Hajir Qassabi, A. Rafliansyah, Johnny Falla, Ahmed Al-Yaaribi
The objective of matrix acidizing in sandstone reservoirs using acid systems that contains Hydrofluoric acid (HF) is to widen the pore throats and spaces in order to increase the permeability around the wellbore and also to remove formation damage. One of the major disadvantages of this acid system is the secondary and tertiary reactions, which may end up with precipitations that damage the formation. Because of this, pumping sufficient pre- flush and post-flush volumes of Hydrochloric acid (HCl) is critical to prevent such damaging reactions. However, the placement of such fluids still are a concern in multiple opened layers or long open intervals zones. Stimulating sandstone reservoirs in the Southern fields of the Sultanate of Oman is very challenging, especially in those that exhibit relatively low permeability. These formations, based on petrology work, contains significant amount of clays and feldspars, which make it difficult in the designing process of the acid formulation. A new version of HF acid system was recently developed. It is specially formulated, so it does not require the addition of Hydrochloric acid (HCl) pre-flush. Because of this, it can be pumped as a single stage system. In addition, its higher reactivity allows deeper penetration and it has the ability to minimize secondary reactions and damaging precipitates. Lab testing work was conducted to ensure the effectiveness of this single stage acid system. The results were promising as they show a good improvement in the rock permeability. These results were encouraging to carry field trials in the sandstone reservoirs in Oman Southern fields. Up to now, it has been pumped in these type of sandstones for oil producer wells and for water injector wells. The actual treatment using this system showed increased oil productivity by higher than 60% and higher than 80% in water injectivity. This paper presents the testing, designing and pumping of the single stage acid system, as well as the comparison with the conventional HF acid system in Southern fields of Oman. It outlines the laboratory work and analysis done as well as the field trials.
{"title":"First Application in Oman of New Single Stage Retarded Sandstone Matrix Acidizing","authors":"Hajir Qassabi, A. Rafliansyah, Johnny Falla, Ahmed Al-Yaaribi","doi":"10.2118/200297-ms","DOIUrl":"https://doi.org/10.2118/200297-ms","url":null,"abstract":"\u0000 The objective of matrix acidizing in sandstone reservoirs using acid systems that contains Hydrofluoric acid (HF) is to widen the pore throats and spaces in order to increase the permeability around the wellbore and also to remove formation damage. One of the major disadvantages of this acid system is the secondary and tertiary reactions, which may end up with precipitations that damage the formation. Because of this, pumping sufficient pre- flush and post-flush volumes of Hydrochloric acid (HCl) is critical to prevent such damaging reactions. However, the placement of such fluids still are a concern in multiple opened layers or long open intervals zones.\u0000 Stimulating sandstone reservoirs in the Southern fields of the Sultanate of Oman is very challenging, especially in those that exhibit relatively low permeability. These formations, based on petrology work, contains significant amount of clays and feldspars, which make it difficult in the designing process of the acid formulation. A new version of HF acid system was recently developed. It is specially formulated, so it does not require the addition of Hydrochloric acid (HCl) pre-flush. Because of this, it can be pumped as a single stage system. In addition, its higher reactivity allows deeper penetration and it has the ability to minimize secondary reactions and damaging precipitates.\u0000 Lab testing work was conducted to ensure the effectiveness of this single stage acid system. The results were promising as they show a good improvement in the rock permeability. These results were encouraging to carry field trials in the sandstone reservoirs in Oman Southern fields. Up to now, it has been pumped in these type of sandstones for oil producer wells and for water injector wells. The actual treatment using this system showed increased oil productivity by higher than 60% and higher than 80% in water injectivity.\u0000 This paper presents the testing, designing and pumping of the single stage acid system, as well as the comparison with the conventional HF acid system in Southern fields of Oman. It outlines the laboratory work and analysis done as well as the field trials.","PeriodicalId":10912,"journal":{"name":"Day 3 Wed, March 23, 2022","volume":"27 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81265459","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. Varfolomeev, Mojtaba Rezaei Koochi, C. Yuan, R. Khayrtdinov, A. Mustafin, M. Glukhov, R. Kadyrov, V. Sudakov, S. Usmanov
This paper presents the feasibility of the application of ion-modified water for enhanced oil recovery (EOR) in low permeable carbonate reservoir with ultra-high salinity of more than 220000 mg/L. Influence of different ions on wettability alteration, interfacial tension (IFT), scale tendency, recovery factor, and water injectivity was investigated. For choosing the optimized injection-water sequence, different types of water (formation water, distilled water, fresh water, and ion-modified water) were used. First, their effects on wettability alteration by measuring contact angle (oil-water-rock) and IFT were evaluated. Then, core flooding experiments were carried out to investigate how different injection sequence affects the oil recovery and injectivity. Furthermore, the scale tendency of different salts was simulated. The results showed that Mg2+ is the most effective ion. The addition of Mg2+ can fast change the oil-wet (130°) carbonate rock to water-wet (29°). The presence of mono-valent ions has negative effects on the effectiveness of Mg2+ on wettability alteration. Also, the presence of Mg2+ in fresh water and distilled water can reduce oil-water IFT two times lower. Core flooding experiments showed that after fresh water or formation water flooding (until 100% water cut), the sequent diluted formation water (diluted 10 times) yielded incremental oil recovery of about 3-5%, while the Mg2+ modified water obtained incremental oil recovery of about 8-18%. This indicates that Mg2+ modified water has a promising prospect in EOR in carbonate reservoirs. A comprehensive analysis combining contact angle measurements, IFT testing, and core flooding experiments indicates that the high efficiency of Mg2+ modified fresh water for EOR mainly benefits from its strong wettability alteration ability. In addition, it was found that the existence of Mg2+ and SO42− can reduce the tendency of precipitation of salts compared with using only fresh water or diluted formation water. This work proves that ion-modified water by adding Mg2+ to fresh water can be an effective, low cost and environment-friendly EOR method for low-permeability carbonate reservoirs with ultra-high salinity. Simultaneously, this research provides some basic data that can help to enrich the theory for developing low salinity water flooding for EOR.
