E. Bayramov, Jonathan Davis, Niyazi Azizov, Vugar Ismayilov, Jalal Rahimov, Anar Isgandarov, Elchin Teymurlu, Gorkhmaz Karimov
The AGT Survey and SIM Geospatial Team in collaboration with SOCAR have deployed efficient and low risk geospatial data acquisition technologies based on Unmanned Air Systems (UAS) for exploration and reservoir development projects. This technology provides key imaging data with high visual quality and positional accuracy. Imagery acquisition for a recent project significantly contributed to the reduction of the company needs for regular field expeditions of geologists and geophysicists. The imagery acquired also supported some geological and geophysical analysis through quantitative imagery analysis methods. This project involved imagery acquisition from satellite and Unmanned Aerial Vehicle (UAV). The use of UAV required extensive collaboration and development work with a UAV acquisition contractor, BP aviation and PSCM teams and SOCAR to ensure that the UAV is operating in full compliance with Azerbaijan, BP and International Civil Aviation Organization regulations. The AGT Survey and SIM Geospatial Team also deployed the acquisition of satellite and airbone imagery for the Shallow Water Absheron Peninsula and ShahDeniz 2 - South Caucasus Pipeline Expansion projects which contributed to the successful starting of exploration and reservoir development analysis in the Caspian Sea and planning of route alignment over Azerbaijan-Georgia-Turkey. In is well known, that the onshore and offshore deployment of field crews has an associated cost and exposes personnel to Health and Safety risks. The deployment of satellite and airborne observation programs played a significant role in the reduction of risks and costs for survey geographic data collection and analysis without deployment of field crews.
{"title":"Space Unmanned Air Systems Support the Optimization of Exploration and Reservoir Development Activities in AGT Region","authors":"E. Bayramov, Jonathan Davis, Niyazi Azizov, Vugar Ismayilov, Jalal Rahimov, Anar Isgandarov, Elchin Teymurlu, Gorkhmaz Karimov","doi":"10.2118/198412-ms","DOIUrl":"https://doi.org/10.2118/198412-ms","url":null,"abstract":"\u0000 The AGT Survey and SIM Geospatial Team in collaboration with SOCAR have deployed efficient and low risk geospatial data acquisition technologies based on Unmanned Air Systems (UAS) for exploration and reservoir development projects. This technology provides key imaging data with high visual quality and positional accuracy. Imagery acquisition for a recent project significantly contributed to the reduction of the company needs for regular field expeditions of geologists and geophysicists. The imagery acquired also supported some geological and geophysical analysis through quantitative imagery analysis methods. This project involved imagery acquisition from satellite and Unmanned Aerial Vehicle (UAV). The use of UAV required extensive collaboration and development work with a UAV acquisition contractor, BP aviation and PSCM teams and SOCAR to ensure that the UAV is operating in full compliance with Azerbaijan, BP and International Civil Aviation Organization regulations.\u0000 The AGT Survey and SIM Geospatial Team also deployed the acquisition of satellite and airbone imagery for the Shallow Water Absheron Peninsula and ShahDeniz 2 - South Caucasus Pipeline Expansion projects which contributed to the successful starting of exploration and reservoir development analysis in the Caspian Sea and planning of route alignment over Azerbaijan-Georgia-Turkey. In is well known, that the onshore and offshore deployment of field crews has an associated cost and exposes personnel to Health and Safety risks. The deployment of satellite and airborne observation programs played a significant role in the reduction of risks and costs for survey geographic data collection and analysis without deployment of field crews.","PeriodicalId":406524,"journal":{"name":"Day 3 Fri, October 18, 2019","volume":"7 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-10-16","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"125644298","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}
Qinghai Yang, Quanbin Wang, Chuan Yu, Deli Jia, Ming Li
Many oilfields in China have stepped into the high and ultra-high water-cut recovery stage, with the comprehensive water cut (the ratio of the monthly water production to the monthly liquid production) approaching 90%. The injection-production relationship is seen with increasing complexity. Moreover, the commingled production is often adopted in the production well, and the liquid producing structure for the individual well is unclear, which results in the difficulty of the fine matching and adjustment between the injection and production. This paper proposes a cable-controlled real-time monitoring and controlling technology for zonal production. The technique is able to implement continuous monitoring of parameters such as the zonal flow rate, pressure, water cut and temperature through the whole production, and automatically adjust the zonal liquid production rate. The key to this technology is an integrated production regulator. The pressure test range of the regulator is 0–45 MPa and flow rate test range for a single layer lies between 5 m3/d and 100 m3/d. The field testing of the proposed technology has been successfully carried out in Daqing oilfield. There were totally three payzones, and the setting depth of the regulator is of 1050–1105 m. A tracking test for one month, including the downhole flow rate and pressure monitoring, the formation pressure buildup monitoring and the water cut monitoring at the wellhead, was conducted following the construction. The testing result indicates that this technology can accurately capture the downhole production status and effectively control the high-water-cut payzone. With the oil production of the individual well unchanged, the liquid production dropped by 5%–15%. The field practice demonstrates that this technology can effectively improve the waterflooding efficiency, suppress the ineffective water circulation and fulfill the refined development requirement of the oilfield.
