Xiaofei Gao, L. Dai, Jia Liu, Xinbo Zou, Liqian Xu, Guang Yang, M. Moradi, M. Konopczynski, Jingheng Hua
In the 2018 intervention campaign, CNOOC aimed to improve production by retrofitting a horizontal well offshore of China. Water mobility in the reservoir was at least 20 times higher than oil mobility and a strong aquifer was located below the well. The well was drilled along a heterogeneous formation with varying properties resulting in an uneven reservoir influx toward the wellbore. Although the well was already completed with passive ICDs, oil production from the well started suffering severely from an early water breakthrough in a couple of weeks after starting production. It was recognized that the challenges could be mitigated by deploying Autonomous Inflow Control Devices (AICDs) which can control the reservoir fluid influx toward the wellbore and therefore optimise the well performance. An AICD is an active flow control device that delivers a variable flow restriction in response to the properties of a fluid and the rate of flow passing through. An integrated workflow comprising history matching and performance evaluation of the existing completion and sensitivity analyses was adopted to determine the best retrofit completion for the well. A well with a horizontal length of 300m was drilled in a thin formation with the oil column averaging 15ft. The optimum retrofit completion was to install a 2 3/8″ inner string consisting of AICD subs, swellable packers inside the existing ICD completion. The well was segmented in three compartments and a tailored AICD completion based on log data from the well was designed to properly restrict the production of water. The string was then connected to a redesigned ESP pump lifting the fluids to the surface. Through teamwork between the companies, the well was successfully re-completed with RCP AICD completions. Over a 9-month period of production, the well performance has been optimised with AICD devices. The AICDs significantly reduced the water cut (WC) of the well from 97% to 87% helping produce 200% more oil compared to production prior to re-completion. This application not only saved the cost of treating extra water but also added value by producing more oil. It also facilitated the connection of another well to the production system due to the enhanced capacity of the system which was then producing a lower volume of liquid. This well is an example that demonstrates the possibility of retrofitting AICDs in existing screens successfully. AICD completions ensured a balanced contribution from all reservoir sections and limited water production significantly. The lessons learnt from pre and post-installation studies will be discussed throughout. The AICD completions enabled the operator to implement an optimum reservoir drainage strategy that uses downhole control that can be manipulated autonomously based on well dynamic conditions to produce more oil.
{"title":"Production Optimisation by Retrofitting Autonomous Inflow Control Devices into an ICD Well in a Oil Reservoir Offshore China","authors":"Xiaofei Gao, L. Dai, Jia Liu, Xinbo Zou, Liqian Xu, Guang Yang, M. Moradi, M. Konopczynski, Jingheng Hua","doi":"10.2118/200124-ms","DOIUrl":"https://doi.org/10.2118/200124-ms","url":null,"abstract":"\u0000 In the 2018 intervention campaign, CNOOC aimed to improve production by retrofitting a horizontal well offshore of China. Water mobility in the reservoir was at least 20 times higher than oil mobility and a strong aquifer was located below the well. The well was drilled along a heterogeneous formation with varying properties resulting in an uneven reservoir influx toward the wellbore. Although the well was already completed with passive ICDs, oil production from the well started suffering severely from an early water breakthrough in a couple of weeks after starting production.\u0000 It was recognized that the challenges could be mitigated by deploying Autonomous Inflow Control Devices (AICDs) which can control the reservoir fluid influx toward the wellbore and therefore optimise the well performance. An AICD is an active flow control device that delivers a variable flow restriction in response to the properties of a fluid and the rate of flow passing through.\u0000 An integrated workflow comprising history matching and performance evaluation of the existing completion and sensitivity analyses was adopted to determine the best retrofit completion for the well. A well with a horizontal length of 300m was drilled in a thin formation with the oil column averaging 15ft. The optimum retrofit completion was to install a 2 3/8″ inner string consisting of AICD subs, swellable packers inside the existing ICD completion. The well was segmented in three compartments and a tailored AICD completion based on log data from the well was designed to properly restrict the production of water. The string was then connected to a redesigned ESP pump lifting the fluids to the surface. Through teamwork between the companies, the well was successfully re-completed with RCP AICD completions.\u0000 Over a 9-month period of production, the well performance has been optimised with AICD devices. The AICDs significantly reduced the water cut (WC) of the well from 97% to 87% helping produce 200% more oil compared to production prior to re-completion. This application not only saved the cost of treating extra water but also added value by producing more oil. It also facilitated the connection of another well to the production system due to the enhanced capacity of the system which was then producing a lower volume of liquid.\u0000 This well is an example that demonstrates the possibility of retrofitting AICDs in existing screens successfully. AICD completions ensured a balanced contribution from all reservoir sections and limited water production significantly. The lessons learnt from pre and post-installation studies will be discussed throughout. The AICD completions enabled the operator to implement an optimum reservoir drainage strategy that uses downhole control that can be manipulated autonomously based on well dynamic conditions to produce more oil.","PeriodicalId":10912,"journal":{"name":"Day 3 Wed, March 23, 2022","volume":"30 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"81533654","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}
PDO is operating some 600 gas wells in the Sultanate of Oman and almost all these gas wells will experience liquid loading during their production life. Surface depletion compression and gas well deliquification are essential to sustain stable production and to maximize ultimate gas recovery. This paper provides an overview of the deliquification measures that are assessed, adapted and implemented in PDO, and describes how to select the best suitable combination of deliquification measures based on well specific reservoir, inflow and outflow parameters.