{"title":"Feasibility of Ion-Modified Water for Low Salinity Water Flooding: A Case Study for Ultra-High-Salinity Carbonate Reservoir in Akanskoe Oilfield Tatarstan, Russia","authors":"M. Varfolomeev, Mojtaba Rezaei Koochi, C. Yuan, R. Khayrtdinov, A. Mustafin, M. Glukhov, R. Kadyrov, V. Sudakov, S. Usmanov","doi":"10.2118/200046-ms","DOIUrl":"https://doi.org/10.2118/200046-ms","url":null,"abstract":"\u0000 This paper presents the feasibility of the application of ion-modified water for enhanced oil recovery (EOR) in low permeable carbonate reservoir with ultra-high salinity of more than 220000 mg/L. Influence of different ions on wettability alteration, interfacial tension (IFT), scale tendency, recovery factor, and water injectivity was investigated. For choosing the optimized injection-water sequence, different types of water (formation water, distilled water, fresh water, and ion-modified water) were used. First, their effects on wettability alteration by measuring contact angle (oil-water-rock) and IFT were evaluated. Then, core flooding experiments were carried out to investigate how different injection sequence affects the oil recovery and injectivity. Furthermore, the scale tendency of different salts was simulated. The results showed that Mg2+ is the most effective ion. The addition of Mg2+ can fast change the oil-wet (130°) carbonate rock to water-wet (29°). The presence of mono-valent ions has negative effects on the effectiveness of Mg2+ on wettability alteration. Also, the presence of Mg2+ in fresh water and distilled water can reduce oil-water IFT two times lower. Core flooding experiments showed that after fresh water or formation water flooding (until 100% water cut), the sequent diluted formation water (diluted 10 times) yielded incremental oil recovery of about 3-5%, while the Mg2+ modified water obtained incremental oil recovery of about 8-18%. This indicates that Mg2+ modified water has a promising prospect in EOR in carbonate reservoirs.\u0000 A comprehensive analysis combining contact angle measurements, IFT testing, and core flooding experiments indicates that the high efficiency of Mg2+ modified fresh water for EOR mainly benefits from its strong wettability alteration ability. In addition, it was found that the existence of Mg2+ and SO42− can reduce the tendency of precipitation of salts compared with using only fresh water or diluted formation water. This work proves that ion-modified water by adding Mg2+ to fresh water can be an effective, low cost and environment-friendly EOR method for low-permeability carbonate reservoirs with ultra-high salinity. Simultaneously, this research provides some basic data that can help to enrich the theory for developing low salinity water flooding for EOR.","PeriodicalId":10912,"journal":{"name":"Day 3 Wed, March 23, 2022","volume":"37 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84667881","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}
Petroleum Development Oman operates large amount of gas wells in Sultanate of Oman. Due to the liquid loading occurring in these ageing assets, PDO has already installed 110+ Velocity String completions in the various gas fields across the concession area. In the 2015–2019 period, 39 wells in the Saih Rawl field were retrofitted with Velocity Strings. This paper presents the integrated and standardized approach to Velocity String candidate selection and compares the production performance post-installation against the forecast.