{"title":"A Cable-Controlled Zonal Production Technology with Real-Time Monitoring and Controlling","authors":"Qinghai Yang, Quanbin Wang, Chuan Yu, Deli Jia, Ming Li","doi":"10.2118/198420-ms","DOIUrl":"https://doi.org/10.2118/198420-ms","url":null,"abstract":"\u0000 Many oilfields in China have stepped into the high and ultra-high water-cut recovery stage, with the comprehensive water cut (the ratio of the monthly water production to the monthly liquid production) approaching 90%. The injection-production relationship is seen with increasing complexity. Moreover, the commingled production is often adopted in the production well, and the liquid producing structure for the individual well is unclear, which results in the difficulty of the fine matching and adjustment between the injection and production. This paper proposes a cable-controlled real-time monitoring and controlling technology for zonal production. The technique is able to implement continuous monitoring of parameters such as the zonal flow rate, pressure, water cut and temperature through the whole production, and automatically adjust the zonal liquid production rate. The key to this technology is an integrated production regulator. The pressure test range of the regulator is 0–45 MPa and flow rate test range for a single layer lies between 5 m3/d and 100 m3/d. The field testing of the proposed technology has been successfully carried out in Daqing oilfield. There were totally three payzones, and the setting depth of the regulator is of 1050–1105 m. A tracking test for one month, including the downhole flow rate and pressure monitoring, the formation pressure buildup monitoring and the water cut monitoring at the wellhead, was conducted following the construction. The testing result indicates that this technology can accurately capture the downhole production status and effectively control the high-water-cut payzone. With the oil production of the individual well unchanged, the liquid production dropped by 5%–15%. The field practice demonstrates that this technology can effectively improve the waterflooding efficiency, suppress the ineffective water circulation and fulfill the refined development requirement of the oilfield.","PeriodicalId":406524,"journal":{"name":"Day 3 Fri, October 18, 2019","volume":"43 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-10-16","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"133008243","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}
Samir Huseynzade, C. Hammond, A. Pashayev, Ilkin Allahverdiyev, Rovshan Mollayev
The Chirag platform is one of six BP operated platforms to produce from the Azeri-Chirag-Gunashli Field in the Azerbaijan sector of Caspian Sea. The Chirag platform was scheduled for early oil delivery but was not developed with any means of artificial lift and as the field became mature, wells experienced water-breakthrough. In the absence of artificial lift, wells can typically flow naturally up to 20-40% watercut at steady-state conditions, however restart of these wells is challenging and at some point, impossible. Historically high watercut (20-40% and above) Chirag wells were side-tracked to up-dip dry oil leg. However, sidetracking for this reason could be uneconomical and could leave reserves from main production sands unrecovered. Therefore, enabling artificial lift for Chirag wells is vital. Several artificial lift options were evaluated, including ESPs and Jet Pumps. The most attractive method proved to be Gas-lift. In the absence of surface facilities to provide gas lift injection into the wells, using high pressure shallow gas formation as a source for gas lift was identified as suitable both from technical and economical perspective. This project was the first of its kind implementation in BP and offshore Caspian. A number of technical challenges had to be solved to deliver the project: Selection of continuous and permeable gas bearing formationOptimum gas lift valve size selectionSand production from perforated shallow gas formationPlant constraints to start-up and produce the well with AGL Three formations were selected as a potential energy source for gas-lift supply. It was identified that among all three zones only one is continuous (confirmed by reservoir pressure data in the Chirag area), with a good rock properties and adjacent to a field operated by the National oil company SOCAR with long production history. The gas lift valve size was selected to deliver enough energy to continue producing the well at high WC (>40%), minimize depletion in gas formation and lessen shut-in cross-flow of the lift gas. Perforation and down-hole completion were designed to minimize likelihood of sand production from gas formation, and in the case of sand production limit erosion of downhole equipment. Thorough risk evaluations were carried out to enable start-up of the well with high shut-in tubing head pressure which was due to high reservoir pressure of gas formation and its cross-flow to main production sands. This paper will focus on describing the technical evaluations carried out to assess and solve the challenges presented above and compare current performance of the wells' vs predicted. As of today, two Chirag wells are operated with AGL and one well has AGL capability for future implementation. The AGL project is confirmed to be a reliable mean of artificial lift method for Chirag wells assuming limited depletion in shallow gas reservoir.