{"title":"Gas Well Deliquification Strategy in Sultanate of Oman","authors":"C. Veeken, Ahmed Al-Rashdi, A. Al-Hashami","doi":"10.2118/200035-ms","DOIUrl":"https://doi.org/10.2118/200035-ms","url":null,"abstract":"\u0000 PDO is operating some 600 gas wells in the Sultanate of Oman and almost all these gas wells will experience liquid loading during their production life. Surface depletion compression and gas well deliquification are essential to sustain stable production and to maximize ultimate gas recovery. This paper provides an overview of the deliquification measures that are assessed, adapted and implemented in PDO, and describes how to select the best suitable combination of deliquification measures based on well specific reservoir, inflow and outflow parameters.","PeriodicalId":10912,"journal":{"name":"Day 3 Wed, March 23, 2022","volume":"14 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85506197","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. Andrianov, Jason Hou, E. Li, Echo Liu, Lisheng Yang
The polymeric nanospheres (NS) is the conformance control agent significantly improving oil recovery through redistribution of water flows deep in reservoir. The operator took a decision to pilot nanospheres technology in their large sandstone Changqing oil field in China after the experimental program has been conducted proved its potential. The nanospheres pilot has been executed in the oil field, resulting in substantial oil recovery improvement and water-cut reversal. Full-field implementation began. Extensive experimental study was conducted to analyze the effect of nanospheres on oil displacement in the Changqing field. The focus of the program was on the impact of reservoir heterogeneity and effect of nanospheres on oil displacement at different permeability contrast. Coreflood experiments were conducted with dual-core set-up, where sand cores were mimicking permeability contrast of the target reservoir. The program resulted in selecting optimum injection concentration and volumes for the pilot. Nanospheres solution has been injected in the oil field, and dedicated surveillance program was executed. Water flooding is effective in heterogeneous reservoirs when the average permeability contrast is below 20. When the contrast is higher e.g. as in target reservoir with permeability ranging from 7 to 2900 mD, water flooding is less efficient, especially in low-permeability zones. Nanospheres can mitigate the negative impact of high permeability contrast by diverting flow into previously unswept reservoir layers. This improves oil recovery, chiefly from low-permeability areas. Coreflood experiments proved the feasibility – incremental oil recovery was observed at 34%. Optimum pilot injection strategy has been designed. The effectiveness of nanospheres with high permeability variation has been demonstrated in the field tests. The field results have confirmed the positive impact of nanospheres on water flooding. In one of the tests, an average oil production rate increased from 5.1 to 10.8 t/d while water-cut was reduced from 94% to 83%. Analysis confirmed that nanospheres provided efficient conformance control deep in reservoir and did not result in loss of injectivity. Chemical utilization factor achieved is more than 100 tons of oil produced per ton of chemicals injected. Treatment costs per pattern were significantly lower compared to other IOR/EOR techniques. The operator has decided to implement nanospheres for conformance control in all field. Dedicated experimental program to select and, more important, optimize conformance control in heterogeneous reservoirs will be presented. Further, the paper will describe the field trial conducted. Both experimental and field data demonstrate the relationship between the oil displacement efficiency and injection conditions for different permeability contrasts. Results of field implementation will be presented. The technology effectiveness has been confirmed and full-field implementation has star
{"title":"Full-Scale Implementation of Conformance Control by Nanospheres in Large Sandstone Oil Field","authors":"A. Andrianov, Jason Hou, E. Li, Echo Liu, Lisheng Yang","doi":"10.2118/200227-ms","DOIUrl":"https://doi.org/10.2118/200227-ms","url":null,"abstract":"\u0000 The polymeric nanospheres (NS) is the conformance control agent significantly improving oil recovery through redistribution of water flows deep in reservoir. The operator took a decision to pilot nanospheres technology in their large sandstone Changqing oil field in China after the experimental program has been conducted proved its potential. The nanospheres pilot has been executed in the oil field, resulting in substantial oil recovery improvement and water-cut reversal. Full-field implementation began.\u0000 Extensive experimental study was conducted to analyze the effect of nanospheres on oil displacement in the Changqing field. The focus of the program was on the impact of reservoir heterogeneity and effect of nanospheres on oil displacement at different permeability contrast. Coreflood experiments were conducted with dual-core set-up, where sand cores were mimicking permeability contrast of the target reservoir. The program resulted in selecting optimum injection concentration and volumes for the pilot. Nanospheres solution has been injected in the oil field, and dedicated surveillance program was executed.\u0000 Water flooding is effective in heterogeneous reservoirs when the average permeability contrast is below 20. When the contrast is higher e.g. as in target reservoir with permeability ranging from 7 to 2900 mD, water flooding is less efficient, especially in low-permeability zones. Nanospheres can mitigate the negative impact of high permeability contrast by diverting flow into previously unswept reservoir layers. This improves oil recovery, chiefly from low-permeability areas. Coreflood experiments proved the feasibility – incremental oil recovery was observed at 34%. Optimum pilot injection strategy has been designed.\u0000 The effectiveness of nanospheres with high permeability variation has been demonstrated in the field tests. The field results have confirmed the positive impact of nanospheres on water flooding. In one of the tests, an average oil production rate increased from 5.1 to 10.8 t/d while water-cut was reduced from 94% to 83%. Analysis confirmed that nanospheres provided efficient conformance control deep in reservoir and did not result in loss of injectivity. Chemical utilization factor achieved is more than 100 tons of oil produced per ton of chemicals injected. Treatment costs per pattern were significantly lower compared to other IOR/EOR techniques. The operator has decided to implement nanospheres for conformance control in all field.\u0000 Dedicated experimental program to select and, more important, optimize conformance control in heterogeneous reservoirs will be presented. Further, the paper will describe the field trial conducted. Both experimental and field data demonstrate the relationship between the oil displacement efficiency and injection conditions for different permeability contrasts. Results of field implementation will be presented. The technology effectiveness has been confirmed and full-field implementation has star","PeriodicalId":10912,"journal":{"name":"Day 3 Wed, March 23, 2022","volume":"46 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86828974","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}
Abdullah Al Sabri, Vipin Dua, Wasik Abeebur Rahman, Mufleh Idris, Muddassir Hameed, A. Kindi
