Y. Bashir, A. H. A. Latif, Shiba Rezaei, M. Mahgoub, Syed Yaser Moussavi Alashloo, M. Hermana, D. Ghosh, C. Sum
Seismic Imaging for the small-scale feature in complex subsurface geology such as Carbonate is not easy to capture because of propagated wave affected by heterogeneous properties of objects in the subsurface. The principal goal of anisotropic seismic diffraction & reflection imaging is to get a subsurface image of structural features with the greatest sharpness or resolution. In this paper, we have presented a new approach for anisotropic diffraction preservation using offset and angle domain data during the initial data processing. Which leads to the better preservation of diffractions amplitude in laterally varying velocity condition. The plane-wave destruction filter is used with a modified approximation for Diffraction separation as the conventional filtering techniques mixed the diffraction amplitudes when there are a series of diffraction hyperbola. Further, the implementation of the proposed method has proven on carbonate field data from Sarawak Basin for steeply dipping Carbonate Build-up.
{"title":"Seismic Diffraction Imaging in Laterally Varying Velocity Media for Frequency Bandwidth Expansion - Application in Carbonate Field Sarawak, Malaysia","authors":"Y. Bashir, A. H. A. Latif, Shiba Rezaei, M. Mahgoub, Syed Yaser Moussavi Alashloo, M. Hermana, D. Ghosh, C. Sum","doi":"10.2118/197656-ms","DOIUrl":"https://doi.org/10.2118/197656-ms","url":null,"abstract":"\u0000 Seismic Imaging for the small-scale feature in complex subsurface geology such as Carbonate is not easy to capture because of propagated wave affected by heterogeneous properties of objects in the subsurface. The principal goal of anisotropic seismic diffraction & reflection imaging is to get a subsurface image of structural features with the greatest sharpness or resolution. In this paper, we have presented a new approach for anisotropic diffraction preservation using offset and angle domain data during the initial data processing. Which leads to the better preservation of diffractions amplitude in laterally varying velocity condition. The plane-wave destruction filter is used with a modified approximation for Diffraction separation as the conventional filtering techniques mixed the diffraction amplitudes when there are a series of diffraction hyperbola. Further, the implementation of the proposed method has proven on carbonate field data from Sarawak Basin for steeply dipping Carbonate Build-up.","PeriodicalId":11061,"journal":{"name":"Day 1 Mon, November 11, 2019","volume":"53 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76154032","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}
Shahril Yang, M. H. M. Yusoff, Ismail Aslam Abdullah, M. I. M. Ros, L. Devadass, Azmi Othman, Thore Andre Stokkeland, P. Matthews, Abdul Karim Sainuddin
Perforate, Wash & Cement (PWC) is a method developed over the past decade to help increase efficiency in plugging & abandonment of wells. The method has helped operators world-wide to save time and cost in plugging and abandonment operations by cutting down time for setting full lateral barriers. This technique can also be used to set permanent lateral barriers for slot recovery operations, and perform well repairs on workovers where there is sustained casing pressure. The technology is used to set lateral barriers to cure the sustained casing pressure, and enable the operator to put the wells back into production. The integrity of the well is restored and significant value is generated. However the technology has previously been limited to setting one barrier at the time. The unique challenge for this well on the Platform Alpha, offshore Malaysia was that two zones had to be isolated in one run. The distance between the two zones was almost 100 meters. A significant challenge, with a significant upside. The execution was using Hydraulic Workover Unit (HWU) and overall 14 plugs completed (for 14 wells). The method has several critical success factors that need to be tailored to be able to produce a high quality result, especially with this unique challenge of plugging and abandoning two different zones in the same run. Optimization of the Tubing Conveyed Perforation (TCP) System to be able to balance hole size, geometry and density in order to create the ideal communication path into the external annulus was paramount to the success of the job. The TCP needed to also take into consideration casing size, weight and metallurgy to ensure that downhole conditions are simulated as accurate as possible, increasing the chance of successfully meeting the perforation criteria that has been optimized. Washing parameters needed to be optimized to be able to create high annular velocity for efficient hole cleaning and debris removal. This optimization takes into consideration the fluids density and rheology, ensuring that the mud system has the correct properties to suspend the debris for removal at surface. The compatibility and stability of the fluids and mud condition prior to cementing operation is also critical. The cementing operation on this well was a unique, tailor-fit engineering project, with the end goal and intention of being able to isolate two zones approximately 100 meters apart at the same time. The cement & spacer properties were important here due to possible gas, and high chance of losses into the formation after perforating, and during washing. The volumes, operational parameters and execution were critical to get the two zones efficiently plugged and abandoned in one run. This paper describes the extensive work that has been performed to plan and execute the successful plugging and abandonment of two independent zones using the Perforate, Wash and Cement technology; and in the process, saving several days of rig time,
