An LNG plant in Australia was designed to maximize energy efficiency and minimize greenhouse gas emissions. In steady-state operations, its greenhouse gas emissions are lower than any in-country LNG project. Typically, gas supplied from two offshore fields contains CO2 (~14%) and high-volume operations run smoothly. At the time of this project, an injector well was found to have critically high CO2 levels (99%), and two other injector wells were shut-in due to pressure anomalies. A solution was needed to confirm casing isolation and detect leakage, while maintaining well barrier integrity and monitoring pressure/temperature below the tubing hanger plug. An innovative acoustic transmission platform served as a barrier assurance tool. A transmitter module (below the plug) has pressure/temperature sensors sending data through tubular/casing walls. A receiver module (above the plug) also houses pressure/temperature sensors. Once configured and deployed downhole, barrier installation is recorded, and barrier setting is verified before pressure testing. During the pressure test, sensors record pressure/temperature (in Wireline mode or fed live to surface) from either side of the barrier, confirming its integrity. The integrated wireless barrier monitoring solution exceeded customer expectations, with continuous acoustic and wireless communication maintained throughout the entire operation. Simultaneous monitoring of two wells for 500+ hours accurately documented the barrier integrity via pressure testing results. The system was run downhole in conjunction with a non-explosive slickline setting tool and retrievable bridge plug allowing to not only log the setting sequence for quality assurance but also record the pressure & temperature across the barrier. Conducted on-location, the customer was able to witness the plugs being successfully set. They then received positive confirmation of established well barrier, by continuous monitoring of the pressure between the two barriers and interpreting data from the wireless system in real time. This combined technology approach reduces time to troubleshoot and verify barriers, enabling quick evaluation of the leak source. Other benefits include significant time savings over traditional isolation methods, improving personnel safety in the well bay area by conducting real-time diagnostics, while also optimizing the suspension to allow efficient intervention or abandonment operations. The main objective of the operation was met, and verification of the shallow set plug was achieved. Barrier verification without the acoustic real-time wireless system would have been questionable. During well intervention for a major LNG plant operator in Western Australia, the novel wireless barrier monitoring solution delivered efficient, real-time pressure testing and verification to ensure success. This marks the first global installation of an integrated barrier system, combining retrievable bridge plug with wireless acous
{"title":"Integrated Wireless Barrier Monitoring System Improves CO2 Well Intervention Efficiency","authors":"V. Azevedo, Firman Paluruan, Robert Skwara","doi":"10.2523/iptc-22891-ea","DOIUrl":"https://doi.org/10.2523/iptc-22891-ea","url":null,"abstract":"\u0000 An LNG plant in Australia was designed to maximize energy efficiency and minimize greenhouse gas emissions. In steady-state operations, its greenhouse gas emissions are lower than any in-country LNG project. Typically, gas supplied from two offshore fields contains CO2 (~14%) and high-volume operations run smoothly. At the time of this project, an injector well was found to have critically high CO2 levels (99%), and two other injector wells were shut-in due to pressure anomalies.\u0000 A solution was needed to confirm casing isolation and detect leakage, while maintaining well barrier integrity and monitoring pressure/temperature below the tubing hanger plug. An innovative acoustic transmission platform served as a barrier assurance tool. A transmitter module (below the plug) has pressure/temperature sensors sending data through tubular/casing walls. A receiver module (above the plug) also houses pressure/temperature sensors. Once configured and deployed downhole, barrier installation is recorded, and barrier setting is verified before pressure testing. During the pressure test, sensors record pressure/temperature (in Wireline mode or fed live to surface) from either side of the barrier, confirming its integrity.\u0000 The integrated wireless barrier monitoring solution exceeded customer expectations, with continuous acoustic and wireless communication maintained throughout the entire operation. Simultaneous monitoring of two wells for 500+ hours accurately documented the barrier integrity via pressure testing results. The system was run downhole in conjunction with a non-explosive slickline setting tool and retrievable bridge plug allowing to not only log the setting sequence for quality assurance but also record the pressure & temperature across the barrier. Conducted on-location, the customer was able to witness the plugs being successfully set. They then received positive confirmation of established well barrier, by continuous monitoring of the pressure between the two barriers and interpreting data from the wireless system in real time. This combined technology approach reduces time to troubleshoot and verify barriers, enabling quick evaluation of the leak source. Other benefits include significant time savings over traditional isolation methods, improving personnel safety in the well bay area by conducting real-time diagnostics, while also optimizing the suspension to allow efficient intervention or abandonment operations. The main objective of the operation was met, and verification of the shallow set plug was achieved. Barrier verification without the acoustic real-time wireless system would have been questionable.\u0000 During well intervention for a major LNG plant operator in Western Australia, the novel wireless barrier monitoring solution delivered efficient, real-time pressure testing and verification to ensure success. This marks the first global installation of an integrated barrier system, combining retrievable bridge plug with wireless acous","PeriodicalId":153269,"journal":{"name":"Day 2 Thu, March 02, 2023","volume":"57 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":"129877309","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}
Xuechen Tang, Yiqiang Li, Jinxin Cao, Zheyu Liu, Xin Chen, Li Liu, Jiangwei Bo
As one of the leading technologies for chemical enhanced oil recovery (cEOR), surfactant-polymer (SP) flooding technology has drawn the attention of petroleum scientists and engineers for many years. However, most of its application scenarios are based on the five-spot well pattern. Rarely reported is its EOR potential in an inverted seven-spot well pattern. Based on the physical properties of Karamay Oilfield in China, this paper studied the adaptability of the SP system in the inverted seven-spot well pattern. Firstly, the numerical simulation method and the single-core flooding experiment were used to compare the seepage intensities of the two well patterns and the EOR ability of the SP system under different seepage intensities. Then, the migration law and the oil displacement effect of the SP system under the conditions of sand-gravel mixture were evaluated. Finally, the EOR ability under different injection strategies in the well patterns was evaluated. The results show that the inverted seven-spot well pattern shows a weak swept state, accounting for 61% of the whole region. Appropriately increasing the viscosity and slug size of the SP system improves the oil production of the low-permeability conglomerate layer. Step-down viscosity injection can further enlarge the sweep range of injection fluid and enhance oil recovery compared to constant viscosity injection. Compared with the five-spot well pattern, the swept area of the SP system in the inverted seven-spot well pattern is larger while the strength is weaker. The injection and production wells should be reasonably arranged when the well pattern is converted to efficiently recover the remaining oil and residual oil that are not recovered in the five-spot well pattern by utilizing the inverted seven-spot well pattern characteristics.