{"title":"Velocity Strings in Sultanate of Oman Gas Fields; A Case Study","authors":"N. Janusz","doi":"10.2118/200241-ms","DOIUrl":"https://doi.org/10.2118/200241-ms","url":null,"abstract":"\u0000 Petroleum Development Oman operates large amount of gas wells in Sultanate of Oman. Due to the liquid loading occurring in these ageing assets, PDO has already installed 110+ Velocity String completions in the various gas fields across the concession area. In the 2015–2019 period, 39 wells in the Saih Rawl field were retrofitted with Velocity Strings. This paper presents the integrated and standardized approach to Velocity String candidate selection and compares the production performance post-installation against the forecast.","PeriodicalId":10912,"journal":{"name":"Day 3 Wed, March 23, 2022","volume":"5 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84310076","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}
LG is a marginal offshore field lying in the west coast of India. Well A and B in field LG were completed using 4 ½ - in and 3 ½ - in single-string multizone completion intersecting gas and oil-bearing zones. During the initial phase of its production, the wells only produced gas, until the oil-bearing sands were perforated, and the wells produced commingled gas and oil. These wells had been flowing naturally on self-drive and recently ceased to flow after showing gradual decline in their production. The diagnosis suggested a failure of Vertical Lift Performance (VLP) indicating a need to change the production technique and possibly a need for artificial lift in the wells to bring them online. The paper discusses an innovative and cost-effective approach involving the implementation of through-tubing mechanical straddle pack-off with gas lift assistance to bring the wells back to production and increasing the overall recovery from the field. A detailed analysis of the various techniques for bringing the well online was evaluated keeping in mind the associated cost and time for each method. The considerations lead to the plan of introducing gas lift as an artificial lift method for these wells. Wells A and B were not equipped with any gas lift mandrel for introducing artificial gas lift. Workover for these wells would result in higher cost, time & risk factors for the wells. The economic viability of such a workover was not justifiable given the incremental production anticipated. After performing a detailed technical and economic analysis, the decision was made to implement a through-tubing gas lift technique using a straddle packer conveyed on slickline across the circulation Sliding Sleeve Door (SSD). The straddle pack-off was to be introduced in the existing 4 ½ - in and 3 ½ - in production tubing with internally mounted gas lift mandrels/orifice valves. Detailed modelling was performed to determine the correct orifice size for different lift parameters. The operations in candidate wells A and B were successfully conducted and the surface setup for the gas lift was installed. The mechanical pack-off was set at the desired depths without any issue, and the gas was injected through the annulus leading to instantaneous production from the well. The total operations period was minimal as compared to the workover operations, far safer and more cost-effective for the production enhancement achieved. This paper describes the job design, technique implemented, and challenges overcome during the successful activation of a theoretically dead well to 1000 BOPD production, establishing the viability of through-tubing gas lifting. Learnings from the paper will help professionals plan for such well interventions involving the use of mechanical straddle pack off for gas lift operations.
{"title":"Well Revival in an Offshore Marginal Field Using Through Tubing Straddle Gas Lift Technology - A Case Study","authors":"R. Vijay, M. Khanna, PJ Sarma","doi":"10.2118/200075-ms","DOIUrl":"https://doi.org/10.2118/200075-ms","url":null,"abstract":"\u0000 LG is a marginal offshore field lying in the west coast of India. Well A and B in field LG were completed using 4 ½ - in and 3 ½ - in single-string multizone completion intersecting gas and oil-bearing zones. During the initial phase of its production, the wells only produced gas, until the oil-bearing sands were perforated, and the wells produced commingled gas and oil. These wells had been flowing naturally on self-drive and recently ceased to flow after showing gradual decline in their production. The diagnosis suggested a failure of Vertical Lift Performance (VLP) indicating a need to change the production technique and possibly a need for artificial lift in the wells to bring them online.\u0000 The paper discusses an innovative and cost-effective approach involving the implementation of through-tubing mechanical straddle pack-off with gas lift assistance to bring the wells back to production and increasing the overall recovery from the field.\u0000 A detailed analysis of the various techniques for bringing the well online was evaluated keeping in mind the associated cost and time for each method. The considerations lead to the plan of introducing gas lift as an artificial lift method for these wells. Wells A and B were not equipped with any gas lift mandrel for introducing artificial gas lift. Workover for these wells would result in higher cost, time & risk factors for the wells. The economic viability of such a workover was not justifiable given the incremental production anticipated.\u0000 After performing a detailed technical and economic analysis, the decision was made to implement a through-tubing gas lift technique using a straddle packer conveyed on slickline across the circulation Sliding Sleeve Door (SSD). The straddle pack-off was to be introduced in the existing 4 ½ - in and 3 ½ - in production tubing with internally mounted gas lift mandrels/orifice valves. Detailed modelling was performed to determine the correct orifice size for different lift parameters.\u0000 The operations in candidate wells A and B were successfully conducted and the surface setup for the gas lift was installed. The mechanical pack-off was set at the desired depths without any issue, and the gas was injected through the annulus leading to instantaneous production from the well. The total operations period was minimal as compared to the workover operations, far safer and more cost-effective for the production enhancement achieved.\u0000 This paper describes the job design, technique implemented, and challenges overcome during the successful activation of a theoretically dead well to 1000 BOPD production, establishing the viability of through-tubing gas lifting. Learnings from the paper will help professionals plan for such well interventions involving the use of mechanical straddle pack off for gas lift operations.","PeriodicalId":10912,"journal":{"name":"Day 3 Wed, March 23, 2022","volume":"33 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85732670","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
L. Zhong, Tongchun Hao, Jie Xu, Xiaocheng Zhang, Xiaopeng Wang, Tao Xie, Tao Lin, Lei Zhang
Affected by the surrounding injection and production wells, the formation near the infill adjustment well is in an abnormal pressure state, and drilling and completion operations are prone to complex situations and accidents such as leakage and overflow. The conventional shut down method is to close all water injection wells within 500 meters from the adjustment well to ensure the safety of the operation, but at the same time reduce the oil field production. This paper proposes a design method for shut-in of water injection wells around adjustment wells based on injection-production data mining. This method is based on the influence of correlation of complex pressure wells under injection and production conditions, and uses water injection index and fluid production index as research objects. Data mining methods are used to find highly correlated wells for precise adjustment instead of conventional adjustment. This method was applied to 20 infill adjustment wells in the Penglai Oilfield in Bohai Sea. The correlation between injection and production wells was calculated using the water injection index and fluid production index of more than 500 injection wells and production wells. Controlling the precise shut-in of highly correlated wells ensures that well pressures are kept within safe limits during drilling and completion operations and that no abnormalities occur. Low-relevant wells do not take shut-in adjustment measures. After a single adjustment well is drilled, the surrounding injection wells can increase the water injection volume by more than 5000m3. This method achieves accurate shut-in for water injection wells that are highly correlated with the adjustment well. Under the premise of ensuring the safety of drilling operations, the impact of adjusting drilling and completion on oilfield development is minimized, and oilfield production efficiency is improved. It has good application and promotion value.