{"title":"Plugging & Abandonment of Multiple Zones in One Run Using Perforate Wash and Cement on Hydraulic Workover Unit","authors":"Shahril Yang, M. H. M. Yusoff, Ismail Aslam Abdullah, M. I. M. Ros, L. Devadass, Azmi Othman, Thore Andre Stokkeland, P. Matthews, Abdul Karim Sainuddin","doi":"10.2118/197149-ms","DOIUrl":"https://doi.org/10.2118/197149-ms","url":null,"abstract":"\u0000 \u0000 \u0000 Perforate, Wash & Cement (PWC) is a method developed over the past decade to help increase efficiency in plugging & abandonment of wells. The method has helped operators world-wide to save time and cost in plugging and abandonment operations by cutting down time for setting full lateral barriers.\u0000 This technique can also be used to set permanent lateral barriers for slot recovery operations, and perform well repairs on workovers where there is sustained casing pressure. The technology is used to set lateral barriers to cure the sustained casing pressure, and enable the operator to put the wells back into production. The integrity of the well is restored and significant value is generated.\u0000 However the technology has previously been limited to setting one barrier at the time. The unique challenge for this well on the Platform Alpha, offshore Malaysia was that two zones had to be isolated in one run. The distance between the two zones was almost 100 meters. A significant challenge, with a significant upside. The execution was using Hydraulic Workover Unit (HWU) and overall 14 plugs completed (for 14 wells).\u0000 \u0000 \u0000 \u0000 The method has several critical success factors that need to be tailored to be able to produce a high quality result, especially with this unique challenge of plugging and abandoning two different zones in the same run.\u0000 Optimization of the Tubing Conveyed Perforation (TCP) System to be able to balance hole size, geometry and density in order to create the ideal communication path into the external annulus was paramount to the success of the job. The TCP needed to also take into consideration casing size, weight and metallurgy to ensure that downhole conditions are simulated as accurate as possible, increasing the chance of successfully meeting the perforation criteria that has been optimized.\u0000 Washing parameters needed to be optimized to be able to create high annular velocity for efficient hole cleaning and debris removal. This optimization takes into consideration the fluids density and rheology, ensuring that the mud system has the correct properties to suspend the debris for removal at surface. The compatibility and stability of the fluids and mud condition prior to cementing operation is also critical.\u0000 The cementing operation on this well was a unique, tailor-fit engineering project, with the end goal and intention of being able to isolate two zones approximately 100 meters apart at the same time. The cement & spacer properties were important here due to possible gas, and high chance of losses into the formation after perforating, and during washing. The volumes, operational parameters and execution were critical to get the two zones efficiently plugged and abandoned in one run.\u0000 This paper describes the extensive work that has been performed to plan and execute the successful plugging and abandonment of two independent zones using the Perforate, Wash and Cement technology; and in the process, saving several days of rig time,","PeriodicalId":11061,"journal":{"name":"Day 1 Mon, November 11, 2019","volume":"65 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89123932","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. Shbair, L. Saputelli, F. Noordin, V. Bogoslavets, Y. Alblooshi, A. Soufi, Mohammed Hijjawi
Water injection is by far the most popular method used in the secondary recovery phase of field development for oil displacement and pressure maintenance. Proactive reservoir management is important to validate the efficiency of the existing water injection schemes and to assess field development strategies to prolong oil production plateau and improve the recovery factor (RF). The main challenges arise in stretching the reservoir target whilst ensuring stabilized or reduced water cut (WCT), minimizing by-passed oil volumes and preventing wells from becoming inactive due to high WCT. In order to mitigate premature water flooding issues, mainly two options are available: (1) artificial lift techniques to activate producers suffering early and rapid water breakthrough; and (2) optimized completion designs via preventive or corrective controls. Preventive (i.e. proactive) approach involves segmenting the wellbore using sliding sleeves, influx control equipment, limited-perforated liners, while corrective (i.e. reactive) methods attempt to divert/remedy unwanted water influx via water-shut off (WSO) interventions. None of these alternatives can be fully pursued as full-field development strategies without realizing the technical limitations as well as their economic benefits. The objective of this paper is to determine the value of applying subsurface water control strategies in the context of enhancing reservoir management and develop a novel framework to assess potential remediation opportunities. The technical evaluation was supported by a robust Integrated Reservoir Management (IRM) process. This process identified the rig/rigless jobs opportunities to intervene inactive wells due to high WCT and rank all possible mitigation methods in an automated economic manner. The findings have also proved the value of installing autonomous inflow control devices (AICDs) to control water production along horizontal sections. In effect, it controlled water slumping without jeopardizing oil production of wells awaiting gas lifting. A case scenario of combined Gas-lift and ICD deployments suggested a net incremental value of $66 million (or 106%). Field test results of the horizontal well's production and WCT were found to be within 10% of the expected planned rates, and the oil gain is expected to further improve by 50% when gas-lift is commenced.