Condensate stabilizers at PDO Saih Rawl Central Processing Plant experienced severe pre-mature flooding causing process upsets and Operational difficulties. Conventional steady state simulations and tray hydraulics could not suggest actual causes. The purpose of the proposed paper is to present the methods followed in analyzing the flooding issue and identified solutions. Initially, the flooding issue was analyzed by carrying out steady state process simulation with latest feed composition and tray adequacy checks in consultation with the tray supplier. The study concluded the existing hardware is adequate, jet flooding limit and down comer flooding levels well within acceptable limits. The study recommended only few adjustments in Operating conditions to resolve the issue. As part of verification, alternate tray suppliers were also approached to carry out tray hydraulic checks and found no concerns. Subsequently, the column was subjected to gamma ray scan during normal operation and a scanning was repeated after simulating a flooding inside the column. Coupled with gamma ray scanning results, a tray by tray by simulation was carried out to ascertain the flooding the phenomena. Gamma ray scan revealed the condition of the column internals, liquid heights and froth level during normal operation as well as during simulated upset conditions. Even though the trays were in good conditions, bottom few trays showed higher liquid height during normal operation itself. Along with the results from Gamma ray scanning, process simulation results and investigation of Operating conditions revealed the possible reasons for the flooding issue. The study predicted a temperature dip in few trays and further rise somewhere near the column top, which is unusual for a distillation column. This is the resultant of different feed ratios from the original design and one of the feed to the column is estimated to be below 5 °C, which is too cold compared to column profile. Based on the results, options were developed to alleviate the flooding issue without compromising the production capabilities of the column profile. The nature of flooding experienced inside the column handling different feeds and large variation in temperatures is unique with the condensate stabilizers. Conventional full column steady state simulation and tray sizing were not adequate for investigating problem. It needed, gamma ray scanning while the column is in normal operation and during simulated flooding condition.
{"title":"Condensate Stabilizer Flooding Diagnosis","authors":"Abdullah Al Sabri, Vipin Dua, Wasik Abeebur Rahman, Mufleh Idris, Muddassir Hameed, A. Kindi","doi":"10.2118/200058-ms","DOIUrl":"https://doi.org/10.2118/200058-ms","url":null,"abstract":"\u0000 Condensate stabilizers at PDO Saih Rawl Central Processing Plant experienced severe pre-mature flooding causing process upsets and Operational difficulties. Conventional steady state simulations and tray hydraulics could not suggest actual causes. The purpose of the proposed paper is to present the methods followed in analyzing the flooding issue and identified solutions.\u0000 Initially, the flooding issue was analyzed by carrying out steady state process simulation with latest feed composition and tray adequacy checks in consultation with the tray supplier. The study concluded the existing hardware is adequate, jet flooding limit and down comer flooding levels well within acceptable limits. The study recommended only few adjustments in Operating conditions to resolve the issue. As part of verification, alternate tray suppliers were also approached to carry out tray hydraulic checks and found no concerns.\u0000 Subsequently, the column was subjected to gamma ray scan during normal operation and a scanning was repeated after simulating a flooding inside the column. Coupled with gamma ray scanning results, a tray by tray by simulation was carried out to ascertain the flooding the phenomena.\u0000 Gamma ray scan revealed the condition of the column internals, liquid heights and froth level during normal operation as well as during simulated upset conditions. Even though the trays were in good conditions, bottom few trays showed higher liquid height during normal operation itself. Along with the results from Gamma ray scanning, process simulation results and investigation of Operating conditions revealed the possible reasons for the flooding issue. The study predicted a temperature dip in few trays and further rise somewhere near the column top, which is unusual for a distillation column. This is the resultant of different feed ratios from the original design and one of the feed to the column is estimated to be below 5 °C, which is too cold compared to column profile. Based on the results, options were developed to alleviate the flooding issue without compromising the production capabilities of the column profile.\u0000 The nature of flooding experienced inside the column handling different feeds and large variation in temperatures is unique with the condensate stabilizers. Conventional full column steady state simulation and tray sizing were not adequate for investigating problem. It needed, gamma ray scanning while the column is in normal operation and during simulated flooding condition.","PeriodicalId":10912,"journal":{"name":"Day 3 Wed, March 23, 2022","volume":"28 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84456920","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}
Mohmaed Hassan, A. Nour, Wejdan Abdul-Aziz, T. Al-Yaqout, A. Al-Azmi, Budoor Al-Hashash, Badriya Al-Methen, A. Abu-Eida, Jorge Munoz, Lulwa Al-Suwailem
Most of wells in the major oil fields of West Kuwait Asset are producing with Electrical Submersible Pump (ESP). During 2012- 2013, the ESP premature failures reached high percentages of up to 30% of ESP population with high deferred oil. In order to enhance the ESP performance and reduce the number of premature failed ESP, FD (WK) has initiated ESP Equipment Reliability Project in 2014. The main objective was to define a proper workflow that will be capable to identify the root cause of ESP premature failures, find the way forward and mitigation actions to overcome the issue. All ESP business partners from KOC and service providers were involved in the project. Series of technical workshops following the API and KOC standards were conducted by the team members to analyze the ESP performance and premature failures where the team was able to define analytical workflow in the early review sessions to conduct the required work. The workflow takes in consideration the reservoir parameters and conditions, ESP performance with all tags and signatures, ESP systems from the overhead electrical line or generator, surface equipment down to ESP down hole equipment specifications, installation and pull-out procedures, and ESP operating conditions. Also attending the tear down of the failed wells to ensure the vendors procedures and the reported findings. In-addition, well models were utilized to find the deviation between the design and actual parameters and surface network model was utilized to define the impact of the pipeline issues on the ESP performance. Based on this study, the root cause of the ESP premature failures were found to be mainly due to; Power Quality, Sour condition, External sand source, Down hole emulsion, and some Equipment quality / specifications that were not designed to handle the down hole conditions of UG wells. A mitigation plan and list of recommended actions were concluded and implemented with a measure of the outcome and results in addition to some modifications that were applied within time. The project shows excellent results with time where the premature failures reduced from 30% in year 2012- 2013 to 12% in year 2018. Also the ESP showed enhanced performance over time. Extra room for improvement can be chieved by enhancing the power quality of the overhead lines and generators. Applying the mentioned workflow with the proper project structure form will help ESP stakeholders to identify the root cause and not the failure reason, Hence reduce premature failures. This will lead to reduce deferred oil, reduce cost per barrel, and avoid equipment compensation fees.