{"title":"Research on the Adaptability of SP Flooding in Sand-Gravel Mixture Reservoir Based on the Inverted Seven-Spot Well Pattern","authors":"Xuechen Tang, Yiqiang Li, Jinxin Cao, Zheyu Liu, Xin Chen, Li Liu, Jiangwei Bo","doi":"10.2523/iptc-22903-ms","DOIUrl":"https://doi.org/10.2523/iptc-22903-ms","url":null,"abstract":"\u0000 As one of the leading technologies for chemical enhanced oil recovery (cEOR), surfactant-polymer (SP) flooding technology has drawn the attention of petroleum scientists and engineers for many years. However, most of its application scenarios are based on the five-spot well pattern. Rarely reported is its EOR potential in an inverted seven-spot well pattern. Based on the physical properties of Karamay Oilfield in China, this paper studied the adaptability of the SP system in the inverted seven-spot well pattern. Firstly, the numerical simulation method and the single-core flooding experiment were used to compare the seepage intensities of the two well patterns and the EOR ability of the SP system under different seepage intensities. Then, the migration law and the oil displacement effect of the SP system under the conditions of sand-gravel mixture were evaluated. Finally, the EOR ability under different injection strategies in the well patterns was evaluated. The results show that the inverted seven-spot well pattern shows a weak swept state, accounting for 61% of the whole region. Appropriately increasing the viscosity and slug size of the SP system improves the oil production of the low-permeability conglomerate layer. Step-down viscosity injection can further enlarge the sweep range of injection fluid and enhance oil recovery compared to constant viscosity injection. Compared with the five-spot well pattern, the swept area of the SP system in the inverted seven-spot well pattern is larger while the strength is weaker. The injection and production wells should be reasonably arranged when the well pattern is converted to efficiently recover the remaining oil and residual oil that are not recovered in the five-spot well pattern by utilizing the inverted seven-spot well pattern characteristics.","PeriodicalId":153269,"journal":{"name":"Day 2 Thu, March 02, 2023","volume":"54 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":"133550594","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}
Swee Hong Gary Ong, Boon Shin Chia, L. Umar, N. Kongpat
HPHT wells are typically associated with high complexity, technically challenging, long duration, high risk and high NPT as many things could go wrong especially when any of the critical nitty- gritty details are overlooked. The complexity is amplified with high risk of losses in carbonate reservoir with high level of contaminants compounded by the requirement of high mud weight above 17 ppg during monsoon season in an offshore environment. The above sums up the challenges an operator had to manage in a groundbreaking HPHT carbonate appraisal well which had successfully pushed the historical envelope of such well category in Central Luconia area, off the coast of Sarawak where one of the new records of the deepest and hottest carbonate HPHT well had been created. This well took almost 4 months to drill with production testing carried out in a safe and efficient manner whereby more than 4000m of vertical interval was covered by 6 hole sections. With the seamless support from host authority, JV partners and all contractors, the well was successfully delivered within the planned duration and cost, despite the extreme challenges brought about by the COVID-19 pandemic. This paper will share the experience of the entire cycle from pre job engineering/planning, execution, key lesson learnt and optimization plan for future exploitations which includes an appraisal well and followed by more than a dozen of development wells.