{"title":"Unlocking Challenges in Water Injection Development Schemes Utilizing a Novel IRM Automation Workflow for Opportunities Generation","authors":"A. Shbair, L. Saputelli, F. Noordin, V. Bogoslavets, Y. Alblooshi, A. Soufi, Mohammed Hijjawi","doi":"10.2118/197708-ms","DOIUrl":"https://doi.org/10.2118/197708-ms","url":null,"abstract":"\u0000 Water injection is by far the most popular method used in the secondary recovery phase of field development for oil displacement and pressure maintenance. Proactive reservoir management is important to validate the efficiency of the existing water injection schemes and to assess field development strategies to prolong oil production plateau and improve the recovery factor (RF). The main challenges arise in stretching the reservoir target whilst ensuring stabilized or reduced water cut (WCT), minimizing by-passed oil volumes and preventing wells from becoming inactive due to high WCT.\u0000 In order to mitigate premature water flooding issues, mainly two options are available: (1) artificial lift techniques to activate producers suffering early and rapid water breakthrough; and (2) optimized completion designs via preventive or corrective controls. Preventive (i.e. proactive) approach involves segmenting the wellbore using sliding sleeves, influx control equipment, limited-perforated liners, while corrective (i.e. reactive) methods attempt to divert/remedy unwanted water influx via water-shut off (WSO) interventions. None of these alternatives can be fully pursued as full-field development strategies without realizing the technical limitations as well as their economic benefits.\u0000 The objective of this paper is to determine the value of applying subsurface water control strategies in the context of enhancing reservoir management and develop a novel framework to assess potential remediation opportunities. The technical evaluation was supported by a robust Integrated Reservoir Management (IRM) process. This process identified the rig/rigless jobs opportunities to intervene inactive wells due to high WCT and rank all possible mitigation methods in an automated economic manner.\u0000 The findings have also proved the value of installing autonomous inflow control devices (AICDs) to control water production along horizontal sections. In effect, it controlled water slumping without jeopardizing oil production of wells awaiting gas lifting. A case scenario of combined Gas-lift and ICD deployments suggested a net incremental value of $66 million (or 106%). Field test results of the horizontal well's production and WCT were found to be within 10% of the expected planned rates, and the oil gain is expected to further improve by 50% when gas-lift is commenced.","PeriodicalId":11061,"journal":{"name":"Day 1 Mon, November 11, 2019","volume":"7 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"88163455","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}
Maintaining pipelines in optimum condition is a costly and time-consuming process for operators, which requires many resources. To help ensure an asset remains in a good operational state, it is necessary to understand its condition to allow it to be maintained in an efficient and cost-effective manner. Current methods for deposit assessment are limited to intrusive methods, theoretical modeling, or external measurement. This paper details a compressive solution to these challenges using pressure wave analysis. The method is based on analyzing the signal response generated by a pressure wave transiting the system as it is affected by geometrical changes in the system. By capturing high resolution pressure measurement on an ultrahigh speed logger, the generated pressure wave can be recorded for analysis. Applying acoustic velocity gradient modeling in conjunction with the effect of the of the system and the fluid parameters, the profile of the internal bore of the system can be accurately determined without the use of intrusive or localized external tools. Detailed is how the theory behind the method is confirmed by results observed when used during a controlled full-scale field-trial environment in addition to subsequent activities to survey system profiles. A case study is presented, demonstrating that the method allows operators to make decisive asset performance decisions and review deposit buildup in a safe and cost-effective manner without having to stop production. The theoretical method for calculation of acoustic velocity for known system and fluid parameters is shown to be accurate within tolerances compared to the acoustic velocity gained in the field by recording the time of flight between two known points. It is demonstrated that restrictions can be detected to a level of accuracy of plus or minus three millimeters of thickness, verified by comparison with other inspection methods. The described is a unique method for determining the internal profile of systems, which can offer significant advantages from traditional bore determination methods. It can provide information in a repeatable and verified level of accuracy without the requirement for expensive and time consuming intrusive intervention, this allows operators the opportunity to target remediation work in the most efficient and cost effective manner, therefore maximizing production uptime and throughput.