{"title":"Precision Shut-In and Pressure Control Drilling in Injection Wells Around Adjustment Well Based on Injection-Production Data Mining","authors":"L. Zhong, Tongchun Hao, Jie Xu, Xiaocheng Zhang, Xiaopeng Wang, Tao Xie, Tao Lin, Lei Zhang","doi":"10.2118/200030-ms","DOIUrl":"https://doi.org/10.2118/200030-ms","url":null,"abstract":"\u0000 Affected by the surrounding injection and production wells, the formation near the infill adjustment well is in an abnormal pressure state, and drilling and completion operations are prone to complex situations and accidents such as leakage and overflow. The conventional shut down method is to close all water injection wells within 500 meters from the adjustment well to ensure the safety of the operation, but at the same time reduce the oil field production. This paper proposes a design method for shut-in of water injection wells around adjustment wells based on injection-production data mining. This method is based on the influence of correlation of complex pressure wells under injection and production conditions, and uses water injection index and fluid production index as research objects. Data mining methods are used to find highly correlated wells for precise adjustment instead of conventional adjustment. This method was applied to 20 infill adjustment wells in the Penglai Oilfield in Bohai Sea. The correlation between injection and production wells was calculated using the water injection index and fluid production index of more than 500 injection wells and production wells. Controlling the precise shut-in of highly correlated wells ensures that well pressures are kept within safe limits during drilling and completion operations and that no abnormalities occur. Low-relevant wells do not take shut-in adjustment measures. After a single adjustment well is drilled, the surrounding injection wells can increase the water injection volume by more than 5000m3. This method achieves accurate shut-in for water injection wells that are highly correlated with the adjustment well. Under the premise of ensuring the safety of drilling operations, the impact of adjusting drilling and completion on oilfield development is minimized, and oilfield production efficiency is improved. It has good application and promotion value.","PeriodicalId":10912,"journal":{"name":"Day 3 Wed, March 23, 2022","volume":" 2","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"91514872","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}
G. Tassone, M. Giammancheri, S. Banoori, Sabino Parziale, V. Mittiga, R. Ilyasov, Nicolas Dupouy, B. Reilly
The operator in West Africa embarked upon the "N" field offshore development in 2016 with 13 multi-stage horizontal wells being fracture-stimulated in Phase-I, with further wells being planned in next development phases. Due to the complex nature of the reservoir, which is a multilayered sandstone characterized by high heterogeneity and low permeability, wellbore connections are often located in structurally altered areas with high presence of faults. The unpredictable local re-orientation of the stresses has resulted in complications for the fracturing operations with multiple fractures being induced. This paper presents the challenges and solutions implemented for delivering more consistent fracturing execution and well productivity improvements. The horizontal wells in the "N" field were hydraulically fractured using the "plug-and-perf" method with up to four fractured intervals. The quality of the near-wellbore connection and the observations of complex near-wellbore fracture geometries have hindered far-field proppant distribution and limited maximum proppant concentration inside the fracture. When fracturing this tight formation, controlling the opening of the pressure-dependent multiple fractures was identified as a critical issue. An engineering breakdown process and adapted frac strategy was implemented to minimize the multiple fractures generated at the formation. For the early hydraulic fracture treatments performed, conservative treatment designs were applied in order to avoid premature screenout with the consequence of increasing operative time. Implemented solutions have shown to improve the near-wellbore connections and increase well productivity. The successful outcomes are attributed to the implementation of improved perforating strategies, the optimization of fracturing fluid performance, an engineered fracturing breakdown process, and the development of a frac decision tree for improved decision making. The hydraulic frac strategy has been tailored well-by-well depending on the reservoir conditions (e.g. faults, permeability thickness, contacts), and on the operational conditions interpreted from the diagnostic injection tests (e.g. near wellbore tortuosity, net pressure). The holistic implementation of these new concepts for hydraulic fracturing and field development have delivered positive production results beyond initial expectations. For the horizontal wells intersecting the deep low permeability "D" reservoir, the risk of multiple fractures and influence of tortuosity have been diminished through corrective techniques and unique solutions applied for each fracturing stage.
