion. Moreover, a control solution containing no corrosion inhibitor was used to establish a corrosion rate for a base case. Upon identifying high performing flowers, extracts of these flowers were subsequently tested to save cost by minimizing quantity needed while achieving acceptable performance.\u0000 The corrosion inhibition efficiency of the different flowers was compared at various concentrations and temperatures as well as the effect of adding corrosion inhibitor intensifiers. The results revealed that one new inhibitor can be developed from the 13 flower samples tested. The corrosion rate of the flower extract after 6 hours at 150°F was 0.0398 lb/ft2. Additionally, this flower extract was assessed at 200°F and 250°F with the addition of 1 wt.% corrosion inhibitor intensifier and exhibited a corrosion rate of 0.00823 lb/ft2 and 0.0141 lb/ft2, respectively.\u0000 The results in this work share one new naturally occurring, green, non-toxic, high-temperature stable corrosion inhibitors that can be developed from flowers and can successfully protect the tubular during acid treatments achieving rates below the industry standard of 0.05 lb/ft2 for 6 hours at temperatures up to 250°F.","PeriodicalId":153269,"journal":{"name":"Day 2 Thu, March 02, 2023","volume":"22 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":"132014675","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}
P. Henglai, K. Laitrakull, Takonporn Kunpitaktakun, Pinyada Taweepornpathomgul, J. Kaewtapan, A. Ruangsirikulchai, Muhammad Hanif Haziq Mohammad
The successful discovery of petroleum exploration primarily depends on the understanding of the basin evolution and sedimentary filling though geological time. Well data also play a key role for reservoir presence and quality analysis; however, none of well fully penetrated the Oligocene Syn-rift sequence in the West Arthit area. Therefore, this study aims to overcome the challenge of limited well information by performing the Forward Stratigraphic Modeling (FSM) to determine basin evolution, depositional setting, and reservoir distribution in this area. The FSM model is constructed with the inputs of paleo-bathymetry, subsidence, sediment supply, water level, and climatic cycle. In addition, the stratigraphic sequence is reproduced based on field observations such as rock samples, seismic mapping, well-log responses, and publications from nearby areas. The main uncertainty of building the FSM model is the initial age of rifting phase due to a lack of well penetration that fully covered the Syn-rift sequence and the limited biostratigraphic data. Therefore, two different age scenarios are examined in this study analogue from the age model as it was published in the Malay Basin locating to the south of study area. Once the FSM model was built, the last step was to calibrate the prediction result with the actual well result and the conventional seismic data to achieve the best accuracy and to increase the confidence on using the model. The FSM model was successfully reproduced the stratigraphic successions of the Syn-rift sequence in West Arthit area. The base case model was chosen from the age scenario of 27.0-23.1 Ma which exhibited four major cyclicities and matched with seismic mapping. The study area had two depocenters, one in the northwest and another one in the southeast. The northern sub-basin was deepened earlier during the first rifting phase whereas the southern sub-basin was subsided later after the second rifting period. With the increase in sedimentation rate and subsidence rate during the third rifting phase, both depocenters were shallowed up and then become a shallow lake covering the whole study area. The last lifting phase coincided with the thermal subsidence that occurred and affected across the region; therefore, the regional extensive lacustrine accumulated in the study area. The results from this study provided a crucial information on petroleum system especially depositional architecture, reservoir distribution, and potential source rock identification, which were incorporated into the planning of future exploration targeting in this field. This study demonstrates the new innovative approach to determine the basin evolution and to understand the variation on depositional setting in the study area with limited well data. This approach also creates the project value by supporting the planning of future exploration and development wells. Furthermore, this technique can be applied to all projects to increase the discove