{"title":"Reducing Pipeline Maintenance Costs, Time, and Resources Through Nonintrusive Diagnostics","authors":"N. Stewart, G. Jack","doi":"10.2118/197262-ms","DOIUrl":"https://doi.org/10.2118/197262-ms","url":null,"abstract":"\u0000 Maintaining pipelines in optimum condition is a costly and time-consuming process for operators, which requires many resources. To help ensure an asset remains in a good operational state, it is necessary to understand its condition to allow it to be maintained in an efficient and cost-effective manner. Current methods for deposit assessment are limited to intrusive methods, theoretical modeling, or external measurement. This paper details a compressive solution to these challenges using pressure wave analysis.\u0000 The method is based on analyzing the signal response generated by a pressure wave transiting the system as it is affected by geometrical changes in the system. By capturing high resolution pressure measurement on an ultrahigh speed logger, the generated pressure wave can be recorded for analysis. Applying acoustic velocity gradient modeling in conjunction with the effect of the of the system and the fluid parameters, the profile of the internal bore of the system can be accurately determined without the use of intrusive or localized external tools.\u0000 Detailed is how the theory behind the method is confirmed by results observed when used during a controlled full-scale field-trial environment in addition to subsequent activities to survey system profiles. A case study is presented, demonstrating that the method allows operators to make decisive asset performance decisions and review deposit buildup in a safe and cost-effective manner without having to stop production. The theoretical method for calculation of acoustic velocity for known system and fluid parameters is shown to be accurate within tolerances compared to the acoustic velocity gained in the field by recording the time of flight between two known points. It is demonstrated that restrictions can be detected to a level of accuracy of plus or minus three millimeters of thickness, verified by comparison with other inspection methods.\u0000 The described is a unique method for determining the internal profile of systems, which can offer significant advantages from traditional bore determination methods. It can provide information in a repeatable and verified level of accuracy without the requirement for expensive and time consuming intrusive intervention, this allows operators the opportunity to target remediation work in the most efficient and cost effective manner, therefore maximizing production uptime and throughput.","PeriodicalId":11061,"journal":{"name":"Day 1 Mon, November 11, 2019","volume":"82 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85858174","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
M. Kelkouli, John Zaggas, Y. Boudiba, Abderrahmane Akham, Riad Boumahrat, S. Ferraz, Sofiane Bellabiod
An exploration deep well crossing two reservoirs with different quality and properties, having an objective of: Fluid identification and sampling in extremely tight section (∼0.02mD/cP mobility) as well as in another section that is suspected to be depleted with very high overbalance exceeding legacy tools, knowing the hydrostatic pressure being ∼9500psia. Wireline formation tester was run using single probe, leading to 65% of tight stations, the rest were valid but with very low mobility. This exposes the tool to an increasing pressure differential exceeding its physical limit and leading to damaging it. This makes any further analysis impossible. The toolstring was upgraded with latest technology of WFT, that is a merge between probe based and dual packer modules. This new technology was designed with extreme environments in mind, that allows sampling in all mobility range from extreme tight to very high with its capability of holding up to 8000psia differential pressure. In the job described here, some of the tested reservoir sections were differentially depleted, something unknown to customer as this was an exploration environment. Since this information were not know even after the completion of the first and second run, a third run was carried out with the objective of re-investigating the same depths performed by the single probe, but this time 3D Radial Probe was used instead. This gave the advantage of taking the pressure down to almost 0 psia. The potential hydrocarbon zone which was bypassed (seen dry with single probe) was then tested with 3D radial probe giving a reservoir pressure of 2864psia with a mobility of ∼300mD/cP where gas condensate was identified and captured. Now for the extreme tight reservoir section, in combination with high hydrostatic, the mechanical limitation of traditional tools remains the same making sampling and/or fluid ID impossible. An attempt was made using the 3D radial probe, and despite the extreme low mobility ∼0.02mD/cP, an identification of the reservoir fluid (water) was successfully completed without any issue. The use of 3D Radial Probe technology gave a completely different picture from what was expected, enabled the completion of all objectives and made the impossible (with conventional technology) possibly and easily achievable. This resulted in changing the well strategies accordingly and complete the well successfully. The new technology made the testing of unconventional reservoirs a reality.