{"title":"Successful Drilling of the Deepest and Hottest HPHT Carbonate Well in Offshore Malaysia, its Lesson Learnt and Way Forward","authors":"Swee Hong Gary Ong, Boon Shin Chia, L. Umar, N. Kongpat","doi":"10.2523/iptc-22815-ms","DOIUrl":"https://doi.org/10.2523/iptc-22815-ms","url":null,"abstract":"\u0000 HPHT wells are typically associated with high complexity, technically challenging, long duration, high risk and high NPT as many things could go wrong especially when any of the critical nitty- gritty details are overlooked. The complexity is amplified with high risk of losses in carbonate reservoir with high level of contaminants compounded by the requirement of high mud weight above 17 ppg during monsoon season in an offshore environment.\u0000 The above sums up the challenges an operator had to manage in a groundbreaking HPHT carbonate appraisal well which had successfully pushed the historical envelope of such well category in Central Luconia area, off the coast of Sarawak where one of the new records of the deepest and hottest carbonate HPHT well had been created.\u0000 This well took almost 4 months to drill with production testing carried out in a safe and efficient manner whereby more than 4000m of vertical interval was covered by 6 hole sections.\u0000 With the seamless support from host authority, JV partners and all contractors, the well was successfully delivered within the planned duration and cost, despite the extreme challenges brought about by the COVID-19 pandemic.\u0000 This paper will share the experience of the entire cycle from pre job engineering/planning, execution, key lesson learnt and optimization plan for future exploitations which includes an appraisal well and followed by more than a dozen of development wells.","PeriodicalId":153269,"journal":{"name":"Day 2 Thu, March 02, 2023","volume":"3 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":"133045614","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}
T. Prasertbordeekul, P. Henglai, Naruttee Kovitkanit, K. Poret, C. Peng
One of the major decisions in managing mature oil fields is to look for opportunities to maximize recovery, such as investigating on the most feasible Improved Oil Recovery (IOR) techniques, especially in the today's volatile oil prices. This paper demonstrates a closed loop, integrated workflow using algorithm-assist reservoir simulation to evaluate the viability of an IOR project by optimizing all essential parameters in waterflood/polymer flood projects and calculate the project economics for all possible options. The outcome of the work results in the best scenario for deciding if the investment in IOR can be paid off. The possible causes on pressure depletion were thoroughly investigated in the well completion towards the geological concept. Both downhole pressure gauge and open-hole gravel pack design were validated to ensure their reading accuracy and performance. Apart from well investigation, the geological concept was analyzed by utilizing all cores, well-logs, seismic data as well as the regional understanding in deepwater setting. Once the possible root cause of pressure drop was identified, the hypothesis was integrated into the static model and tested by reservoir simulation study. Lastly, an appropriate solution will be proposed to optimize recoverable gas resources and prolong production plateau. The investigation over the well completion showed that the pressure depletion was not associated with downhole pressure gauge and well completion design. Whereas the geological setting of deepwater suggested that sheet sand deposit in this field containing several hemipelagic shales. Regarding outcrop analogue, the hemipelagic shales are laterally widespread and can potentially be the primary cause for the unexpected pressure drop. Therefore, the presence of extensive hemipelagic shales as observed in both core and well-log information was included into static model. The updated static model was then calibrated with actual production data and the result showed a good history matching, which supported the presence of extensive hemipelagic shales and their negative impacted on production pressure. Moreover, our investigation also unraveled the fact that water channeling and undrained gas resources below these shale layers were the main reasons of shorter plateau period and lower recoverable gas resources. Consequently, we proposed an optimal solution by drilling infill wells in the up-dip position to access the undrained gas and to avoid water channeling in the down-dip position. With this new development plan, this study can increase the additional gas recoverable resources and extend the production plateau. This project demonstrates a robust workflow of among multi-disciplinary team from a well-founded geological concept, more accurate and justifiable reservoir model inputs, and hypothesis testing by reservoir modeling approach to achieve the optimal field development plan. In addition, this is an excellent opportunity for PTTEP comp
{"title":"Geology-Driven Reservoir Simulation for Deepwater Field Development Planning in Offshore Sabah, Malaysia","authors":"T. Prasertbordeekul, P. Henglai, Naruttee Kovitkanit, K. Poret, C. Peng","doi":"10.2523/iptc-22963-ea","DOIUrl":"https://doi.org/10.2523/iptc-22963-ea","url":null,"abstract":"\u0000 One of the major decisions in managing mature oil fields is to look for opportunities to maximize recovery, such as investigating on the most feasible Improved Oil Recovery (IOR) techniques, especially in the today's volatile oil prices. This paper demonstrates a closed loop, integrated workflow using algorithm-assist reservoir simulation to evaluate the viability of an IOR project by optimizing all essential parameters in waterflood/polymer flood projects and calculate the project economics for all possible options. The outcome of the work results in the best scenario for deciding if the investment in IOR can be paid off.\u0000 The possible causes on pressure depletion were thoroughly investigated in the well completion towards the geological concept. Both downhole pressure gauge and open-hole gravel pack design were validated to ensure their reading accuracy and performance. Apart from well investigation, the geological concept was analyzed by utilizing all cores, well-logs, seismic data as well as the regional understanding in deepwater setting. Once the possible root cause of pressure drop was identified, the hypothesis was integrated into the static model and tested by reservoir simulation study. Lastly, an appropriate solution will be proposed to optimize recoverable gas resources and prolong production plateau.\u0000 The investigation over the well completion showed that the pressure depletion was not associated with downhole pressure gauge and well completion design. Whereas the geological setting of deepwater suggested that sheet sand deposit in this field containing several hemipelagic shales. Regarding outcrop analogue, the hemipelagic shales are laterally widespread and can potentially be the primary cause for the unexpected pressure drop. Therefore, the presence of extensive hemipelagic shales as observed in both core and well-log information was included into static model. The updated static model was then calibrated with actual production data and the result showed a good history matching, which supported the presence of extensive hemipelagic shales and their negative impacted on production pressure. Moreover, our investigation also unraveled the fact that water channeling and undrained gas resources below these shale layers were the main reasons of shorter plateau period and lower recoverable gas resources. Consequently, we proposed an optimal solution by drilling infill wells in the up-dip position to access the undrained gas and to avoid water channeling in the down-dip position. With this new development plan, this study can increase the additional gas recoverable resources and extend the production plateau.