{"title":"ESP Performance Enhancement and Premature Failure Reduction Through Esp Equipment Reliability Project in a West Kuwait Field - Case Study From Kuwait","authors":"Mohmaed Hassan, A. Nour, Wejdan Abdul-Aziz, T. Al-Yaqout, A. Al-Azmi, Budoor Al-Hashash, Badriya Al-Methen, A. Abu-Eida, Jorge Munoz, Lulwa Al-Suwailem","doi":"10.2118/200120-ms","DOIUrl":"https://doi.org/10.2118/200120-ms","url":null,"abstract":"\u0000 Most of wells in the major oil fields of West Kuwait Asset are producing with Electrical Submersible Pump (ESP). During 2012- 2013, the ESP premature failures reached high percentages of up to 30% of ESP population with high deferred oil.\u0000 In order to enhance the ESP performance and reduce the number of premature failed ESP, FD (WK) has initiated ESP Equipment Reliability Project in 2014. The main objective was to define a proper workflow that will be capable to identify the root cause of ESP premature failures, find the way forward and mitigation actions to overcome the issue.\u0000 All ESP business partners from KOC and service providers were involved in the project. Series of technical workshops following the API and KOC standards were conducted by the team members to analyze the ESP performance and premature failures where the team was able to define analytical workflow in the early review sessions to conduct the required work.\u0000 The workflow takes in consideration the reservoir parameters and conditions, ESP performance with all tags and signatures, ESP systems from the overhead electrical line or generator, surface equipment down to ESP down hole equipment specifications, installation and pull-out procedures, and ESP operating conditions. Also attending the tear down of the failed wells to ensure the vendors procedures and the reported findings. In-addition, well models were utilized to find the deviation between the design and actual parameters and surface network model was utilized to define the impact of the pipeline issues on the ESP performance.\u0000 Based on this study, the root cause of the ESP premature failures were found to be mainly due to; Power Quality, Sour condition, External sand source, Down hole emulsion, and some Equipment quality / specifications that were not designed to handle the down hole conditions of UG wells.\u0000 A mitigation plan and list of recommended actions were concluded and implemented with a measure of the outcome and results in addition to some modifications that were applied within time.\u0000 The project shows excellent results with time where the premature failures reduced from 30% in year 2012- 2013 to 12% in year 2018. Also the ESP showed enhanced performance over time. Extra room for improvement can be chieved by enhancing the power quality of the overhead lines and generators.\u0000 Applying the mentioned workflow with the proper project structure form will help ESP stakeholders to identify the root cause and not the failure reason, Hence reduce premature failures. This will lead to reduce deferred oil, reduce cost per barrel, and avoid equipment compensation fees.","PeriodicalId":10912,"journal":{"name":"Day 3 Wed, March 23, 2022","volume":"84 3 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"87660493","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}
Issatay Dosmukhambetov, Bakhytzhan Taubayev, Ualikhan Yesbolov, A. Sadykov, Muratbek Shmalin, B. Akbayev, Y. Kaipov, Samat Ramatullayev, Daniyar Kuvatov, Olzhas Amanbayev, Bulat Khaziev
The Caspian offshore is a prolific area for hydrocarbon accumulation. Since it is an offshore, it is a challenging area in terms of strict environmental regulations and safety. At the early stage of the project it was clear, that formation properties of the exploration well require artificial lift assistance to produce during well testing. Therefore, designing proper DST string with ESP was crucial to the success of well testing. This paper describes unique combination of technologies and techniques that enabled a DST with ESP in combination with the Y tool, that provides capabilities to run thePLT below the pump. Also, one of the main challenges of well testing operation was to handle heavy oil fluid at surface. Being in environmentally sensitive area, designing a surface well testing equipment in a limited footprint, that enables efficient separation and disposal of heavy oil was very critical. Another challenge was unconsolidated formation with the high risk of sand production under drawdown, therefore downhole testing string and ESP pump supposed to withstand large quantity of solids during the production. The key technology that enabled testing was a new generation of abrasion resistant ESP pumps, that are designed to handle extensive solids production. The heavy oil also posed a number of risks. The surface equipment was specifically designed to heat oil in the tanks and if required to mix with diesel before flaring operations. Local regulation does not permit production during the night time and allows limited number of days for well testing. Therefore, well testing design must enable to acquire all necessary information within short period of test duration. The real-time data transmission and interpretation was a key to achieve main goal of the testing in exploration well - to accurately characterize the reservoir. This was the first successful ESP-DST in Caspian Sea. Despite of many challenges, the technologies that were selected for well testing operation was proven to be reliable. This allowed Operator to untap previously not accessible hydrocarbon reserves.