{"title":"A Forward Stratigraphic Modelling Approach to Determine the Evolution of an Oligocene Syn-Rift Sequence in West Arthit Area, Gulf of Thailand","authors":"P. Henglai, K. Laitrakull, Takonporn Kunpitaktakun, Pinyada Taweepornpathomgul, J. Kaewtapan, A. Ruangsirikulchai, Muhammad Hanif Haziq Mohammad","doi":"10.2523/iptc-22834-ms","DOIUrl":"https://doi.org/10.2523/iptc-22834-ms","url":null,"abstract":"\u0000 The successful discovery of petroleum exploration primarily depends on the understanding of the basin evolution and sedimentary filling though geological time. Well data also play a key role for reservoir presence and quality analysis; however, none of well fully penetrated the Oligocene Syn-rift sequence in the West Arthit area. Therefore, this study aims to overcome the challenge of limited well information by performing the Forward Stratigraphic Modeling (FSM) to determine basin evolution, depositional setting, and reservoir distribution in this area.\u0000 The FSM model is constructed with the inputs of paleo-bathymetry, subsidence, sediment supply, water level, and climatic cycle. In addition, the stratigraphic sequence is reproduced based on field observations such as rock samples, seismic mapping, well-log responses, and publications from nearby areas. The main uncertainty of building the FSM model is the initial age of rifting phase due to a lack of well penetration that fully covered the Syn-rift sequence and the limited biostratigraphic data. Therefore, two different age scenarios are examined in this study analogue from the age model as it was published in the Malay Basin locating to the south of study area. Once the FSM model was built, the last step was to calibrate the prediction result with the actual well result and the conventional seismic data to achieve the best accuracy and to increase the confidence on using the model.\u0000 The FSM model was successfully reproduced the stratigraphic successions of the Syn-rift sequence in West Arthit area. The base case model was chosen from the age scenario of 27.0-23.1 Ma which exhibited four major cyclicities and matched with seismic mapping.\u0000 The study area had two depocenters, one in the northwest and another one in the southeast. The northern sub-basin was deepened earlier during the first rifting phase whereas the southern sub-basin was subsided later after the second rifting period. With the increase in sedimentation rate and subsidence rate during the third rifting phase, both depocenters were shallowed up and then become a shallow lake covering the whole study area. The last lifting phase coincided with the thermal subsidence that occurred and affected across the region; therefore, the regional extensive lacustrine accumulated in the study area.\u0000 The results from this study provided a crucial information on petroleum system especially depositional architecture, reservoir distribution, and potential source rock identification, which were incorporated into the planning of future exploration targeting in this field.\u0000 This study demonstrates the new innovative approach to determine the basin evolution and to understand the variation on depositional setting in the study area with limited well data. This approach also creates the project value by supporting the planning of future exploration and development wells. Furthermore, this technique can be applied to all projects to increase the discove","PeriodicalId":153269,"journal":{"name":"Day 2 Thu, March 02, 2023","volume":"515 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":"116217689","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
M. S. M. Allapitchai, Ahmad Johan, W. Liew, S. Sellapan, Khalil Ould Mohamed M’Bareck, Ahmad Hafizi Ahmad Zaini, M. A. Abdul Razak
Wells plug & abandonment was carried out in a deepwater field (Field C) offshore West Africa. There were 15 deepwater subsea wells, in this field. Thirteen of the wells were completed with Open Water Vertical Xmas Tree (OXT) while remaining two were completed with Enhanced Vertical Xmas Tree (EVXT). All the wells were permanently abandoned with permanent barriers established in accordance to Norsok D-010, rev 4. (2013). This involved establishing well barriers which would both horizontally and vertically effective. Plug and abandonment in a subsea environment remains a major challenge most operators face around the world. This paper will discuss the systematic approach to establish the methodology for plug placement by Operator for installing permanent abandonment barriers in their campaign. The paper shall discuss the systematic approach in permanent plug placement as well as highlight challenges and lessons learnts. The paper discusses the guidelines and philosophy to devise methodology for permanent plug placement based on industry capability. The paper also shares the novel approach in devising Plug Placement decision tree as well as well as explanation on principle behind the method. The paper will share on the process flow used by Operator for the permanent abandonment of these wells. Other than that, paper shall highlight the implementation of the decision tree during operations with examples. The best practices and lessons learnts in the plug placement methodology implementation during Operator's campaign in subsea plug and abandonment shall also be discussed in this paper. Ultimately, the paper shall also share on the recommendation for future subsea abandonment planning to assist Operator in their planning.