{"title":"Auto Gas Lift Application in Azeri-Chirag-Gunashli Field, Azerbaijan, Caspian Offshore","authors":"Samir Huseynzade, C. Hammond, A. Pashayev, Ilkin Allahverdiyev, Rovshan Mollayev","doi":"10.2118/198364-ms","DOIUrl":"https://doi.org/10.2118/198364-ms","url":null,"abstract":"\u0000 The Chirag platform is one of six BP operated platforms to produce from the Azeri-Chirag-Gunashli Field in the Azerbaijan sector of Caspian Sea. The Chirag platform was scheduled for early oil delivery but was not developed with any means of artificial lift and as the field became mature, wells experienced water-breakthrough. In the absence of artificial lift, wells can typically flow naturally up to 20-40% watercut at steady-state conditions, however restart of these wells is challenging and at some point, impossible.\u0000 Historically high watercut (20-40% and above) Chirag wells were side-tracked to up-dip dry oil leg. However, sidetracking for this reason could be uneconomical and could leave reserves from main production sands unrecovered. Therefore, enabling artificial lift for Chirag wells is vital. Several artificial lift options were evaluated, including ESPs and Jet Pumps. The most attractive method proved to be Gas-lift. In the absence of surface facilities to provide gas lift injection into the wells, using high pressure shallow gas formation as a source for gas lift was identified as suitable both from technical and economical perspective. This project was the first of its kind implementation in BP and offshore Caspian. A number of technical challenges had to be solved to deliver the project: Selection of continuous and permeable gas bearing formationOptimum gas lift valve size selectionSand production from perforated shallow gas formationPlant constraints to start-up and produce the well with AGL\u0000 Three formations were selected as a potential energy source for gas-lift supply. It was identified that among all three zones only one is continuous (confirmed by reservoir pressure data in the Chirag area), with a good rock properties and adjacent to a field operated by the National oil company SOCAR with long production history. The gas lift valve size was selected to deliver enough energy to continue producing the well at high WC (>40%), minimize depletion in gas formation and lessen shut-in cross-flow of the lift gas. Perforation and down-hole completion were designed to minimize likelihood of sand production from gas formation, and in the case of sand production limit erosion of downhole equipment. Thorough risk evaluations were carried out to enable start-up of the well with high shut-in tubing head pressure which was due to high reservoir pressure of gas formation and its cross-flow to main production sands.\u0000 This paper will focus on describing the technical evaluations carried out to assess and solve the challenges presented above and compare current performance of the wells' vs predicted. As of today, two Chirag wells are operated with AGL and one well has AGL capability for future implementation. The AGL project is confirmed to be a reliable mean of artificial lift method for Chirag wells assuming limited depletion in shallow gas reservoir.","PeriodicalId":406524,"journal":{"name":"Day 3 Fri, October 18, 2019","volume":"341 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-10-16","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"134217784","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
As oil production continues, reservoir pressure decreases and oil production rate may not be as high as the plateau production rate. Once any sign of reduction in oil production rate has been observed, improved oil recovery (IOR) techniques are considered to aid the production. However, IOR methods could be accomplished from the beginning of oil production. Among different IOR methods, implementing artificial lift systems is one of the main options especially in brown fields. Artificial lift methods are categorized into pump-lift methods and gas-lift methods. In this study, screening process has been performed to find feasible artificial lift methods. During the screening process, different aspects of reservoir, well and fluid behavior have been studied to find the feasible options and it has been concluded that only ESP and gas lift could be implemented in this particular field. Both of these methods have been studied by simulating an integrated model including the reservoir and all of the candidate wells. So, impact of any variation in reservoir or well properties has been captured during the next 10 years. Three scenarios have been defined to predict the field performance by natural depletion, installing electrical submersible pumps and implementing gas lift system. Although an option might be selected as the best method for the present time, a long term evaluation is able to change the selected method. Integrated modeling the whole system of reservoir and wells provides a better understanding of the impact of different factors on performance of each scenario in long time. By performing a number of sensitivity analysis tests, it has been observed that increasing the water-cut may affect noticeably the performance of lifting systems. So, the pressure and water-cut of the reservoir and wells have been predicted during the next decade. It has been shown that using gas-lift method in the mentioned field has the highest oil recovery factor and the cumulative oil production during the next 10 years is more than 134 MMSTB. The ESP pumping system could lift almost 112 MMSTB oil during 10 years, while the natural depletion system has the lowest recovery and only 13 MMSTB oil could be produced during the same period.