{"title":"First Successful ESP-DST Well Test in Heavy Oil Unconsolidated Sandstone in Caspian Sea","authors":"Issatay Dosmukhambetov, Bakhytzhan Taubayev, Ualikhan Yesbolov, A. Sadykov, Muratbek Shmalin, B. Akbayev, Y. Kaipov, Samat Ramatullayev, Daniyar Kuvatov, Olzhas Amanbayev, Bulat Khaziev","doi":"10.2118/200121-ms","DOIUrl":"https://doi.org/10.2118/200121-ms","url":null,"abstract":"\u0000 The Caspian offshore is a prolific area for hydrocarbon accumulation. Since it is an offshore, it is a challenging area in terms of strict environmental regulations and safety. At the early stage of the project it was clear, that formation properties of the exploration well require artificial lift assistance to produce during well testing. Therefore, designing proper DST string with ESP was crucial to the success of well testing.\u0000 This paper describes unique combination of technologies and techniques that enabled a DST with ESP in combination with the Y tool, that provides capabilities to run thePLT below the pump. Also, one of the main challenges of well testing operation was to handle heavy oil fluid at surface. Being in environmentally sensitive area, designing a surface well testing equipment in a limited footprint, that enables efficient separation and disposal of heavy oil was very critical. Another challenge was unconsolidated formation with the high risk of sand production under drawdown, therefore downhole testing string and ESP pump supposed to withstand large quantity of solids during the production.\u0000 The key technology that enabled testing was a new generation of abrasion resistant ESP pumps, that are designed to handle extensive solids production. The heavy oil also posed a number of risks. The surface equipment was specifically designed to heat oil in the tanks and if required to mix with diesel before flaring operations.\u0000 Local regulation does not permit production during the night time and allows limited number of days for well testing. Therefore, well testing design must enable to acquire all necessary information within short period of test duration. The real-time data transmission and interpretation was a key to achieve main goal of the testing in exploration well - to accurately characterize the reservoir.\u0000 This was the first successful ESP-DST in Caspian Sea. Despite of many challenges, the technologies that were selected for well testing operation was proven to be reliable. This allowed Operator to untap previously not accessible hydrocarbon reserves.","PeriodicalId":10912,"journal":{"name":"Day 3 Wed, March 23, 2022","volume":"22 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78373317","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}
Bruno Jesus Romero Mora, Beatrice Ioannilli, Sam Stobart, M. Gassert, Tommaso Castellito, S. Sartirana, V. Calabrese, Arturo Belleza, J. Ballotta, F. Duclocher, G. Citi, Darrell Knight, Jostein Lien
An Eni initiative Fast 3Digital Subsea was made to identify opportunities for improving Company's Subsea developments in terms of time, quality and cost by applying a new way of working and implementing a new digital tool, the FieldAP/Fieldtwin platform (by FutureOn). The purpose of this paper is to present the results of the comparison made between the conventional way of working and the application of the Fast 3Digital Subsea on subsea tieback projects. Data was collected and analysed for a project using the Fast 3Digital Subsea and the results showed the following key success benefits for Eni projects: time saving, cost reduction and improvement in engineering, quality and safety. The benefits listed above were proved during the engineering phase of the project, however the Fast 3Digital Subsea is expected to lead to similar improvements for the future phases of the projects such as installation, commissioning, maintenance and operation. From a Project point of view, the digital solution is expected to lead to minimum time savings of between 1-2 months from discovery to First Oil. This 1-2 months saving are expected mainly in projects where the critical path is represented by subsea items / flowlines that could benefit from an early procurement, in particular tie-backs to existing facilities (FPSO, FPU, and Onshore Plants). For this paper, an Eni project was chosen as the base case and the impacts on project schedule, cost, quality, and discipline collaboration during the engineering, feasibility and FEED activities were evaluated. The Fast 3Digital Subsea allowed engineers to evaluate multiple scenarios more effectively, increased the quality on the project documentation, allowed to select the optimum field layout configuration at an early stage and to quickly prepare an ITT package. All of the above, showed an average time saving of approximately 30% on field layout preparation, therefore cost saving compared to the conventional way of working were realised. Another significant time saving obtained by implementing a Fast 3Digital Subsea approach was during creating of overall deliverables with time saving of nearly 60% during Pre-FEED activities. All of time savings are broken down in activities and are described in the results section. In terms of marine operation, the selected digital solution allows engineers to assess the subsea deveolopment by visualising geohazards and clashes during SIMOPS, this aspect adds singnificant value to projects for faster decision making whilst taking into consideration safety.