{"title":"Breaking New Grounds and Records for Unconventional Reservoirs Characterization Using the New Formation Testing and Sampling Technology","authors":"M. Kelkouli, John Zaggas, Y. Boudiba, Abderrahmane Akham, Riad Boumahrat, S. Ferraz, Sofiane Bellabiod","doi":"10.2118/197281-ms","DOIUrl":"https://doi.org/10.2118/197281-ms","url":null,"abstract":"\u0000 An exploration deep well crossing two reservoirs with different quality and properties, having an objective of: Fluid identification and sampling in extremely tight section (∼0.02mD/cP mobility) as well as in another section that is suspected to be depleted with very high overbalance exceeding legacy tools, knowing the hydrostatic pressure being ∼9500psia.\u0000 Wireline formation tester was run using single probe, leading to 65% of tight stations, the rest were valid but with very low mobility. This exposes the tool to an increasing pressure differential exceeding its physical limit and leading to damaging it. This makes any further analysis impossible. The toolstring was upgraded with latest technology of WFT, that is a merge between probe based and dual packer modules. This new technology was designed with extreme environments in mind, that allows sampling in all mobility range from extreme tight to very high with its capability of holding up to 8000psia differential pressure.\u0000 In the job described here, some of the tested reservoir sections were differentially depleted, something unknown to customer as this was an exploration environment. Since this information were not know even after the completion of the first and second run, a third run was carried out with the objective of re-investigating the same depths performed by the single probe, but this time 3D Radial Probe was used instead. This gave the advantage of taking the pressure down to almost 0 psia. The potential hydrocarbon zone which was bypassed (seen dry with single probe) was then tested with 3D radial probe giving a reservoir pressure of 2864psia with a mobility of ∼300mD/cP where gas condensate was identified and captured. Now for the extreme tight reservoir section, in combination with high hydrostatic, the mechanical limitation of traditional tools remains the same making sampling and/or fluid ID impossible. An attempt was made using the 3D radial probe, and despite the extreme low mobility ∼0.02mD/cP, an identification of the reservoir fluid (water) was successfully completed without any issue.\u0000 The use of 3D Radial Probe technology gave a completely different picture from what was expected, enabled the completion of all objectives and made the impossible (with conventional technology) possibly and easily achievable. This resulted in changing the well strategies accordingly and complete the well successfully. The new technology made the testing of unconventional reservoirs a reality.","PeriodicalId":11061,"journal":{"name":"Day 1 Mon, November 11, 2019","volume":"31 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83950867","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}
Eni has more than 40 years' experience on developing and managing sour hydrocarbons Projects. That has allowed to build up in Eni a specific knowhow, which is continuously improving and updating through operational activities on assets with an high concentration of H2S in the process fluids such as Karachaganak and Kashagan in Kazakhstan, COVA in Southern Italy and the more recent Zohr facilities in Egypt. The Eni's acquired knowledge in running sour hydrocarbon assets, both offshore and onshore, has been founded on a robust risk based approach. Since the project start, risk assessments such as blowout study, Quantitative Risk Assessment, Emergency Escape Rescue Analysis, etc. results are considered the pillars for the proper design, construction, commissioning, start-up and operations phases. Specifically, SIMOPS/CONOPS methodologies and procedures and their applications in sour operational contexts are defined for managing sour hydrocarbons assets and activities.