{"title":"Artificial Lift Method Selection for Mature Oil Fields: A Case Study","authors":"A. D. Sarvestani, A. Hadipour","doi":"10.2118/198424-ms","DOIUrl":"https://doi.org/10.2118/198424-ms","url":null,"abstract":"\u0000 As oil production continues, reservoir pressure decreases and oil production rate may not be as high as the plateau production rate. Once any sign of reduction in oil production rate has been observed, improved oil recovery (IOR) techniques are considered to aid the production. However, IOR methods could be accomplished from the beginning of oil production. Among different IOR methods, implementing artificial lift systems is one of the main options especially in brown fields. Artificial lift methods are categorized into pump-lift methods and gas-lift methods. In this study, screening process has been performed to find feasible artificial lift methods. During the screening process, different aspects of reservoir, well and fluid behavior have been studied to find the feasible options and it has been concluded that only ESP and gas lift could be implemented in this particular field. Both of these methods have been studied by simulating an integrated model including the reservoir and all of the candidate wells. So, impact of any variation in reservoir or well properties has been captured during the next 10 years. Three scenarios have been defined to predict the field performance by natural depletion, installing electrical submersible pumps and implementing gas lift system.\u0000 Although an option might be selected as the best method for the present time, a long term evaluation is able to change the selected method. Integrated modeling the whole system of reservoir and wells provides a better understanding of the impact of different factors on performance of each scenario in long time. By performing a number of sensitivity analysis tests, it has been observed that increasing the water-cut may affect noticeably the performance of lifting systems. So, the pressure and water-cut of the reservoir and wells have been predicted during the next decade. It has been shown that using gas-lift method in the mentioned field has the highest oil recovery factor and the cumulative oil production during the next 10 years is more than 134 MMSTB. The ESP pumping system could lift almost 112 MMSTB oil during 10 years, while the natural depletion system has the lowest recovery and only 13 MMSTB oil could be produced during the same period.","PeriodicalId":406524,"journal":{"name":"Day 3 Fri, October 18, 2019","volume":"174 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-10-16","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"122999116","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}
W. Liew, Khalil Mohamed M'bareck, Shahira Emie Lyana Mustaffa, M. H. A. Razak, M. Y. Yaakub
Abandonment and decommissioning activities of oil and gas assets had been on the increasing trend for the past few years. Mature assets approaching end of life cycle and depleted production coupled with the low oil price environment has contributed to poor economic evaluation of the producing fields. This paper will discuss operator's experience in planning and executing subsea well intervention to temporary suspend fifteen (15) deepwater subsea wells tied to a Floating Production, Storage and Offloading (FPSO) unit in West Africa. The approach of the temporary wells suspension will be shared. Decision to temporary suspend the wells was made to meet the objective of releasing the FPSO early due to high operating cost. This temporary wells suspension design is mainly driven by the objective to meet the industry standard and best practices in re-instating double barrier envelope in the wells during the suspension period. During the planning stage few methods of barrier installation including contingency plans were considered. The temporary barriers placement were designed with end state in mind, the subsequent wells plug and abandonment after the suspension period. Based on the barriers placement philosophy, the subsea well intervention activities were planned and followed by the selection of vessel or rig for the operations. Drivers behind the temporary wells suspension design, approach for subsea well intervention - using riser based or riserless operations; and selection of vessel or rig for the operations will be shared in this paper. In addition, the lessons learnt and optimization opportunity throughout the execution of this subsea well intervention activity will be presented. This project is the pioneer to deepwater subsea abandonment and decommissioning (A&D) in the region of West Africa. The fifteen deepwater subsea wells were successfully suspended safely, ahead of planned schedule and below AFE cost. The lessons learnt from successful temporary wells suspension through subsea well intervention carried out by operator is believed to benefit all industry players, including the regulators, operators, service partners; and could be reference for industry's deepwater subsea decommissioning.