\u0000 This project demonstrates a robust workflow of among multi-disciplinary team from a well-founded geological concept, more accurate and justifiable reservoir model inputs, and hypothesis testing by reservoir modeling approach to achieve the optimal field development plan. In addition, this is an excellent opportunity for PTTEP comp","PeriodicalId":153269,"journal":{"name":"Day 2 Thu, March 02, 2023","volume":"84 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":"133650804","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. Grant, P. Bandyopadhyay, Kittipat Wejwittayaklung, James Hunter Mansion, Swee Hong Gary Ong, Pornchuda Konganuntragul, Wararit Toempromraj, Prapapor Jantasuwanna, Choon How Lee, Boon Shin Chia, David Lewis
This paper deals with the lessons learned during the completion design for a HPHT gas field (Field-X) offshore Sarawak, Malaysia. It is a carbonate reservoir with more than 500 meters of the gas column containing between 6-10 tcf of OGIP making it one of the major discoveries in recent years in this region. However, the combination of HPHT and the presence of about 18% CO2 and 2% H2S in the gas makes it a complex development, particularly for well and completion design. To address the challenges associated with the development of this field, a taskforce was formed with personnel from all relevant disciplines to come up with an appropriate design that can help produce from this reservoir safely. The project is now in the detailed design phase where the final aspects of the completion designs are being formulated. Considering that this will be one of the first development in this area with this combination of reservoir conditions, it is expected that the lessons learned from this project will support other future developments too. The paper discusses lessons learned during the design process specifically related to material selection for the highly sour environment, temperature modeling, identification of annulus pressure envelopes and their management, perforation philosophy, and surveillance methods for both reservoir management and well integrity. Another aspect which affects the overall well and completion philosophy for a complex development is the challenges associated with procurement and component qualification. At this stage, the key issues are being identified and will be briefly covered in this paper.
{"title":"Lessons Learnt from the Completion Design for a HPHT Sour Gas Field Development in Offshore Sarawak","authors":"C. Grant, P. Bandyopadhyay, Kittipat Wejwittayaklung, James Hunter Mansion, Swee Hong Gary Ong, Pornchuda Konganuntragul, Wararit Toempromraj, Prapapor Jantasuwanna, Choon How Lee, Boon Shin Chia, David Lewis","doi":"10.2523/iptc-22881-ms","DOIUrl":"https://doi.org/10.2523/iptc-22881-ms","url":null,"abstract":"\u0000 This paper deals with the lessons learned during the completion design for a HPHT gas field (Field-X) offshore Sarawak, Malaysia. It is a carbonate reservoir with more than 500 meters of the gas column containing between 6-10 tcf of OGIP making it one of the major discoveries in recent years in this region. However, the combination of HPHT and the presence of about 18% CO2 and 2% H2S in the gas makes it a complex development, particularly for well and completion design.\u0000 To address the challenges associated with the development of this field, a taskforce was formed with personnel from all relevant disciplines to come up with an appropriate design that can help produce from this reservoir safely. The project is now in the detailed design phase where the final aspects of the completion designs are being formulated. Considering that this will be one of the first development in this area with this combination of reservoir conditions, it is expected that the lessons learned from this project will support other future developments too.\u0000 The paper discusses lessons learned during the design process specifically related to material selection for the highly sour environment, temperature modeling, identification of annulus pressure envelopes and their management, perforation philosophy, and surveillance methods for both reservoir management and well integrity.\u0000 Another aspect which affects the overall well and completion philosophy for a complex development is the challenges associated with procurement and component qualification. At this stage, the key issues are being identified and will be briefly covered in this paper.","PeriodicalId":153269,"journal":{"name":"Day 2 Thu, March 02, 2023","volume":"2012 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":"133481882","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}
Sew Keng Tan, M. M. M. Shah, S. Sufian, Pui Vun Chai
Constructed wetlands (CW) are man-made systems that mimic the natural wetlands. They can be used for various purposes, including wastewater treatment, stormwater management, and carbon sequestration. Wetlands naturally absorb and store carbon from the atmosphere, and CW can replicate this process by using plants and microorganisms to remove and store carbon from the water. Conventional wastewater treatment plants (WWTP) use more energy and contribute to carbon emissions, so many industries are looking for ways to reduce greenhouse gas (GHG) emissions. While CW have been widely used for municipal and sewage treatment, their use as an alternative or supplement to industrial wastewater treatment, particularly in the oil and gas and petrochemical industries, is limited. However, CW have the potential to promote carbon sequestration and have a lower cost of capital and operating expenses compared to conventional WWTP, while also emitting lower GHG emissions. A case study is presented for two types of system in which one is actual operating conventional WWTP in Malaysia design and operate at 60m3/d and a hybrid CW of equivalent treatment capability and capacity. The case study found that GHG emissions from a conventional WWTP were approximately 3.75 times higher than the hybrid CW system with the same treatment capacity. For a small capacity WWTP at 60m3 per day, converting the treatment system from conventional WWTP to CW will reduce approximately 45.7t CO2 eq per year based on Life Cycle Assessment (LCA) calculation. The conventional WWTP consumed much higher power especially from the air blower compared to CW where limited number of equipment is required. The additional carbon sink for CW from carbon sequestration from plant, soil decomposition and sediment has not been quantified in the LCA calculation. Hence, it is expected the actual CO2 eq emission for CW is much lesser than the conventional WWTP. With all the benefit identified and the proven success case in several places, the adoption of CW as an industrial WWTP should be widely promoted as the replacement of conventional WWTP for sustainable future.