{"title":"Hydraulic Fracturing Challenges and Solutions for the Development of a Low Permeability Oil Reservoir – Case History from Offshore West Africa","authors":"G. Tassone, M. Giammancheri, S. Banoori, Sabino Parziale, V. Mittiga, R. Ilyasov, Nicolas Dupouy, B. Reilly","doi":"10.2118/200115-ms","DOIUrl":"https://doi.org/10.2118/200115-ms","url":null,"abstract":"\u0000 The operator in West Africa embarked upon the \"N\" field offshore development in 2016 with 13 multi-stage horizontal wells being fracture-stimulated in Phase-I, with further wells being planned in next development phases. Due to the complex nature of the reservoir, which is a multilayered sandstone characterized by high heterogeneity and low permeability, wellbore connections are often located in structurally altered areas with high presence of faults. The unpredictable local re-orientation of the stresses has resulted in complications for the fracturing operations with multiple fractures being induced. This paper presents the challenges and solutions implemented for delivering more consistent fracturing execution and well productivity improvements.\u0000 The horizontal wells in the \"N\" field were hydraulically fractured using the \"plug-and-perf\" method with up to four fractured intervals. The quality of the near-wellbore connection and the observations of complex near-wellbore fracture geometries have hindered far-field proppant distribution and limited maximum proppant concentration inside the fracture. When fracturing this tight formation, controlling the opening of the pressure-dependent multiple fractures was identified as a critical issue. An engineering breakdown process and adapted frac strategy was implemented to minimize the multiple fractures generated at the formation.\u0000 For the early hydraulic fracture treatments performed, conservative treatment designs were applied in order to avoid premature screenout with the consequence of increasing operative time. Implemented solutions have shown to improve the near-wellbore connections and increase well productivity. The successful outcomes are attributed to the implementation of improved perforating strategies, the optimization of fracturing fluid performance, an engineered fracturing breakdown process, and the development of a frac decision tree for improved decision making. The hydraulic frac strategy has been tailored well-by-well depending on the reservoir conditions (e.g. faults, permeability thickness, contacts), and on the operational conditions interpreted from the diagnostic injection tests (e.g. near wellbore tortuosity, net pressure). The holistic implementation of these new concepts for hydraulic fracturing and field development have delivered positive production results beyond initial expectations.\u0000 For the horizontal wells intersecting the deep low permeability \"D\" reservoir, the risk of multiple fractures and influence of tortuosity have been diminished through corrective techniques and unique solutions applied for each fracturing stage.","PeriodicalId":10912,"journal":{"name":"Day 3 Wed, March 23, 2022","volume":"121 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90885889","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}
Lei Liang, Yanling Wang, Bin Liu, Yongfei Li, Longhao Tang, B. Bai, Yehui Zhang
To develop a low formation damage clay stabilizer, a kind of organic polyether amine clay stabilizer (OPACS) was synthesized. Compared with the commercial clay stabilizers, the application performance of the OPACS was investigated. OPACS was synthesized with 1, 2-propanediol, 2-(chloromethyl)oxirane and ammonia as main raw materials. The molecular structure of OPACS were characterized by FTIR and NMR, and its anti-swelling performance was tested by centrifugation. Other performance, including its temperature resistance, acid and alkali resistance, elution resistance and etc., were also researched. Different permeability cores were used to test the formation damage of OPACS, and its anti-swelling mechanism was studied by SEM. The FTIR and NMR spectra showed that the expected product structure was synthesized. When the clay stabilizer was adding with 2.0 wt.%, the anti-swelling rate of OPACS was over 90% which was better than the commercial clay stabilizers (about 80%) we bought. At the temperature range of 20 °C-120 °C and the pH range of 2-12, the anti-swelling rate of OPACS changed less than 2.5%. In the long-term efficacy test, the elution recovery rate of OPACS was higher than 92% within the concentration between 0.5 wt.%-3.0 wt.%. Natural cores with different permeability were selected for core flow experiments. The test results showed that the permeability recovery rate of cores were more than 95% treated with OPACS, which meant the formation damage value was less than 5%. From the SEM of clay treated with different clay stabilizers, we could find out the structure of clay treated with OPACS was more compact than those treated with other stabilizers we bought. These results have shown that OPACS can effectively inhibit the water absorption swelling of clay and recovery formation damage, which are helpful to the EOR and friendly to the environment.