{"title":"Subsea Well Intervention – An Operator's Experience in First Deepwater Temporary Wells Suspension in West Africa","authors":"W. Liew, Khalil Mohamed M'bareck, Shahira Emie Lyana Mustaffa, M. H. A. Razak, M. Y. Yaakub","doi":"10.2118/198403-ms","DOIUrl":"https://doi.org/10.2118/198403-ms","url":null,"abstract":"\u0000 Abandonment and decommissioning activities of oil and gas assets had been on the increasing trend for the past few years. Mature assets approaching end of life cycle and depleted production coupled with the low oil price environment has contributed to poor economic evaluation of the producing fields. This paper will discuss operator's experience in planning and executing subsea well intervention to temporary suspend fifteen (15) deepwater subsea wells tied to a Floating Production, Storage and Offloading (FPSO) unit in West Africa.\u0000 The approach of the temporary wells suspension will be shared. Decision to temporary suspend the wells was made to meet the objective of releasing the FPSO early due to high operating cost. This temporary wells suspension design is mainly driven by the objective to meet the industry standard and best practices in re-instating double barrier envelope in the wells during the suspension period. During the planning stage few methods of barrier installation including contingency plans were considered.\u0000 The temporary barriers placement were designed with end state in mind, the subsequent wells plug and abandonment after the suspension period. Based on the barriers placement philosophy, the subsea well intervention activities were planned and followed by the selection of vessel or rig for the operations. Drivers behind the temporary wells suspension design, approach for subsea well intervention - using riser based or riserless operations; and selection of vessel or rig for the operations will be shared in this paper. In addition, the lessons learnt and optimization opportunity throughout the execution of this subsea well intervention activity will be presented.\u0000 This project is the pioneer to deepwater subsea abandonment and decommissioning (A&D) in the region of West Africa. The fifteen deepwater subsea wells were successfully suspended safely, ahead of planned schedule and below AFE cost. The lessons learnt from successful temporary wells suspension through subsea well intervention carried out by operator is believed to benefit all industry players, including the regulators, operators, service partners; and could be reference for industry's deepwater subsea decommissioning.","PeriodicalId":406524,"journal":{"name":"Day 3 Fri, October 18, 2019","volume":"39 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-10-16","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"126613858","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}
Ilyas Yechshanov, K. Zhumagulov, I. Tussupbayev, Chingiz Bopiyev, Y. Ghomian, Bolat Amangaliyev
Sour Gas Injection project has been successfully implemented in Tengiz field, achieving long term pressure maintenance in the platform area by re-injecting gas with high H2S concentration and improving oil recovery. From the recent gas saturation campaign, sweep efficiency in injection pattern has varied from 10 to 70%, with the highest sweep, as well as most of gas breakthroughs observed in Bashkirian interval. This represents effective and uniform piston like miscible displacement across whole Bashkirian that enhances oil production. Similarly, surveillance monitoring shows that due to higher depletion rate in same Bashkirian, it experiences higher exposure to injectant fluid (sour gas) causing elevated GOR production at surface, whereas, lower intervals remain at near solution GOR with lower sweep efficiency. Such, anisotropy between the upper and lower intervals in terms of reservoir pressure and sweep efficiency creates an opportunity for the development of lower intervals by implementing conformance control technology. Injectant breakthrough and GOR elevation in SGI wells create additional challenges for TCO, due to limited gas handling capacity at the plant processing facilities. Hence, isolation of Bashkirian will not only stimulate lower intervals to produce, but also, reduce GOR concerns. First pilot workover to isolate Bashkirian in SGI used chemical polymers. Polymers were injected into the formation and provided strong isolation of the target interval. As a result, time-lapse gas saturation logs confirmed significant increase in vertical sweep efficiency across whole Unit-1 intervals, plus lower GOR production lasted for more than 6 years. Completion type variety in existing SGI wells, make application of chemical polymers challenging, therefore, conformance control completions were introduced as an alternative solution. Conformance control liner provides mechanical isolation between compartments for more effective staged acid stimulation treatments and enable potential isolation of unwanted fluids. This paper will introduce application of various conformance control techniques to alter production in SGI pattern by developing lower intervals and reducing elevated GOR. A gas shut-off campaign was initiated in Tengiz field after a decade of sour gas injection. Case studies will be presented to share challenges and results during planning and execution phases.