{"title":"Benefits of New Digital Solution and Workflow Applied to Fast Track Subsea Development","authors":"Bruno Jesus Romero Mora, Beatrice Ioannilli, Sam Stobart, M. Gassert, Tommaso Castellito, S. Sartirana, V. Calabrese, Arturo Belleza, J. Ballotta, F. Duclocher, G. Citi, Darrell Knight, Jostein Lien","doi":"10.2118/200054-ms","DOIUrl":"https://doi.org/10.2118/200054-ms","url":null,"abstract":"\u0000 An Eni initiative Fast 3Digital Subsea was made to identify opportunities for improving Company's Subsea developments in terms of time, quality and cost by applying a new way of working and implementing a new digital tool, the FieldAP/Fieldtwin platform (by FutureOn).\u0000 The purpose of this paper is to present the results of the comparison made between the conventional way of working and the application of the Fast 3Digital Subsea on subsea tieback projects. Data was collected and analysed for a project using the Fast 3Digital Subsea and the results showed the following key success benefits for Eni projects: time saving, cost reduction and improvement in engineering, quality and safety.\u0000 The benefits listed above were proved during the engineering phase of the project, however the Fast 3Digital Subsea is expected to lead to similar improvements for the future phases of the projects such as installation, commissioning, maintenance and operation. From a Project point of view, the digital solution is expected to lead to minimum time savings of between 1-2 months from discovery to First Oil.\u0000 This 1-2 months saving are expected mainly in projects where the critical path is represented by subsea items / flowlines that could benefit from an early procurement, in particular tie-backs to existing facilities (FPSO, FPU, and Onshore Plants).\u0000 For this paper, an Eni project was chosen as the base case and the impacts on project schedule, cost, quality, and discipline collaboration during the engineering, feasibility and FEED activities were evaluated.\u0000 The Fast 3Digital Subsea allowed engineers to evaluate multiple scenarios more effectively, increased the quality on the project documentation, allowed to select the optimum field layout configuration at an early stage and to quickly prepare an ITT package. All of the above, showed an average time saving of approximately 30% on field layout preparation, therefore cost saving compared to the conventional way of working were realised.\u0000 Another significant time saving obtained by implementing a Fast 3Digital Subsea approach was during creating of overall deliverables with time saving of nearly 60% during Pre-FEED activities.\u0000 All of time savings are broken down in activities and are described in the results section.\u0000 In terms of marine operation, the selected digital solution allows engineers to assess the subsea deveolopment by visualising geohazards and clashes during SIMOPS, this aspect adds singnificant value to projects for faster decision making whilst taking into consideration safety.","PeriodicalId":10912,"journal":{"name":"Day 3 Wed, March 23, 2022","volume":"71 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83279320","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}
Jasbindra Singh, Mohammed Harthi, Mohamed Siyabi, Marya Al Salmi, Carmen Hamm, Omar Riyami, Safiya Hatmi, Rady Abdel Samiee, Mohammed Hinai, Anas Mazroui, Yousuf Sinani, I. Mahruqi, Nasser Al Azri
Produced water is an inextricable part of the hydrocarbon recovery processes, yet it is by far the largest volume waste stream associated with hydrocarbon recovery. In a C-field in South Oman, the produced water has been disposed in the aquifer zone of the producing formation. The feasibility of alternative ways to dispose water at surface using alternative options is being evaluated with the objective of reducing (or completely stopping) this water disposal which has shown benefits in maximizing the recovery by reversing the pressure decline. A simple model has been used to quantify the benefits of produced water re-injection into the deep aquifer zone. Deep water disposal (DWD) has been on-going for over 20 years in the aquifer zone in the B-formation in this field in South Oman. All the produced water from the surrounding fields is sent for disposal near the field via the C-Field Processing Station DWD system. This DWD activity has provided important energy to the system as evident in the reversing reservoir pressure trend in field. However, due to various reasons, efforts are being put forward with the aim of replacing DWD with alternative ways of disposing produced water at surface. An integrated model has been built and calibrated to the field response and used to predict the field performance. The calibrated model recommends to continue pressure to the field through water disposal or injection system. The study predicts the complete discontinuation of DWD will put significant reserves at risk eroding the field value and has quantified the amount of water available for the alternative options for surface disposal. The study has also identified an opportunity to further optimize the solution for pressure maintenance and thereby, potentially improving the recovery from the field.
采出水是油气回收过程中不可分割的一部分，也是迄今为止与油气回收相关的最大的废水流。在阿曼南部的一个c型油田，采出水已被处理到生产地层的含水层中。为了减少(或完全停止)这种水处理方式，正在评估使用替代方案在地表处理水的替代方法的可行性，这种处理方式已经显示出通过扭转压力下降来最大限度地提高采收率的好处。一个简单的模型被用来量化采出水回注到深层含水层的效益。在阿曼南部该油田的b层含水层中，深水处理(DWD)已经进行了20多年。周围油田的所有采出水都通过C-Field Processing Station DWD系统送到油田附近处理。这一DWD活动为系统提供了重要的能量，这一点在现场的油藏压力逆转趋势中得到了体现。然而，由于种种原因，人们正在努力用其他的地表采出水处理方法来取代直接钻井。建立了一个集成模型，并根据现场响应进行了校准，用于预测现场性能。校准后的模型建议通过水处理或注入系统继续向现场施加压力。该研究预测，完全停止DWD将使大量储量面临侵蚀油田价值的风险，并量化了可供地面处理替代方案的水量。该研究还发现了进一步优化压力维持解决方案的机会，从而有可能提高油田的采收率。