{"title":"Synthesis and Application of a Low Formation Damage Clay Stabilizer","authors":"Lei Liang, Yanling Wang, Bin Liu, Yongfei Li, Longhao Tang, B. Bai, Yehui Zhang","doi":"10.2118/200039-ms","DOIUrl":"https://doi.org/10.2118/200039-ms","url":null,"abstract":"\u0000 To develop a low formation damage clay stabilizer, a kind of organic polyether amine clay stabilizer (OPACS) was synthesized. Compared with the commercial clay stabilizers, the application performance of the OPACS was investigated.\u0000 OPACS was synthesized with 1, 2-propanediol, 2-(chloromethyl)oxirane and ammonia as main raw materials. The molecular structure of OPACS were characterized by FTIR and NMR, and its anti-swelling performance was tested by centrifugation. Other performance, including its temperature resistance, acid and alkali resistance, elution resistance and etc., were also researched. Different permeability cores were used to test the formation damage of OPACS, and its anti-swelling mechanism was studied by SEM.\u0000 The FTIR and NMR spectra showed that the expected product structure was synthesized. When the clay stabilizer was adding with 2.0 wt.%, the anti-swelling rate of OPACS was over 90% which was better than the commercial clay stabilizers (about 80%) we bought. At the temperature range of 20 °C-120 °C and the pH range of 2-12, the anti-swelling rate of OPACS changed less than 2.5%. In the long-term efficacy test, the elution recovery rate of OPACS was higher than 92% within the concentration between 0.5 wt.%-3.0 wt.%. Natural cores with different permeability were selected for core flow experiments. The test results showed that the permeability recovery rate of cores were more than 95% treated with OPACS, which meant the formation damage value was less than 5%. From the SEM of clay treated with different clay stabilizers, we could find out the structure of clay treated with OPACS was more compact than those treated with other stabilizers we bought. These results have shown that OPACS can effectively inhibit the water absorption swelling of clay and recovery formation damage, which are helpful to the EOR and friendly to the environment.","PeriodicalId":10912,"journal":{"name":"Day 3 Wed, March 23, 2022","volume":"81 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83202720","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. A. Md Yusof, Mohamad Arif Ibrahim, Ismail M. Saaid, A. Idris, M. Idress, M. A. Mohamed
Large volume of CO2 injection into the saline aquifer is considered to be the high potential CO2 storage method. Until now, the field of CO2 injectivity has been completely dominated by salt precipitation – and by far the most studied mechanism for the loss of injectivity. In this paper, our aim is to focus on recent findings on CO2 injectivity impairment by fines migration that should not be overlooked. This paper summarizes the state-of-the-art knowledge obtained from theoretical, field studies, and experimental observations on CO2 injectivity impairment by fines migration in saline aquifers in the sense of CO2 storage. By gathering various data from books, DOE papers, field reports and SPE publications, a detailed and high quality data set for fines migration during CO2 injection into saline aquifer is created. Key reservoir/fluid/rock information, operational parameters and petrophysical evaluations are assessments are provided, providing the basis for comprehensive data analysis. The results are presented in terms of boxplot and histogram, where histogram displays the distribution of each parameter and identifies the best suitable ranges for best practices; boxplots are used to detect the special cases and summarize the ranges of each parameter. Previous coreflooding experiments concluded that salt precipitation, mineral precipitation, dissolution and mobilization are the main mechanisms that caused CO2 injectivity impairments. Dissolution of carbonate minerals is dominant and it increases the poro spaces and connectivity of sandstone core samples. Conversely, detachment, precipitation of salt and clay minerals and deposition of fines particles decreases the flow are and even clog the flow paths despite net dissolution. However, the results are case dependent and lack generality in terms of quantifying the petrophysical damage. It has been highlighted that injection scheme (flow rate, time frame), mineral composition (clay content, sensitive minerals), particulate process in porous media (pore geometry, particle and carrier fluid properties), and thermodynamic conditions (pressure, temperature, salinity, CO2 and brine composition) give substantial effect on the fines migration during CO2 injection. Additionally, the current experimental work is limited to rendering time and difficult to identify the dynamic process of fines migration during CO2 injection. A list of potential additional work has therefore been presented in this paper including the establishment of microscopic visualization of CO2-brine-rock interactions with representative pore-network under reservoir pressure and temperature. This is the first paper to summarize the contribution of fines migration on CO2 injectivity impairment in saline aquifer.
{"title":"Fines Migration During CO2 Injection: A Review of the Phenomenon and New Breakthrough","authors":"M. A. Md Yusof, Mohamad Arif Ibrahim, Ismail M. Saaid, A. Idris, M. Idress, M. A. Mohamed","doi":"10.2118/200134-ms","DOIUrl":"https://doi.org/10.2118/200134-ms","url":null,"abstract":"\u0000 Large volume of CO2 injection into the saline aquifer is considered to be the high potential CO2 storage method. Until now, the field of CO2 injectivity has been completely dominated by salt precipitation – and by far the most studied mechanism for the loss of injectivity. In this paper, our aim is to focus on recent findings on CO2 injectivity impairment by fines migration that should not be overlooked. This paper summarizes the state-of-the-art knowledge obtained from theoretical, field studies, and experimental observations on CO2 injectivity impairment by fines migration in saline aquifers in the sense of CO2 storage. By gathering various data from books, DOE papers, field reports and SPE publications, a detailed and high quality data set for fines migration during CO2 injection into saline aquifer is created. Key reservoir/fluid/rock information, operational parameters and petrophysical evaluations are assessments are provided, providing the basis for comprehensive data analysis. The results are presented in terms of boxplot and histogram, where histogram displays the distribution of each parameter and identifies the best suitable ranges for best practices; boxplots are used to detect the special cases