{"title":"Constructed Wetland as an Alternative to Conventional Industrial Wastewater Treatment to Promote Carbon Sequestration for Sustainable Future","authors":"Sew Keng Tan, M. M. M. Shah, S. Sufian, Pui Vun Chai","doi":"10.2523/iptc-22913-ea","DOIUrl":"https://doi.org/10.2523/iptc-22913-ea","url":null,"abstract":"\u0000 Constructed wetlands (CW) are man-made systems that mimic the natural wetlands. They can be used for various purposes, including wastewater treatment, stormwater management, and carbon sequestration. Wetlands naturally absorb and store carbon from the atmosphere, and CW can replicate this process by using plants and microorganisms to remove and store carbon from the water. Conventional wastewater treatment plants (WWTP) use more energy and contribute to carbon emissions, so many industries are looking for ways to reduce greenhouse gas (GHG) emissions. While CW have been widely used for municipal and sewage treatment, their use as an alternative or supplement to industrial wastewater treatment, particularly in the oil and gas and petrochemical industries, is limited. However, CW have the potential to promote carbon sequestration and have a lower cost of capital and operating expenses compared to conventional WWTP, while also emitting lower GHG emissions. A case study is presented for two types of system in which one is actual operating conventional WWTP in Malaysia design and operate at 60m3/d and a hybrid CW of equivalent treatment capability and capacity. The case study found that GHG emissions from a conventional WWTP were approximately 3.75 times higher than the hybrid CW system with the same treatment capacity. For a small capacity WWTP at 60m3 per day, converting the treatment system from conventional WWTP to CW will reduce approximately 45.7t CO2 eq per year based on Life Cycle Assessment (LCA) calculation. The conventional WWTP consumed much higher power especially from the air blower compared to CW where limited number of equipment is required. The additional carbon sink for CW from carbon sequestration from plant, soil decomposition and sediment has not been quantified in the LCA calculation. Hence, it is expected the actual CO2 eq emission for CW is much lesser than the conventional WWTP. With all the benefit identified and the proven success case in several places, the adoption of CW as an industrial WWTP should be widely promoted as the replacement of conventional WWTP for sustainable future.","PeriodicalId":153269,"journal":{"name":"Day 2 Thu, March 02, 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":"125822765","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}
Witthaya Channarong, N. Taranut, T. Thamrongnāwāsawat
The Microplastics Baseline Study was initiated with a collaboration between PTTEP and Kasetsart University. The objective of this project is to measure microplastics level in the GoT through the use of PTTEP strength in location advantage cover PTTEP offshore facilities, Koh Losin, Koh Tao, and a coastal area in Chumphon. The baseline data was developed to support the government agencies scheme in fighting with Microplastics and identification of opportunities for further improvement. The microplastic sampling was conducted 3 times at each location and twice between 2020 – 2021 through the use of Manta net (the global standard tool) by the well trained PTTEP operators onsite. All collected Microplastic samples were sent to analyze microplastic components through the use of the cutting-edge technology such as Fourier Transform Infrared (FTIR). The result of Microplastics Baseline Study in the GoT is used as part of the Microplastics baseline data of Thailand. The study found that the average numbers of microplastics particles in water from our 3 offshore assets are between 0.33- 1.26 pieces of mini-microplastics/m3 of water or 82,137-314,009 pieces/km2, close to the level found in the Eastern North Pacific, compared to other studies from oversea, this is more than the study from the northwest Atlantic (12,000-20,000 particles/km2) but more akin to the study of the northeast pacific (90,000-278,000 particles/km2) and less than that of Pacific garbage patch (1,345,000 particles/km2). The study also showed that the portion of offshore microplastics from fibers usually found in fishery tools like nets and fishing lines is high when compared to nearshore microplastics. (48% Fishing Net/ Line). PTTEP aims to foster collaboration among academics and private sectors in safeguarding the oceans with the ultimate goal of achieving concrete marine resource conservations. The study marked Thailand's first attempt in conducting a baseline study of microplastics in the GoT and the world's first attempt to use a petroleum platform as a station to collect microplastic data.