{"title":"Effective Reuse of the Produced Water - A Case Study from a Field in South Oman","authors":"Jasbindra Singh, Mohammed Harthi, Mohamed Siyabi, Marya Al Salmi, Carmen Hamm, Omar Riyami, Safiya Hatmi, Rady Abdel Samiee, Mohammed Hinai, Anas Mazroui, Yousuf Sinani, I. Mahruqi, Nasser Al Azri","doi":"10.2118/200200-ms","DOIUrl":"https://doi.org/10.2118/200200-ms","url":null,"abstract":"\u0000 Produced water is an inextricable part of the hydrocarbon recovery processes, yet it is by far the largest volume waste stream associated with hydrocarbon recovery. In a C-field in South Oman, the produced water has been disposed in the aquifer zone of the producing formation. The feasibility of alternative ways to dispose water at surface using alternative options is being evaluated with the objective of reducing (or completely stopping) this water disposal which has shown benefits in maximizing the recovery by reversing the pressure decline. A simple model has been used to quantify the benefits of produced water re-injection into the deep aquifer zone.\u0000 Deep water disposal (DWD) has been on-going for over 20 years in the aquifer zone in the B-formation in this field in South Oman. All the produced water from the surrounding fields is sent for disposal near the field via the C-Field Processing Station DWD system. This DWD activity has provided important energy to the system as evident in the reversing reservoir pressure trend in field. However, due to various reasons, efforts are being put forward with the aim of replacing DWD with alternative ways of disposing produced water at surface.\u0000 An integrated model has been built and calibrated to the field response and used to predict the field performance. The calibrated model recommends to continue pressure to the field through water disposal or injection system. The study predicts the complete discontinuation of DWD will put significant reserves at risk eroding the field value and has quantified the amount of water available for the alternative options for surface disposal. The study has also identified an opportunity to further optimize the solution for pressure maintenance and thereby, potentially improving the recovery from the field.","PeriodicalId":10912,"journal":{"name":"Day 3 Wed, March 23, 2022","volume":"22 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90520420","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}
V. Karpan, J. de Reus, Diederik van Batenburg, E. Mikhaylenko
An Alkaline-Surfactant-Polymer (ASP) pilot was executed in the West Salym oil field in the Russian West-Siberian oil province. To successfully interpret the project outcome an extensive surveillance plan was put in place. A tracer program formed an important, stand-alone part of the plan. Tracers injection was designed and executed to evaluate the incremental oil production due to ASP injection by using A) change in volume swept between the pilot wells and B) change in oil saturations due to ASP flooding. This paper focusses on the practical aspects of the tracer program execution and how the tracer program results were used for the interpretation of the pilot. The West Salym reservoir is a sandstone formation with 83°C temperature, 2 cP crude oil viscosity, permeabilities ranging from 10 to 250 mD and porosity ranging from 18 to 22%. The field is operated as a mature waterflood, with oil production having peaked in 2011. To increase the recovery factor, a tertiary oil recovery technique (ASP) was selected. A confined five spot well pattern was chosen for conducting the ASP field trial. Due to low remaining oil saturation after the waterflood (executed also as a pre-flush for the ASP flood) the production watercut reverse due to the ASP injection changed only from 98% to 88-90%. Hence, it was important to evaluate the efficiency of ASP flooding using several independent approaches. In addition to field injection/production data, analytical and modelling techniques, the tracer data interpretation became a valuable source of information. Four tracer injection stages were conducted during West Salym ASP pilot. Passive and partitioning tracer injection/production data were analyzed using Shook's analytical method and supported by the reservoir modelling. Analytical analysis of field data was complicated by the production and injection upsets, as well as the changes in injected viscosities. Even though the requirement for steady state conditions were not fully met, the passive tracer recovery data provided an important input to the history matching of pilot dynamic model helping to determine the sweep increase due to injection of viscous chemical solutions. The partitioning tracer recovery data in the water post-flush were used to confirm the low residual oil saturation after ASP flooding.
在俄罗斯西西伯利亚油区的西萨利姆油田进行了碱-表面活性剂-聚合物(ASP)试验。为了成功地解释项目结果，一个广泛的监督计划已经到位。示踪程序是该计划中重要的独立部分。注入示踪剂的设计和实施，是为了评估注入三元复合驱后的产油量增量，方法是:A)试验井之间波及量的变化;B)三元复合驱后油饱和度的变化。本文着重于跟踪程序执行的实际方面，以及如何使用跟踪程序结果来解释试点。West Salym油藏为砂岩储层，温度83℃，原油粘度2 cP，渗透率10 ~ 250 mD，孔隙度18% ~ 22%。该油田作为一个成熟的注水油田进行运营，其产油量在2011年达到顶峰。为了提高采收率，选择了三次采油技术(ASP)。选择了一个封闭的5点井网进行ASP现场试验。由于注水后的剩余油饱和度较低(也作为三元复合驱的预冲作业)，由于注入三元复合驱导致的生产含水率逆转仅从98%变化到88-90%。因此，使用几种独立的方法来评估三元复合驱的效率是很重要的。除了现场注入/生产数据、分析和建模技术外，示踪剂数据解释也成为宝贵的信息来源。在West Salym ASP试验期间，共进行了4次示踪剂注入。被动示踪剂和分区示踪剂注入/生产数据采用Shook的分析方法进行分析，并辅以油藏建模。现场数据的分析分析由于生产和注入紊乱以及注入粘度的变化而变得复杂。尽管没有完全满足稳态条件的要求，但被动示踪剂采收率数据为先导动态模型的历史匹配提供了重要输入，有助于确定由于注入粘性化学溶液而增加的波及范围。利用注水后的分区示踪剂采收率数据，证实复合驱后剩余油饱和度较低。
{"title":"Interpretation of the Alkaline-Surfactant-Polymer Pilot in West Salym Using Tracers","authors":"V. Karpan, J. de Reus, Diederik van Batenburg, E. Mikhaylenko","doi":"10.2118/200100-ms","DOIUrl":"https://doi.org/10.2118/200100-ms","url":null,"abstract":"\u0000 An Alkaline-Surfactant-Polymer (ASP) pilot was executed in the West Salym oil field in the Russian West-Siberian oil province. To successfully interpret the project outcome an extensive surveillance plan was put in place. A tracer program formed an important, stand-alone part of the plan. Tracers injection was designed and executed to evaluate the incremental oil production due to ASP injection by using A) change in volume swept between the pilot wells and B) change in oil saturations due to ASP flooding. This paper focusses on the practical aspects of the tracer program execution and how the tracer program results were used for the interpretation of the pilot.