and summarize the ranges of each parameter. Previous coreflooding experiments concluded that salt precipitation, mineral precipitation, dissolution and mobilization are the main mechanisms that caused CO2 injectivity impairments. Dissolution of carbonate minerals is dominant and it increases the poro spaces and connectivity of sandstone core samples. Conversely, detachment, precipitation of salt and clay minerals and deposition of fines particles decreases the flow are and even clog the flow paths despite net dissolution. However, the results are case dependent and lack generality in terms of quantifying the petrophysical damage. It has been highlighted that injection scheme (flow rate, time frame), mineral composition (clay content, sensitive minerals), particulate process in porous media (pore geometry, particle and carrier fluid properties), and thermodynamic conditions (pressure, temperature, salinity, CO2 and brine composition) give substantial effect on the fines migration during CO2 injection. Additionally, the current experimental work is limited to rendering time and difficult to identify the dynamic process of fines migration during CO2 injection. A list of potential additional work has therefore been presented in this paper including the establishment of microscopic visualization of CO2-brine-rock interactions with representative pore-network under reservoir pressure and temperature. This is the first paper to summarize the contribution of fines migration on CO2 injectivity impairment in saline aquifer.","PeriodicalId":10912,"journal":{"name":"Day 3 Wed, March 23, 2022","volume":"10 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84350428","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}
Secure storage of carbon dioxide in underground reservoirs has been an increasingly interesting topic for the researches in the recent decade. The literature includes great works covering the idea of storing CO2 in depleted oil and gas fields or deep saline aquifer. In this study, long-term adsorption of CO2 and hydrocarbon gases is discussed as another opportunity to permanently store greenhouse gases and reduce the amount of the carbon dioxide that enters atmosphere. The simplified local-density (SLD) theory was used for matching the experimental data and providing predictions of high-pressure supercritical adsorption isotherms of CO2 and hydrocarbon gases. The SLD model is able to capture the contributions from the fluid-fluid and fluid-solid interactions and, despite the typical assumption of uniform bulk phase density, the model plots the variable density profile of the fluids in nanopore. An extensive set of adsorption measurements available in the literature is used in this evaluation. The slit and cylindrical pore geometry are assessed and the effect of the pressure, temperature, pore size and fluid composition is also discussed in detail. The results show that the SLD-PR model can predict absolute adsorption of the CO2 and hydrocarbon gases within the experimental uncertainty range. For heavier components (C3+), the model illustrates a thicker adsorbed wall close to the pore surface, the adsorption is enhanced while the pressure is increased to a certain point. This observation is in line with the pore-fluid interaction energy which shows a positive trend in terms of molecular size and pressure. In addition, it is concluded that the pore size lower than 2 nm show an exponentially high interest in adsorbing the gas molecules at supercritical conditions. Finally, the results recommend that the simplified local density model gives promising estimates for converting excess adsorption data to absolute adsorption data and calculating the storage capacity of the reservoir rock. Using the outcomes of this study, millions of tons of carbon dioxide can be safely stored in carefully selected high-organic content rocks. The proposed method can also have some applications in predicting the hydrocarbon-in-place and production behavior in shale reservoirs with high organic carbon content.
{"title":"Modeling Supercritical CO2 and Hydrocarbon Adsorption in Nanopores","authors":"A. Haghshenas, Mohammad Hamedpour","doi":"10.2118/200068-ms","DOIUrl":"https://doi.org/10.2118/200068-ms","url":null,"abstract":"\u0000 Secure storage of carbon dioxide in underground reservoirs has been an increasingly interesting topic for the researches in the recent decade. The literature includes great works covering the idea of storing CO2 in depleted oil and gas fields or deep saline aquifer. In this study, long-term adsorption of CO2 and hydrocarbon gases is discussed as another opportunity to permanently store greenhouse gases and reduce the amount of the carbon dioxide that enters atmosphere.\u0000 The simplified local-density (SLD) theory was used for matching the experimental data and providing predictions of high-pressure supercritical adsorption isotherms of CO2 and hydrocarbon gases. The SLD model is able to capture the contributions from the fluid-fluid and fluid-solid interactions and, despite the typical assumption of uniform bulk phase density, the model plots the variable density profile of the fluids in nanopore. An extensive set of adsorption measurements available in the literature is used in this evaluation. The slit and cylindrical pore geometry are assessed and the effect of the pressure, temperature, pore size and fluid composition is also discussed in detail.\u0000 The results show that the SLD-PR model can predict absolute adsorption of the CO2 and hydrocarbon gases within the experimental uncertainty range. For heavier components (C3+), the model illustrates a thicker adsorbed wall close to the pore surface, the adsorption is enhanced while the pressure is increased to a certain point. This observation is in line with the pore-fluid interaction energy which shows a positive trend in terms of molecular size and pressure. In addition, it is concluded that the pore size lower than 2 nm show an exponentially high interest in adsorbing the gas molecules at supercritical conditions. Finally, the results recommend that the simplified local density model gives promising estimates for converting excess adsorption data to absolute adsorption data and calculating the storage capacity of the reservoir rock.\u0000 Using the outcomes of this study, millions of tons of carbon dioxide can be safely stored in carefully selected high-organic content rocks. The proposed method can also have some applications in predicting the hydrocarbon-in-place and production behavior in shale reservoirs with high organic carbon content.","PeriodicalId":10912,"journal":{"name":"Day 3 Wed, March 23, 2022","volume":"315 4 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79603951","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}