{"title":"A Systematic Approach in Methodology for Permanent Plug Placement in Deepwater Subsea Plug and Abandonment Campaign","authors":"M. S. M. Allapitchai, Ahmad Johan, W. Liew, S. Sellapan, Khalil Ould Mohamed M’Bareck, Ahmad Hafizi Ahmad Zaini, M. A. Abdul Razak","doi":"10.2523/iptc-22892-ms","DOIUrl":"https://doi.org/10.2523/iptc-22892-ms","url":null,"abstract":"\u0000 Wells plug & abandonment was carried out in a deepwater field (Field C) offshore West Africa. There were 15 deepwater subsea wells, in this field. Thirteen of the wells were completed with Open Water Vertical Xmas Tree (OXT) while remaining two were completed with Enhanced Vertical Xmas Tree (EVXT). All the wells were permanently abandoned with permanent barriers established in accordance to Norsok D-010, rev 4. (2013). This involved establishing well barriers which would both horizontally and vertically effective. Plug and abandonment in a subsea environment remains a major challenge most operators face around the world. This paper will discuss the systematic approach to establish the methodology for plug placement by Operator for installing permanent abandonment barriers in their campaign.\u0000 The paper shall discuss the systematic approach in permanent plug placement as well as highlight challenges and lessons learnts. The paper discusses the guidelines and philosophy to devise methodology for permanent plug placement based on industry capability. The paper also shares the novel approach in devising Plug Placement decision tree as well as well as explanation on principle behind the method. The paper will share on the process flow used by Operator for the permanent abandonment of these wells. Other than that, paper shall highlight the implementation of the decision tree during operations with examples. The best practices and lessons learnts in the plug placement methodology implementation during Operator's campaign in subsea plug and abandonment shall also be discussed in this paper. Ultimately, the paper shall also share on the recommendation for future subsea abandonment planning to assist Operator in their planning.","PeriodicalId":153269,"journal":{"name":"Day 2 Thu, March 02, 2023","volume":"80 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":"121686452","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}
E. Samuel, N. Nopsiri, Lee Chan Fong, Alxner Kalalo, Nicholas Moses, Agus Jayadi, Ding Yi, A. Nordin, Melissa Teoh
As fields mature, the drilling and completion design and execution for infill development becomes challenging. In a deepwater environment, one of the strategies to address this challenge is to optimize subsea facilities by targeting several reservoir packages in a single wellbore. However, this technique comes with technical challenges because penetrating different zones requires active reservoir management, an allowance for zonal isolation, and an adequate response to potential crossflow. A smart completion architecture should overcome these constraints and reduce overall capital expenditure while maximizing production. Furthermore, for wells requiring sand control, the completion solution must ensure a reliable and proven approach that minimizes the potential completion failures introduced by unsuccessful sand retention. This paper presents the completion strategy implemented in an intelligent well completed in the Malaysian deepwater Block K, during the field development of Siakap North Petai (SNP) Phase 2 and executed in Q1 2022.
随着油田的成熟，钻井和完井的设计和执行变得具有挑战性。在深水环境中，解决这一挑战的策略之一是通过在单个井眼中定位多个储层包来优化水下设施。然而，该技术面临着技术挑战，因为穿透不同的层需要积极的油藏管理，考虑层间隔离，以及对潜在的交叉流的充分响应。智能完井架构应该克服这些限制，在最大限度地提高产量的同时减少总体资本支出。此外，对于需要防砂的井，完井解决方案必须确保可靠且经过验证的方法，以最大限度地减少因留砂失败而导致的完井失败。本文介绍了马来西亚深水区块K在Siakap North Petai (SNP)第二期油田开发期间实施的智能井完井策略，该井于2022年第一季度执行。
{"title":"Advancement of Open Hole Gravel Pack and Zonal Isolation with Selective Intelligent Completion in Deepwater Malaysia","authors":"E. Samuel, N. Nopsiri, Lee Chan Fong, Alxner Kalalo, Nicholas Moses, Agus Jayadi, Ding Yi, A. Nordin, Melissa Teoh","doi":"10.2523/iptc-22882-ms","DOIUrl":"https://doi.org/10.2523/iptc-22882-ms","url":null,"abstract":"\u0000 As fields mature, the drilling and completion design and execution for infill development becomes challenging. In a deepwater environment, one of the strategies to address this challenge is to optimize subsea facilities by targeting several reservoir packages in a single wellbore. However, this technique comes with technical challenges because penetrating different zones requires active reservoir management, an allowance for zonal isolation, and an adequate response to potential crossflow. A smart completion architecture should overcome these constraints and reduce overall capital expenditure while maximizing production. Furthermore, for wells requiring sand control, the completion solution must ensure a reliable and proven approach that minimizes the potential completion failures introduced by unsuccessful sand retention. This paper presents the completion strategy implemented in an intelligent well completed in the Malaysian deepwater Block K, during the field development of Siakap North Petai (SNP) Phase 2 and executed in Q1 2022.","PeriodicalId":153269,"journal":{"name":"Day 2 Thu, March 02, 2023","volume":"19 