{"title":"Application of Conformance Control Techniques in Tengiz Field","authors":"Ilyas Yechshanov, K. Zhumagulov, I. Tussupbayev, Chingiz Bopiyev, Y. Ghomian, Bolat Amangaliyev","doi":"10.2118/198363-ms","DOIUrl":"https://doi.org/10.2118/198363-ms","url":null,"abstract":"\u0000 Sour Gas Injection project has been successfully implemented in Tengiz field, achieving long term pressure maintenance in the platform area by re-injecting gas with high H2S concentration and improving oil recovery. From the recent gas saturation campaign, sweep efficiency in injection pattern has varied from 10 to 70%, with the highest sweep, as well as most of gas breakthroughs observed in Bashkirian interval. This represents effective and uniform piston like miscible displacement across whole Bashkirian that enhances oil production. Similarly, surveillance monitoring shows that due to higher depletion rate in same Bashkirian, it experiences higher exposure to injectant fluid (sour gas) causing elevated GOR production at surface, whereas, lower intervals remain at near solution GOR with lower sweep efficiency. Such, anisotropy between the upper and lower intervals in terms of reservoir pressure and sweep efficiency creates an opportunity for the development of lower intervals by implementing conformance control technology.\u0000 Injectant breakthrough and GOR elevation in SGI wells create additional challenges for TCO, due to limited gas handling capacity at the plant processing facilities. Hence, isolation of Bashkirian will not only stimulate lower intervals to produce, but also, reduce GOR concerns. First pilot workover to isolate Bashkirian in SGI used chemical polymers. Polymers were injected into the formation and provided strong isolation of the target interval. As a result, time-lapse gas saturation logs confirmed significant increase in vertical sweep efficiency across whole Unit-1 intervals, plus lower GOR production lasted for more than 6 years. Completion type variety in existing SGI wells, make application of chemical polymers challenging, therefore, conformance control completions were introduced as an alternative solution. Conformance control liner provides mechanical isolation between compartments for more effective staged acid stimulation treatments and enable potential isolation of unwanted fluids.\u0000 This paper will introduce application of various conformance control techniques to alter production in SGI pattern by developing lower intervals and reducing elevated GOR. A gas shut-off campaign was initiated in Tengiz field after a decade of sour gas injection. Case studies will be presented to share challenges and results during planning and execution phases.","PeriodicalId":406524,"journal":{"name":"Day 3 Fri, October 18, 2019","volume":"26 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-10-16","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"131654835","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}
Ivan Susliakov, T. Shevchuk, A. Alekseev, Alexey Dryaba, Andrey Alyakin, Oleg Sekachev
Significant progress in technologies development of well completion and stimulation allowed to involve in the development of reserves which 10 years ago were considered unpromising due to the too low reservoir permeability. Particularly significant influence of modern achievements on shale beds, which were previously not seriously considered as possible objects for hydrocarbon production. The success of shale oil production in the United States inspires oil companies around the world to study the possibility for the development of such objects. On the territory of the Russian Federation is perhaps the largest area of shale formation of the world – Bazhenov formation. In 2016, PJSC Gazprom Neft for the first time for the Bazhenov formation implemented a full cycle of construction of a horizontal well with a Multi-Stage Fracturing, which on the level of the applied technological solutions is not inferior to the American analogues used in the United States for shale oil production. The length of the horizontal section of the well was more than 1000 m; the 114 mm liner OD was run in and cemented. The cementing operation was carried out with liner rotation, and the cement blend itself contained specially selected additives which were designed to ensure high resistance of the cement stone to the damaging effects from multi-stage fracturing. The experience in drilling and cementing, completion and production operation of the well turned out to be positive, and in 2018, a pilot project started drilling a whole series of horizontal wells with multi-stage fracturing at two well sites. During the implementation of the project was found a stable relationship between the well production and the efficiency of fracturing, which is significantly affected by the isolation the anulus.
{"title":"Well Cementing with Elastic Properties Cement Stone and Liner Rotation is the Key to the Successful Development of Hard-to-Recover or Tight Oil Reserves from Bazhenov Formation","authors":"Ivan Susliakov, T. Shevchuk, A. Alekseev, Alexey Dryaba, Andrey Alyakin, Oleg Sekachev","doi":"10.2118/198366-ms","DOIUrl":"https://doi.org/10.2118/198366-ms","url":null,"abstract":"\u0000 Significant progress in technologies development of well completion and stimulation allowed to involve in the development of reserves which 10 years ago were considered unpromising due to the too low reservoir permeability. Particularly significant influence of modern achievements on shale beds, which were previously not seriously considered as possible objects for hydrocarbon production. The success of shale oil production in the United States inspires oil companies around the world to study the possibility for the development of such objects.\u0000 On the territory of the Russian Federation is perhaps the largest area of shale formation of the world – Bazhenov formation. In 2016, PJSC Gazprom Neft for the first time for the Bazhenov formation implemented a full cycle of construction of a horizontal well with a Multi-Stage Fracturing, which on the level of the applied technological solutions is not inferior to the American analogues used in the United States for shale oil production. The length of the horizontal section of the well was more than 1000 m; the 114 mm liner OD was run in and cemented. The cementing operation was carried out with liner rotation, and the cement blend itself contained specially selected additives which were designed to ensure high resistance of the cement stone to the damaging effects from multi-stage fracturing.\u0000 The experience in drilling and cementing, completion and production operation of the well turned out to be positive, and in 2018, a pilot project started drilling a whole series of horizontal wells with multi-stage fracturing at two well sites. During the implementation of the project was found a stable relationship between the well production and the efficiency of fracturing, which is significantly affected by the isolation the anulus.","PeriodicalId":406524,"journal":{"name":"Day 3 Fri, October 18, 2019","volume":"1 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-10-16","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"124330921","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
E. Eliseeva, Fabien Hauchart, Scott Wilson, S. Mukhin