{"title":"Microplastics Baseline Study in Gulf of Thailand: First Time in Thailand","authors":"Witthaya Channarong, N. Taranut, T. Thamrongnāwāsawat","doi":"10.2523/iptc-22899-ea","DOIUrl":"https://doi.org/10.2523/iptc-22899-ea","url":null,"abstract":"\u0000 The Microplastics Baseline Study was initiated with a collaboration between PTTEP and Kasetsart University. The objective of this project is to measure microplastics level in the GoT through the use of PTTEP strength in location advantage cover PTTEP offshore facilities, Koh Losin, Koh Tao, and a coastal area in Chumphon. The baseline data was developed to support the government agencies scheme in fighting with Microplastics and identification of opportunities for further improvement.\u0000 The microplastic sampling was conducted 3 times at each location and twice between 2020 – 2021 through the use of Manta net (the global standard tool) by the well trained PTTEP operators onsite. All collected Microplastic samples were sent to analyze microplastic components through the use of the cutting-edge technology such as Fourier Transform Infrared (FTIR). The result of Microplastics Baseline Study in the GoT is used as part of the Microplastics baseline data of Thailand.\u0000 The study found that the average numbers of microplastics particles in water from our 3 offshore assets are between 0.33- 1.26 pieces of mini-microplastics/m3 of water or 82,137-314,009 pieces/km2, close to the level found in the Eastern North Pacific, compared to other studies from oversea, this is more than the study from the northwest Atlantic (12,000-20,000 particles/km2) but more akin to the study of the northeast pacific (90,000-278,000 particles/km2) and less than that of Pacific garbage patch (1,345,000 particles/km2). The study also showed that the portion of offshore microplastics from fibers usually found in fishery tools like nets and fishing lines is high when compared to nearshore microplastics. (48% Fishing Net/ Line). PTTEP aims to foster collaboration among academics and private sectors in safeguarding the oceans with the ultimate goal of achieving concrete marine resource conservations.\u0000 The study marked Thailand's first attempt in conducting a baseline study of microplastics in the GoT and the world's first attempt to use a petroleum platform as a station to collect microplastic data.","PeriodicalId":153269,"journal":{"name":"Day 2 Thu, March 02, 2023","volume":"28 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":"130259259","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}
Cation exchange occurs when water with a different salinity as the connate brine is injected in a reservoir. During polymer flooding operations, the potential release of divalent cations by the rock can have a detrimental impact on the in-situ viscosity in the polymer bank. The objective of this work was to assess for the risk related to cations exchange in an Argentinian oilfield and to provide guidelines for the injection water design. Reservoir rock samples were first submitted to mineralogical analysis involving scanning-electron microscopy (SEM), X-Ray Diffraction (XRD) and determination of their Cation Exchange Capacities (CEC). Coreflood tests were then performed where the effluents were analyzed for their cations composition. In these experiments, two main scenarios for the composition of the low-salinity injection water (with or without softening) were investigated and the transport properties of the polymer were determined. As a more exploratory approach, polymer was also injected in a 12-meter-long slim tube filled with crushed reservoir rock, to assess if it could be exposed to released cations. The results showed that all reservoir rocks investigated had high CEC, which was consistent with their high clay contents, and that significant cations exchanges took place during low salinity water injection, although no formation damage occurred, showing the stability of the clays. During injection of the softened water, evidences of significant divalent (and monovalent) cations release from the rock were found. During injection of the unsoftened water, a marked and long-term adsorption of the injected calcium cations was observed, corresponding to a depletion in calcium of the injected water. This suggests that, quite counter-intuitively, using unsoftened water as polymer make up water could be interesting in view of economics because the cations exchanges could entail an increase of the in-situ viscosity. The coreflood test results also showed that the presence of polymer in the injected water had no impact on the cations exchanges mechanisms. The partial results from the slim tube injection test suggested, however, that the retardation of the polymer bank caused by polymer adsorption was sufficient to avoid for its viscosity to be affected by the changes in cations distribution. This study illustrates the importance of cation exchange mechanisms and their potential impact for polymer flooding. It also shows that these effects can be investigated in a representative manner at the lab and that practical guidelines for the composition of the polymer injection water can be deduced from the experiments, provided a risk for in-situ viscosity reduction is identified.