4","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"113960676","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 common and costly situations in drilling operations is stuck pipe recovery, as it results in significant non-productive time (NPT). Stuck pipe is often freed by applying axial jarring forces to the string to overcome the sticking force. However, becoming stuck at a shallow depth often results in insufficient pipe stretch in the string to generate enough energy to free the stuck pipe using a jar. In cases where it is not applicable to use a jar, the use of the Oscillation Fishing System (OFS) is a more effective technique and an optimal solution to free the stuck pipe. Using the OFS to free stuck pipe encompasses generating continuous oscillatory axial motion. Pressure pulsations generated within the tool are converted to steady axial oscillations using the springs in the tool. This continuous motion produces axial forces at high frequencies, which translates to continuous energy applied to the stuck pipe. The OFS is used in different fishing applications, such as vertical and directional well profiles. The technology is used to free stuck pipes in cased and open holes. Depending on the stuck situation, the OFS is either placed at the surface or downhole with conventional bottom hole assemblies (BHA). In the subject applications, the OFS was run at the surface to free both motor and slick rotary BHAs in large hole sizes, 22 in. and 16 in., in different scenarios. This paper will analyze four examples where the OFS was used in a similar application. In all these examples, conventional stroking tools (i.e., fishing jar) were not part of the system and jars were not used to avoid the potential hazards of impact forces affecting the rig floor. Moreover, activating jars at shallower depths is ineffective as it requires a longer length of pipe to generate enough energy to free the stuck fish. The OFS was used after unsuccessful attempts to pull and recover the string. When the OFS was activated at the surface, producing continuous axial movement, it successfully freed the stuck fish. A new application of the OFS in fishing operations was introduced by using it in the surface sections. Not only did the OFS eliminate the extra steps required to get closer to the stuck point, but also it saved rig time and drillstring components and prevented the need for sidetracking. This paper discusses the use of the OFS at the surface in three examples, including an analysis of the performance to free the stuck string.
{"title":"Oscillation Fishing System: A Novel Approach to Improve the Chances of Freeing Shallow Mechanical Stuck Pipe","authors":"Kyungnam Han, S. Alharbi, A. Albaqshi, A. Eltoum","doi":"10.2523/iptc-22910-ea","DOIUrl":"https://doi.org/10.2523/iptc-22910-ea","url":null,"abstract":"\u0000 One of the most common and costly situations in drilling operations is stuck pipe recovery, as it results in significant non-productive time (NPT). Stuck pipe is often freed by applying axial jarring forces to the string to overcome the sticking force. However, becoming stuck at a shallow depth often results in insufficient pipe stretch in the string to generate enough energy to free the stuck pipe using a jar.\u0000 In cases where it is not applicable to use a jar, the use of the Oscillation Fishing System (OFS) is a more effective technique and an optimal solution to free the stuck pipe. Using the OFS to free stuck pipe encompasses generating continuous oscillatory axial motion. Pressure pulsations generated within the tool are converted to steady axial oscillations using the springs in the tool. This continuous motion produces axial forces at high frequencies, which translates to continuous energy applied to the stuck pipe.\u0000 The OFS is used in different fishing applications, such as vertical and directional well profiles. The technology is used to free stuck pipes in cased and open holes. Depending on the stuck situation, the OFS is either placed at the surface or downhole with conventional bottom hole assemblies (BHA). In the subject applications, the OFS was run at the surface to free both motor and slick rotary BHAs in large hole sizes, 22 in. and 16 in., in different scenarios.\u0000 This paper will analyze four examples where the OFS was used in a similar application. In all these examples, conventional stroking tools (i.e., fishing jar) were not part of the system and jars were not used to avoid the potential hazards of impact forces affecting the rig floor. Moreover, activating jars at shallower depths is ineffective as it requires a longer length of pipe to generate enough energy to free the stuck fish. The OFS was used after unsuccessful attempts to pull and recover the string. When the OFS was activated at the surface, producing continuous axial movement, it successfully freed the stuck fish.\u0000 A new application of the OFS in fishing operations was introduced by using it in the surface sections. Not only did the OFS eliminate the extra steps required to get closer to the stuck point, but also it saved rig time and drillstring components and prevented the need for sidetracking. This paper discusses the use of the OFS at the surface in three examples, including an analysis of the performance to free the stuck string.","PeriodicalId":153269,"journal":{"name":"Day 2 Thu, March 02, 2023","volume":"46 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-02-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"132547481","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}