The process of creating, maturing and ultimately submitting a field development plan for a given resource is often complex, time consuming, and inefficient; perhaps inextricably linked to its multi-disciplinary nature. The workflow(s) traditionally used in today's industry are domain-centric, involve many discrete software programs resulting in a linear process which limits optimization and prevents cross-domain collaboration. The paper describes an innovative field development planning (FDP) methodology, utilizing deep domain expertise supported by leading-edge software technology and illustrates the benefits through a study case in the Caspian Sea. Although well-established software tools exist for isolated parts of field layout, no existing platform integrates the equipment selection, systems knowledge, field layout, economics, and software simulations required for the entire planning process from feasibility studies to detail design and optimization. The paper describes an innovative field development planning methodology that combines lean project execution and uses the industry's first cloud-based collaborative subsea FDP software environment, providing efficiency and optimization. This is achieved by combining full-field economics with petroleum engineering disciplines, subsea systems engineering, subsea technology selection and installation knowledge spanning the entire planning process and visualized through a single working environment. This paper demonstrates how the core value of multi-discipline domain knowledge can be truly integrated through the use of collaborative workflows based upon cloud-based platforms and how it transforms concept development and selection in the upstream industry. In the early stages of exploitation planning, from the feasibility and concept selection phases, operators plan for the development of a field that will produce for 20 years or more. It is at this early phase that key Tier 1 level decisions are taken often with limited reservoir information and a significant range of uncertainty. The short duration of these initial stages inevitable means that operators rarely have the time or resources necessary to evaluate all possible development scenarios, and decisions are taken with less conviction or assurance than is desirable. As a result of this sub-optimal way of working, exploration and production companies are constantly seeking tools, methods and processes to enable the multi-scenario evaluation and option screening that will improve decision quality in field development planning. This paper demonstrates this novel approach through a practical example of such an FDP study, focusing on a case study relevant to the Caspian region. The discussion seeks to illustrate how the single working environment improves collaboration between disciplines whilst identifying cost savings and opportunity gains of the recommended development scenario.
{"title":"Collaborative and Multidiscipline Field Development Planning – A Caspian Case Study","authors":"E. Eliseeva, Fabien Hauchart, Scott Wilson, S. Mukhin","doi":"10.2118/198425-ms","DOIUrl":"https://doi.org/10.2118/198425-ms","url":null,"abstract":"\u0000 The process of creating, maturing and ultimately submitting a field development plan for a given resource is often complex, time consuming, and inefficient; perhaps inextricably linked to its multi-disciplinary nature. The workflow(s) traditionally used in today's industry are domain-centric, involve many discrete software programs resulting in a linear process which limits optimization and prevents cross-domain collaboration. The paper describes an innovative field development planning (FDP) methodology, utilizing deep domain expertise supported by leading-edge software technology and illustrates the benefits through a study case in the Caspian Sea.\u0000 Although well-established software tools exist for isolated parts of field layout, no existing platform integrates the equipment selection, systems knowledge, field layout, economics, and software simulations required for the entire planning process from feasibility studies to detail design and optimization. The paper describes an innovative field development planning methodology that combines lean project execution and uses the industry's first cloud-based collaborative subsea FDP software environment, providing efficiency and optimization. This is achieved by combining full-field economics with petroleum engineering disciplines, subsea systems engineering, subsea technology selection and installation knowledge spanning the entire planning process and visualized through a single working environment.\u0000 This paper demonstrates how the core value of multi-discipline domain knowledge can be truly integrated through the use of collaborative workflows based upon cloud-based platforms and how it transforms concept development and selection in the upstream industry.\u0000 In the early stages of exploitation planning, from the feasibility and concept selection phases, operators plan for the development of a field that will produce for 20 years or more. It is at this early phase that key Tier 1 level decisions are taken often with limited reservoir information and a significant range of uncertainty. The short duration of these initial stages inevitable means that operators rarely have the time or resources necessary to evaluate all possible development scenarios, and decisions are taken with less conviction or assurance than is desirable. As a result of this sub-optimal way of working, exploration and production companies are constantly seeking tools, methods and processes to enable the multi-scenario evaluation and option screening that will improve decision quality in field development planning.\u0000 This paper demonstrates this novel approach through a practical example of such an FDP study, focusing on a case study relevant to the Caspian region. The discussion seeks to illustrate how the single working environment improves collaboration between disciplines whilst identifying cost savings and opportunity gains of the recommended development scenario.","PeriodicalId":406524,"journal":{"name":"Day 3 Fri, October 18, 2019","volume":"11 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-10-16","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"128664059","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}
O. Zotkin, A. Osokina, M. Simonov, Andrianova Alla, A. Sharifov
One of the crucial components of any company successful development in the oil industry is the high-quality processing and analysis of a large amount of data for subsequent solving the forecasting and scheduling tasks of the oil, liquid, natural and co-produced wellhead gas production. Under the conditions of rapidly developing IT sphere, the use of machine learning methods is a relevant and a promising direction. However, most of the emerging engineering challenges cannot be solved efficiently by using either only machine learning algorithms or only physical and mathematical models. Solving the above-mentioned tasks using only one of the approaches is either more labour-intensive (the description of all processes running in the system like in a complete physical/mathematical model), or allows for the possibility of non-physical solutions and high error values (when only machine learning approach is used) in comparison with the combined physical/mathematical and machine learning models. The proposed hybrid approach allows to eliminate the uncertainties inherent in physical and mathematical models that are difficult to describe analytically by the application of machine learning methods to refine the results.