{"title":"Impact Of Cation Exchange On Polymer In-Situ Viscosity: An Experimental Investigation For A Low-Salinity Polymer Flooding Case","authors":"D. Rousseau, M. Salaün","doi":"10.2523/iptc-22907-ms","DOIUrl":"https://doi.org/10.2523/iptc-22907-ms","url":null,"abstract":"\u0000 Cation exchange occurs when water with a different salinity as the connate brine is injected in a reservoir. During polymer flooding operations, the potential release of divalent cations by the rock can have a detrimental impact on the in-situ viscosity in the polymer bank. The objective of this work was to assess for the risk related to cations exchange in an Argentinian oilfield and to provide guidelines for the injection water design.\u0000 Reservoir rock samples were first submitted to mineralogical analysis involving scanning-electron microscopy (SEM), X-Ray Diffraction (XRD) and determination of their Cation Exchange Capacities (CEC). Coreflood tests were then performed where the effluents were analyzed for their cations composition. In these experiments, two main scenarios for the composition of the low-salinity injection water (with or without softening) were investigated and the transport properties of the polymer were determined. As a more exploratory approach, polymer was also injected in a 12-meter-long slim tube filled with crushed reservoir rock, to assess if it could be exposed to released cations.\u0000 The results showed that all reservoir rocks investigated had high CEC, which was consistent with their high clay contents, and that significant cations exchanges took place during low salinity water injection, although no formation damage occurred, showing the stability of the clays. During injection of the softened water, evidences of significant divalent (and monovalent) cations release from the rock were found. During injection of the unsoftened water, a marked and long-term adsorption of the injected calcium cations was observed, corresponding to a depletion in calcium of the injected water. This suggests that, quite counter-intuitively, using unsoftened water as polymer make up water could be interesting in view of economics because the cations exchanges could entail an increase of the in-situ viscosity. The coreflood test results also showed that the presence of polymer in the injected water had no impact on the cations exchanges mechanisms. The partial results from the slim tube injection test suggested, however, that the retardation of the polymer bank caused by polymer adsorption was sufficient to avoid for its viscosity to be affected by the changes in cations distribution.\u0000 This study illustrates the importance of cation exchange mechanisms and their potential impact for polymer flooding. It also shows that these effects can be investigated in a representative manner at the lab and that practical guidelines for the composition of the polymer injection water can be deduced from the experiments, provided a risk for in-situ viscosity reduction is identified.","PeriodicalId":153269,"journal":{"name":"Day 2 Thu, March 02, 2023","volume":"125 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":"127405061","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}
Carbon capture and storage (CCS) presents a key solution to reducing emissions especially from stationary power and industrial sites. A major component of CCS is CO2 storage in geologic formations, including saline aquifers, presents a great opportunity for the oil and gas industry to capitalize on their subsurface expertise to ensure that CO2 is stored safely underground over the long term. Saline aquifers are particularly relevant in the Middle East, where hydrocarbon reservoirs may not be at high depletion stages and so may not be available for CO2 storage yet. This paper looks at key geologic formation considerations related to CO2 storage in saline aquifers, highlighting the static and dynamic characteristics of the rock and the fluids that determine how much CO2 can be stored and at what injection rate. It also highlights how these characteristics affect the economics of the subsurface component of a CCS project. This paper shall provide an overview of the key aspects that guide subsurface storage evaluations: containment ability, trapping mechanisms, storage capacity, and injectivity. It will highlight the different storage capacity assessment methods. Then it shall discuss resource classification and categorization, and determination of commerciality as per the SPE CO2 Storage Resources Management System (SRMS). Finally, the paper goes into further considerations that need to be taken into account beyond the initial screening, including the data acquisition program and the impact of CO2 stream impurities on storage potential, geologic formation properties and cap rock integrity. The work illustrates the importance of understanding the physics of CO2 injection into a water-bearing system and lays out considerations for screening potential saline aquifer sites from a reservoir engineering perspective. The screening process should evaluate the anticipated CO2 trapping mechanism, assure its ability to contain the injected fluids over the long term, and estimate its storage capacity and injectivity.