Rehan Shahreyar, Mitchell Kelly, Charles Albouy, Benjamin Saltel, Benjamin Le Pouezard
This paper describes how an operator restored the casing integrity of a nonproducing well to resume offshore drilling operations by installing four 10¾-in. overlapping expandable steel patches. From 2020 to 2022, the operator scheduled a sidetrack drilling program, Māui A Crestal Infill (MACI), from the Māui A offshore platform, located in the Taranaki Basin of New Zealand. The operations included eight wells targeting the remaining unswept zones within the Māui A structure. During a reentry in a plugged and abandoned well, MA-03, a multifinger caliper log and a failed pressure test indicated a casing leak in the 10¾-in. intermediate casing. The log identified severe longitudinal casing wear with some fully penetrating holes. This lack of integrity prevented the scheduled operations from being performed. Several lost circulation material (LCM) and cement squeeze jobs attempted to seal off the leak but were unsuccessful. A service company proposed a mechanical repair solution to cover the long interval with four 13-m- (42.7-ft)-long customized, overlapping patches. Later, a second caliper was run to check if the cement squeeze jobs had reinforced the area for better patch support. Surprisingly, the zone appeared significantly more damaged, with a complete circumferential casing breach. Thus, the planned solution looked very challenging to implement. A video camera run, additional thinking, modeling, and cooperative engineering led to a complete redesign of the solution. The lengths and positions of the patches were changed, and one of the patches was assigned to serve as an inner reinforcement. The team assembled, deployed, and installed the patches in an accelerated mode. In 10 days, the casing integrity was fully restored, enabling the 8½-in. sidetrack hole to be drilled to total depth. This case is a typical example of how industry practices should evolve regarding the management of casing integrity issues. Remedial cement squeezes are often prioritized over mechanical options, even though mechanical options are now adjustable, much quicker to implement, and likely offer greater success rates.
{"title":"How Expandable Casing Patches Can Restore Casing Integrity and Enable the Sidetracking of an Old Well","authors":"Rehan Shahreyar, Mitchell Kelly, Charles Albouy, Benjamin Saltel, Benjamin Le Pouezard","doi":"10.2523/iptc-22810-ms","DOIUrl":"https://doi.org/10.2523/iptc-22810-ms","url":null,"abstract":"\u0000 This paper describes how an operator restored the casing integrity of a nonproducing well to resume offshore drilling operations by installing four 10¾-in. overlapping expandable steel patches.\u0000 From 2020 to 2022, the operator scheduled a sidetrack drilling program, Māui A Crestal Infill (MACI), from the Māui A offshore platform, located in the Taranaki Basin of New Zealand. The operations included eight wells targeting the remaining unswept zones within the Māui A structure. During a reentry in a plugged and abandoned well, MA-03, a multifinger caliper log and a failed pressure test indicated a casing leak in the 10¾-in. intermediate casing. The log identified severe longitudinal casing wear with some fully penetrating holes. This lack of integrity prevented the scheduled operations from being performed.\u0000 Several lost circulation material (LCM) and cement squeeze jobs attempted to seal off the leak but were unsuccessful. A service company proposed a mechanical repair solution to cover the long interval with four 13-m- (42.7-ft)-long customized, overlapping patches. Later, a second caliper was run to check if the cement squeeze jobs had reinforced the area for better patch support. Surprisingly, the zone appeared significantly more damaged, with a complete circumferential casing breach. Thus, the planned solution looked very challenging to implement.\u0000 A video camera run, additional thinking, modeling, and cooperative engineering led to a complete redesign of the solution. The lengths and positions of the patches were changed, and one of the patches was assigned to serve as an inner reinforcement.\u0000 The team assembled, deployed, and installed the patches in an accelerated mode. In 10 days, the casing integrity was fully restored, enabling the 8½-in. sidetrack hole to be drilled to total depth.\u0000 This case is a typical example of how industry practices should evolve regarding the management of casing integrity issues. Remedial cement squeezes are often prioritized over mechanical options, even though mechanical options are now adjustable, much quicker to implement, and likely offer greater success rates.","PeriodicalId":153269,"journal":{"name":"Day 2 Thu, March 02, 2023","volume":"67 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":"132745528","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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