\u0000 The West Salym reservoir is a sandstone formation with 83°C temperature, 2 cP crude oil viscosity, permeabilities ranging from 10 to 250 mD and porosity ranging from 18 to 22%. The field is operated as a mature waterflood, with oil production having peaked in 2011. To increase the recovery factor, a tertiary oil recovery technique (ASP) was selected. A confined five spot well pattern was chosen for conducting the ASP field trial. Due to low remaining oil saturation after the waterflood (executed also as a pre-flush for the ASP flood) the production watercut reverse due to the ASP injection changed only from 98% to 88-90%. Hence, it was important to evaluate the efficiency of ASP flooding using several independent approaches. In addition to field injection/production data, analytical and modelling techniques, the tracer data interpretation became a valuable source of information.\u0000 Four tracer injection stages were conducted during West Salym ASP pilot. Passive and partitioning tracer injection/production data were analyzed using Shook's analytical method and supported by the reservoir modelling. Analytical analysis of field data was complicated by the production and injection upsets, as well as the changes in injected viscosities. Even though the requirement for steady state conditions were not fully met, the passive tracer recovery data provided an important input to the history matching of pilot dynamic model helping to determine the sweep increase due to injection of viscous chemical solutions. The partitioning tracer recovery data in the water post-flush were used to confirm the low residual oil saturation after ASP flooding.","PeriodicalId":10912,"journal":{"name":"Day 3 Wed, March 23, 2022","volume":"70 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74130541","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. Al-Taq, Luai Alhmad, Abdulla A. Alrustum, Sajjad Aldarweesh
Hydrogel polymers have served the oil and gas industry in different applications including water shot-off. Hydrogel polymers can create impermeable gels to optimize water injection profile, improve sweep efficiency, and seal undesirable permeable zones. Hydrogels have been successfully applied as remediation treatments to control water production from thief zones, natural fractures and matrix formation. In this study, a new polymer gel system (PGS), a hydrogel type, was examined for water control treatments. The experimental work included swelling testing, viscosity measurement, and coreflood experiments. The effect of water salinity, PGS concentration, pH values and temperature on hydrogel polymer system properties was examined. The PGS concentrations examined in this study were 0.5 and 1.5% while water salinity ranged from 20 to 200 g/L of NaCl. The examined pH values were 7 and 1. The coreflood experiments were conducted at 80 °C using sandstone core plugs. The results showed that viscosity of the polymer gel system increased as a function of concentration and temperature but decreased as a function of water salinity. The viscosity of PGS at 1.5 wt% and at a temperature of 60 °C decreased from 575 to 16 cP when the pH value was decreased from 7 to 1. Salinity was found to be negatively impacting the swelling properties of the examined PGS too. Coreflood experiments showed that the PGS should be squeezed into the core plug at higher injection rates (below frac pressure) in order to achieve high water control. The residual resistant factor to water obtained at an injection rate of 5 cm3/min was 158 while it was found to be < 5 at an injection rate of 1 cm3/min. At a lower injecting rate, the PGS was found to form an external filtercake at the inlet face of the core plug. The paper presents in detail lab findings of evaluation of a new hydrogel polymer system and recommend optimum conditions to control water production successfully.
{"title":"Hydrogels for Water Shut-Off Treatments: Evaluation of a New Polymer Gel System","authors":"A. Al-Taq, Luai Alhmad, Abdulla A. Alrustum, Sajjad Aldarweesh","doi":"10.2118/200041-ms","DOIUrl":"https://doi.org/10.2118/200041-ms","url":null,"abstract":"\u0000 Hydrogel polymers have served the oil and gas industry in different applications including water shot-off. Hydrogel polymers can create impermeable gels to optimize water injection profile, improve sweep efficiency, and seal undesirable permeable zones. Hydrogels have been successfully applied as remediation treatments to control water production from thief zones, natural fractures and matrix formation.\u0000 In this study, a new polymer gel system (PGS), a hydrogel type, was examined for water control treatments. The experimental work included swelling testing, viscosity measurement, and coreflood experiments. The effect of water salinity, PGS concentration, pH values and temperature on hydrogel polymer system properties was examined. The PGS concentrations examined in this study were 0.5 and 1.5% while water salinity ranged from 20 to 200 g/L of NaCl. The examined pH values were 7 and 1. The coreflood experiments were conducted at 80 °C using sandstone core plugs.\u0000 The results showed that viscosity of the polymer gel system increased as a function of concentration and temperature but decreased as a function of water salinity. The viscosity of PGS at 1.5 wt% and at a temperature of 60 °C decreased from 575 to 16 cP when the pH value was decreased from 7 to 1. Salinity was found to be negatively impacting the swelling properties of the examined PGS too. Coreflood experiments showed that the PGS should be squeezed into the core plug at higher injection rates (below frac pressure) in order to achieve high water control. The residual resistant factor to water obtained at an injection rate of 5 cm3/min was 158 while it was found to be < 5 at an injection rate of 1 cm3/min. At a lower injecting rate, the PGS was found to form an external filtercake at the inlet face of the core plug.\u0000 The paper presents in detail lab findings of evaluation of a new hydrogel polymer system and recommend optimum conditions to control water production successfully.","PeriodicalId":10912,"journal":{"name":"Day 3 Wed, March 23, 2022","volume":"7 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2022-03-21","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90203202","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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