{"title":"Key Considerations for Screening and Selection of Saline Aquifers for CO2 Storage","authors":"Malik Alarfaj, Angelo Vidal Faez","doi":"10.2523/iptc-22838-ms","DOIUrl":"https://doi.org/10.2523/iptc-22838-ms","url":null,"abstract":"\u0000 Carbon capture and storage (CCS) presents a key solution to reducing emissions especially from stationary power and industrial sites. A major component of CCS is CO2 storage in geologic formations, including saline aquifers, presents a great opportunity for the oil and gas industry to capitalize on their subsurface expertise to ensure that CO2 is stored safely underground over the long term. Saline aquifers are particularly relevant in the Middle East, where hydrocarbon reservoirs may not be at high depletion stages and so may not be available for CO2 storage yet. This paper looks at key geologic formation considerations related to CO2 storage in saline aquifers, highlighting the static and dynamic characteristics of the rock and the fluids that determine how much CO2 can be stored and at what injection rate. It also highlights how these characteristics affect the economics of the subsurface component of a CCS project.\u0000 This paper shall provide an overview of the key aspects that guide subsurface storage evaluations: containment ability, trapping mechanisms, storage capacity, and injectivity. It will highlight the different storage capacity assessment methods. Then it shall discuss resource classification and categorization, and determination of commerciality as per the SPE CO2 Storage Resources Management System (SRMS). Finally, the paper goes into further considerations that need to be taken into account beyond the initial screening, including the data acquisition program and the impact of CO2 stream impurities on storage potential, geologic formation properties and cap rock integrity.\u0000 The work illustrates the importance of understanding the physics of CO2 injection into a water-bearing system and lays out considerations for screening potential saline aquifer sites from a reservoir engineering perspective. The screening process should evaluate the anticipated CO2 trapping mechanism, assure its ability to contain the injected fluids over the long term, and estimate its storage capacity and injectivity.","PeriodicalId":153269,"journal":{"name":"Day 2 Thu, March 02, 2023","volume":"7 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":"130968102","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 study area belongs to Qaidam Basin of Tibetan Plateau. It has extremely complex structural and sedimentological conditions which seriously hinder in-depth geological understanding and effective exploration and development activities. We solve the problems to a great extent with highly integrated unique geophysical and geological modeling. The solutions mainly included: (1) Continuously improving the quality of seismic image by updating the PSDM cube twice during project execution based on a unique workflow of Coupled Geophysical & Geological Modeling; (2) Adjusting/consolidating seismic structural interpretation, well tops, and structural information on microresistivity images reiteratively to obtain robust structural interpretations; (3) Structural modeling with the method suitable for complex structural background; (4) Property modeling with combined constraints of well data, seismic trend, sedimentary cycle, variogram and geological understanding, such as using element logging interpretation results for Lithofacies, Mineral composition and Porosity models; (5) DFN fracture modeling with fracture statistics from microresistivity images, seismic edge-detection cube, seismic drivers and NFP geomechanical drivers. Not only are the double complex reservoirs effectively characterized, but also many meaningful geological conclusions are reached which in turn could guide more effective E&P activities, including (1) distributions of oil-bearing belts, pools, and high-production wells are all controlled obviously by structural patterns; (2) although the reservoirs belong to a very large lacustrine basin sedimentologically, great heterogeneity still commonly exists, with many local structural highs and lows causing quick variation of microfacies in plan view; (3) source rocks, reservoirs, traps and preservation condition are the key factors for oil abundance; (4) four geological conditions need to be carefully evaluated for any outskirt well design & drilling, etc. Based on the results, measured OOIP of tens of millions of tons has been summitted to the country, a bunch of kiloton-oil exploration wells have been drilled and dozens of optimized development wells have been placed in recent years. We realize "for the first time" in some aspects for effectively characterizing the saline lacustrine thin tight oil reservoirs on tectonically complex Tibetan plateau. This study can be referred to by other geologically complex regions in the industry.
{"title":"Unravelling the Mystery of Double Complex Unconventional Reservoirs on Tibetan Plateau by Highly Integrated Geophysical and Geological Modelling","authors":"Yanming Tong, Xiaodong Chen, Qinghui Zhang, Chuan Wu, Chenqing Tan, Farun Gao, Ning Guo, Wulin Tan, Monthathip Kosolpinete","doi":"10.2523/iptc-22829-ea","DOIUrl":"https://doi.org/10.2523/iptc-22829-ea","url":null,"abstract":"\u0000 The study area belongs to Qaidam Basin of Tibetan Plateau. It has extremely complex structural and sedimentological conditions which seriously hinder in-depth geological understanding and effective exploration and development activities. We solve the problems to a great extent with highly integrated unique geophysical and geological modeling.\u0000 The solutions mainly included: (1) Continuously improving the quality of seismic image by updating the PSDM cube twice during project execution based on a unique workflow of Coupled Geophysical & Geological Modeling; (2) Adjusting/consolidating seismic structural interpretation, well tops, and structural information on microresistivity images reiteratively to obtain robust structural interpretations; (3) Structural modeling with the method suitable for complex structural background; (4) Property modeling with combined constraints of well data, seismic trend, sedimentary cycle, variogram and geological understanding, such as using element logging interpretation results for Lithofacies, Mineral composition and Porosity models; (5) DFN fracture modeling with fracture statistics from microresistivity images, seismic edge-detection cube, seismic drivers and NFP geomechanical drivers.\u0000 Not only are the double complex reservoirs effectively characterized, but also many meaningful geological conclusions are reached which in turn could guide more effective E&P activities, including (1) distributions of oil-bearing belts, pools, and high-production wells are all controlled obviously by structural patterns; (2) although the reservoirs belong to a very large lacustrine basin sedimentologically, great heterogeneity still commonly exists, with many local structural highs and lows causing quick variation of microfacies in plan view; (3) source rocks, reservoirs, traps and preservation condition are the key factors for oil abundance; (4) four geological conditions need to be carefully evaluated for any outskirt well design & drilling, etc.\u0000 Based on the results, measured OOIP of tens of millions of tons has been summitted to the country, a bunch of kiloton-oil exploration wells have been drilled and dozens of optimized development wells have been placed in recent years.\u0000 We realize \"for the first time\" in some aspects for effectively characterizing the saline lacustrine thin tight oil reservoirs on tectonically complex Tibetan plateau. This study can be referred to by other geologically complex regions in the industry.","PeriodicalId":153269,"journal":{"name":"Day 2 Thu, March 02, 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":"131046235","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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