{"title":"A Novel Approach to Refinment Reservoir Proxy Model Using Machine-Learning Techniques","authors":"O. Zotkin, A. Osokina, M. Simonov, Andrianova Alla, A. Sharifov","doi":"10.2118/198411-ms","DOIUrl":"https://doi.org/10.2118/198411-ms","url":null,"abstract":"\u0000 One of the crucial components of any company successful development in the oil industry is the high-quality processing and analysis of a large amount of data for subsequent solving the forecasting and scheduling tasks of the oil, liquid, natural and co-produced wellhead gas production. Under the conditions of rapidly developing IT sphere, the use of machine learning methods is a relevant and a promising direction. However, most of the emerging engineering challenges cannot be solved efficiently by using either only machine learning algorithms or only physical and mathematical models.\u0000 Solving the above-mentioned tasks using only one of the approaches is either more labour-intensive (the description of all processes running in the system like in a complete physical/mathematical model), or allows for the possibility of non-physical solutions and high error values (when only machine learning approach is used) in comparison with the combined physical/mathematical and machine learning models.\u0000 The proposed hybrid approach allows to eliminate the uncertainties inherent in physical and mathematical models that are difficult to describe analytically by the application of machine learning methods to refine the results.","PeriodicalId":406524,"journal":{"name":"Day 3 Fri, October 18, 2019","volume":"80 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-10-16","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"132856530","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
A method for isolating water inflows into the well by blocking high permeability zones with a gel-forming composition based on sodium silicate, including biologically active additives has been developed. Whey is used as a biologically active supplement. As a result of isolation of the watering intervals by the gel-forming composition, low-permeability oil-saturated areas are involved in the development. The gelation process can be adjusted depending on the concentrations of sodium silicate and whey, as well as the temperature at a certain depth of the reservoir, necessary for isolation. To prevent a premature coagulation process when the formation is saturated with hard formation water, fresh or softened water is pumped in front of the gel-forming composition. When using this technology, the residual resistance factor will reach 3.88, an increase in oil production will be 18.5%.
{"title":"New Selective Isolation Method of Water Inflows into the Well Using Biologically Active Supplements","authors":"F. K. Kazimov, S. J. Rzaeva","doi":"10.2118/198415-ms","DOIUrl":"https://doi.org/10.2118/198415-ms","url":null,"abstract":"\u0000 A method for isolating water inflows into the well by blocking high permeability zones with a gel-forming composition based on sodium silicate, including biologically active additives has been developed. Whey is used as a biologically active supplement. As a result of isolation of the watering intervals by the gel-forming composition, low-permeability oil-saturated areas are involved in the development.\u0000 The gelation process can be adjusted depending on the concentrations of sodium silicate and whey, as well as the temperature at a certain depth of the reservoir, necessary for isolation. To prevent a premature coagulation process when the formation is saturated with hard formation water, fresh or softened water is pumped in front of the gel-forming composition. When using this technology, the residual resistance factor will reach 3.88, an increase in oil production will be 18.5%.","PeriodicalId":406524,"journal":{"name":"Day 3 Fri, October 18, 2019","volume":"54 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2019-10-16","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"127276106","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}
京公网安备 11010802042870号
京ICP备2023020795号-1
扫码关注我们
求助内容：
应助结果提醒方式：