{"title":"Running Sour Hydrocarbon Assets: Eni's Story of Experience","authors":"L. Scataglini, L. Decarli","doi":"10.2118/197582-ms","DOIUrl":"https://doi.org/10.2118/197582-ms","url":null,"abstract":"\u0000 Eni has more than 40 years' experience on developing and managing sour hydrocarbons Projects. That has allowed to build up in Eni a specific knowhow, which is continuously improving and updating through operational activities on assets with an high concentration of H2S in the process fluids such as Karachaganak and Kashagan in Kazakhstan, COVA in Southern Italy and the more recent Zohr facilities in Egypt.\u0000 The Eni's acquired knowledge in running sour hydrocarbon assets, both offshore and onshore, has been founded on a robust risk based approach. Since the project start, risk assessments such as blowout study, Quantitative Risk Assessment, Emergency Escape Rescue Analysis, etc. results are considered the pillars for the proper design, construction, commissioning, start-up and operations phases. Specifically, SIMOPS/CONOPS methodologies and procedures and their applications in sour operational contexts are defined for managing sour hydrocarbons assets and activities.","PeriodicalId":11061,"journal":{"name":"Day 1 Mon, November 11, 2019","volume":"30 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78697268","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}
Zainah Salem Al Agbari, M. Chatterjee, P. Hewitt, I. Mohamed, M. Sudarev, E. Latypov, Ahmed Mohamed Al Bairaq, Ammar Al Amri
Using a tracer as a monitoring technique to measure the migration of the injected fluid in the reservoir is relatively inexpensive method, and it applied in numerous fields throughout the world. The application of tracer can assess the volumetric sweep to quantify the amount of fluid flowing from injectors to producers. It gives an indication of offending injectors. Tracer helps in addressing the communication between different reservoir units. Another objective is delineation of flow barriers to identify the geological features that dominate the flow directionality (i.e. high permeability streaks, faults, fractures, etc) to determine directional permeability trends. The information obtained from tracer can reduce the model uncertainty and provide better tuning for future prediction. The tracer data is used to generate not only qualitative information but also a substantial amount of quantitative data. Primarily, chemical tracers should be tested against a number of reservoir formation rocks and found not to adsorb or retard. Tracers are injected in the injectors and the samples are collected from nearby producers. Analysis of tracer concentration versus time curves from individual producing wells enables interwell flow characteristics to be determined so that improvements can be made to optimize sweep effectiveness of the hydrocarbon reserve. A record of base line sampling and analyses from all producers should be conducted. A frequent sampling and analysis are performed to understand the reservoir characteristics and performance. After the application of tracer technique, the following results were observed: The first breakthrough was detected after about one year; due to the short distance between the injector and the producer. The second breakthrough was detected after about three years; due to the reservoir characteristic in the producers. An identical patterns of tracer response was seen, indicates almost homogenous reservoir in the tracer injected. This points out towards a similar depositional pattern across the reservoir. Most of tracers are observed downward towards the flank area. Tracer direction was to the least pressure area (flank) due to high offtake. No breakthrough was observed in the attic wells due to high pressure area. Tracer technology is inexpensive method used to provide inflow directional information, and it has no impact on the completion design and effectively prove the reservoir characterizations and well performance.