Azzan Al Yaarubi, Chanh Cao Minh, Nate Bachman, A. Valori, Suryanarayana Guntupalli, Khalsa Al Hadidi
Wettability is a critical reservoir and petrophysical evaluation parameter that is often ignored. Both disciplines often assume the formations are water-wet for simplicity and because wettability measurement on cores often carries a high degree of uncertainty. With the expansion of unconventional carbonate reservoirs development and interest in enhanced oil recovery (EOR), the importance of understanding wettability at the native state and its variability with various injection fluids is becoming critical. For practical purposes, a fast and accurate determination method, ideally at in-situ conditions, is desired. It is widely recognized that nuclear magnetic resonance (NMR) is very sensitive to the strength of the fluid-rock interactions, and therefore, has been long considered as a good candidate for wettability determination. The NMR methodology was first applied in the laboratory using T2 relaxation measurements. For instance, sample wettability is inferred from a shift of the oil peak to shorter T2 values compared with the bulk T2 response of a live oil in the case of oil-wet system. The main practical limitation to the applicability of the T2 shift-based evaluation of wettability is the usually poor separation of oil and water peaks in the T2 spectrum. Furthermore, the bulk T2 of live oils must be measured and the core sample must be perfectly cleaned to quantify the NMR surface relaxation effect. Recently, a method based on two-dimensional mapping of NMR diffusion versus T2 was developed and validated with Amott-Harvey and USBM lab measurements. This method has two advantages. First, separation between the oil and water signals is greatly improved compared with the one-dimensional T2. Second, key properties such as tortuosity, represented by the electrical cementation factor m, and effective surface relaxivity can be inferred from the two-dimensional NMR maps using the restricted-diffusion model. The wettability index can then be estimated from the effective surface relaxivities. The laboratory results on cores suggest that it is possible to obtain reservoir wettability using downhole NMR measurements. This requires high-resolution, high signal-to-noise ratio (SNR) data and improved processing techniques to separate oil and water signals. We examined the NMR restricted-diffusion wettability technique utilizing log data collected in an observation well completed with plastic casing. This well is used to monitor oil desaturation during different phases of an EOR pilot consisting of water, alkaline surfactant (ASP), and polymer floods. A downhole NMR tool that simultaneously records T1, T2 and diffusion at multiple depth of investigation (DOI) was used. This device allowed to periodically collect high-quality NMR data with SNR higher than 50. The targeted reservoir is a sandstone containing hydrocarbon with viscosity of 90 cP. The computed wettability consistently showed mildly oil-wet condition at the selected depth and over the analyzed
{"title":"In-Situ Wettability Determination Using Magnetic Resonance Restricted Diffusion","authors":"Azzan Al Yaarubi, Chanh Cao Minh, Nate Bachman, A. Valori, Suryanarayana Guntupalli, Khalsa Al Hadidi","doi":"10.2118/200167-ms","DOIUrl":"https://doi.org/10.2118/200167-ms","url":null,"abstract":"\u0000 Wettability is a critical reservoir and petrophysical evaluation parameter that is often ignored. Both disciplines often assume the formations are water-wet for simplicity and because wettability measurement on cores often carries a high degree of uncertainty. With the expansion of unconventional carbonate reservoirs development and interest in enhanced oil recovery (EOR), the importance of understanding wettability at the native state and its variability with various injection fluids is becoming critical. For practical purposes, a fast and accurate determination method, ideally at in-situ conditions, is desired.\u0000 It is widely recognized that nuclear magnetic resonance (NMR) is very sensitive to the strength of the fluid-rock interactions, and therefore, has been long considered as a good candidate for wettability determination. The NMR methodology was first applied in the laboratory using T2 relaxation measurements. For instance, sample wettability is inferred from a shift of the oil peak to shorter T2 values compared with the bulk T2 response of a live oil in the case of oil-wet system. The main practical limitation to the applicability of the T2 shift-based evaluation of wettability is the usually poor separation of oil and water peaks in the T2 spectrum. Furthermore, the bulk T2 of live oils must be measured and the core sample must be perfectly cleaned to quantify the NMR surface relaxation effect. Recently, a method based on two-dimensional mapping of NMR diffusion versus T2 was developed and validated with Amott-Harvey and USBM lab measurements. This method has two advantages. First, separation between the oil and water signals is greatly improved compared with the one-dimensional T2. Second, key properties such as tortuosity, represented by the electrical cementation factor m, and effective surface relaxivity can be inferred from the two-dimensional NMR maps using the restricted-diffusion model. The wettability index can then be estimated from the effective surface relaxivities.\u0000 The laboratory results on cores suggest that it is possible to obtain reservoir wettability using downhole NMR measurements. This requires high-resolution, high signal-to-noise ratio (SNR) data and improved processing techniques to separate oil and water signals. We examined the NMR restricted-diffusion wettability technique utilizing log data collected in an observation well completed with plastic casing. This well is used to monitor oil desaturation during different phases of an EOR pilot consisting of water, alkaline surfactant (ASP), and polymer floods. A downhole NMR tool that simultaneously records T1, T2 and diffusion at multiple depth of investigation (DOI) was used. This device allowed to periodically collect high-quality NMR data with SNR higher than 50. The targeted reservoir is a sandstone containing hydrocarbon with viscosity of 90 cP. The computed wettability consistently showed mildly oil-wet condition at the selected depth and over the analyzed ","PeriodicalId":10912,"journal":{"name":"Day 3 Wed, March 23, 2022","volume":"16 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74770497","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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