{"title":"Use Of Tracer Technology to Improve Reservoir Understanding","authors":"Zainah Salem Al Agbari, M. Chatterjee, P. Hewitt, I. Mohamed, M. Sudarev, E. Latypov, Ahmed Mohamed Al Bairaq, Ammar Al Amri","doi":"10.2118/197364-ms","DOIUrl":"https://doi.org/10.2118/197364-ms","url":null,"abstract":"\u0000 Using a tracer as a monitoring technique to measure the migration of the injected fluid in the reservoir is relatively inexpensive method, and it applied in numerous fields throughout the world. The application of tracer can assess the volumetric sweep to quantify the amount of fluid flowing from injectors to producers. It gives an indication of offending injectors. Tracer helps in addressing the communication between different reservoir units. Another objective is delineation of flow barriers to identify the geological features that dominate the flow directionality (i.e. high permeability streaks, faults, fractures, etc) to determine directional permeability trends. The information obtained from tracer can reduce the model uncertainty and provide better tuning for future prediction.\u0000 The tracer data is used to generate not only qualitative information but also a substantial amount of quantitative data. Primarily, chemical tracers should be tested against a number of reservoir formation rocks and found not to adsorb or retard. Tracers are injected in the injectors and the samples are collected from nearby producers. Analysis of tracer concentration versus time curves from individual producing wells enables interwell flow characteristics to be determined so that improvements can be made to optimize sweep effectiveness of the hydrocarbon reserve. A record of base line sampling and analyses from all producers should be conducted. A frequent sampling and analysis are performed to understand the reservoir characteristics and performance.\u0000 After the application of tracer technique, the following results were observed: The first breakthrough was detected after about one year; due to the short distance between the injector and the producer. The second breakthrough was detected after about three years; due to the reservoir characteristic in the producers. An identical patterns of tracer response was seen, indicates almost homogenous reservoir in the tracer injected. This points out towards a similar depositional pattern across the reservoir. Most of tracers are observed downward towards the flank area. Tracer direction was to the least pressure area (flank) due to high offtake. No breakthrough was observed in the attic wells due to high pressure area.\u0000 Tracer technology is inexpensive method used to provide inflow directional information, and it has no impact on the completion design and effectively prove the reservoir characterizations and well performance.","PeriodicalId":11061,"journal":{"name":"Day 1 Mon, November 11, 2019","volume":"110 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79248864","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}
Erismar Rubio, N. Reddicharla, Melike Dilsiz, Mohamed Ali Al-Attar, Apurv Raj, Sandeep Soni, S. Sabat, Jose Isambertt
This paper describes an efficient, accurate, and timesaving approach for setting well allowable using advanced and automated workflows in a digital oil field with more than 300 producing and injecting strings from multi-layered reservoirs having varied reservoir characteristics. This paper provides an insight on the usage of ADNOC shareholders guidelines, well characteristics, surface facility constraints, and integrated asset models to compute the well allowable rate. An integrated asset operations model (IAOM) within a digital framework provides an automation of engineering approach where shareholder/reservoir management guidelines, in conjunction with a calibrated well and network models, are used to improve efficiency and accuracy of setting wells allowable. This process incorporates the interaction among various components, including wellbore dynamics (Inflow and outflow performance), surface network backpressure effect, and complex system constraints. "System Efficiency and Well Availability" factors as well as predicted well parameters such as GOR and watercut. This advance workflow computes the rate that can be delivered from each well corresponding to each guideline and constraint, thereby providing key inputs to various business objective scenarios for production efficiency improvement. This automated "Setting Well Allowable" workflow, using an IAOM solution in a digital framework, has enabled the asset to identify true potential of wells and overcoming potential challenges of computational time saving while identifying opportunities. This automated validation workflows ensured usage of updated and validated well models, allowing effective use of the well test information and real time data for further analysis and sensitivities. The use of the automated workflow has reduced the time to compute the well allowable rates and well technical rates by more than 50%. This workflow prevented engineers from performing tedious manual calculations on a well-by-well basis, therefore engineers focus on engineering and analytical problems rather than collecting data. Additionally, this robust engineering approach provides users with key information associated with a well's performance under various guideline index such as potential rates, well technical rate, minimum backpressure rate, rate to maintain drawdown/ minimum bottom hole pressure limit to ensure a homogenous reservoir withdraw to avoid pressure sink areas. This work process also highlights the wells with increased watercut (WC) and gas oil ratio (GOR), thus providing crucial information for deteriorating well performance. A short-term forecasting with diagnostic curve fitting and trend analysis enabled users to validate deliverability of allowable rates in a calibrated network model scenario, thereby incorporating potential surface constraints and facility bottlenecks. The robustness of advanced and automated setting of well allowable workflow enables the operator to establish well
{"title":"Unlocking Well Potential Using an Automated Well Allowable Analysis in a Digital IAOM Framework","authors":"Erismar Rubio, N. Reddicharla, Melike Dilsiz, Mohamed Ali Al-Attar, Apurv Raj, Sandeep Soni, S. Sabat, Jose Isambertt","doi":"10.2118/197877-ms","DOIUrl":"https://doi.org/10.2118/197877-ms","url":null,"abstract":"\u0000 This paper describes an efficient, accurate, and timesaving approach for setting well allowable using advanced and automated workflows in a digital oil field with more than 300 producing and injecting strings from multi-layered reservoirs having varied reservoir characteristics. This paper provides an insight on the usage of ADNOC shareholders guidelines, well characteristics, surface facility constraints, and integrated asset models to compute the well allowable rate.\u0000 An integrated asset operations model (IAOM) within a digital framework provides an automation of engineering approach where shareholder/reservoir management guidelines, in conjunction with a calibrated well and network models, are used to improve efficiency and accuracy of setting wells allowable. This process incorporates the interaction among various components, including wellbore dynamics (Inflow and outflow performance), surface network backpressure effect, and complex system constraints. \"System Efficiency and Well Availability\" factors as well as predicted well parameters such as GOR and watercut. This advance workflow computes the rate that can be delivered from each well corresponding to each guideline and constraint, thereby providing key inputs to various business objective scenarios for production efficiency improvement.\u0000 This automated \"Setting Well Allowable\" workflow, using an IAOM solution in a digital framework, has enabled the asset to identify true potential of wells and overcoming potential challenges of computational time saving while identifying opportunities. This automated validation workflows ensured usage of updated and validated well models, allowing effective use of the well test information and real time data for further analysis and sensitivities.\u0000 The use of the automated workflow has reduced the time to compute the well allowable rates and well technical rates by more than 50%. This workflow prevented engineers from performing tedious manual calculations on a well-by-well basis, therefore engineers focus on engineering and analytical problems rather than collecting data. Additionally, this robust engineering approach provides users with key information associated with a well's performance under various guideline index such as potential rates, well technical rate, minimum backpressure rate, rate to maintain drawdown/ minimum bottom hole pressure limit to ensure a homogenous reservoir withdraw to avoid pressure sink areas. This work process also highlights the wells with increased watercut (WC) and gas oil ratio (GOR), thus providing crucial information for deteriorating well performance. A short-term forecasting with diagnostic curve fitting and trend analysis enabled users to validate deliverability of allowable rates in a calibrated network model scenario, thereby incorporating potential surface constraints and facility bottlenecks.\u0000 The robustness of advanced and automated setting of well allowable workflow enables the operator to establish well ","PeriodicalId":11061,"journal":{"name":"Day 1 Mon, November 11, 2019","volume":"13 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83372226","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}
Prasad B. Karadkar, Ayman Almohsin, M. Bataweel, Jin Huang
A nanosilica based fluid system was evaluated for forming in-situ glass-like material inside matrix for permanent gas shutoff. This novel method involves two steps; firstly, pumping low viscosity aqueous nanosilica mixture into the formation and allowing it to gel up. Secondly, gas production dehydrates nanosilica to form glass-like material inside the matrix. For this paper, a nanosilica-based fluid system was assessed for pumping strategy and performance evaluation. A nanosilica based fluid system consists of a mixture of colloidal silica and activators. It possesses low viscosity, which assists in deeper penetration during placement. With time and temperature, it can lead to in-situ gelation to form a rigid gel to block the pore space. Gas production can dehydrate nanosilica gel to form in-situ glass-like material inside formation porosity for permanent gas shutoff. The nanosilica based fluid system was optimized using gelation tests and core flooding tests to evaluate its performance under high-pressure, high-temperature conditions. Formation of in-situ glass-like material inside pores was analyzed using a scanning electron microscope (SEM). The gelation time can be tailored by varying the activator type and concentration to match the field operation requirements. Kinetics of colloidal silica gelation at elevated temperatures showed faster viscosity buildup. Before gelation, the viscosity for the nanosilica based fluid system was recorded less than 5 cp at a 10 1/s shear rate, whereas the viscosity was increased more than 500 cp at a 10 1/s shear rate. Using core flow tests, N2 gas permeability of the Berea sandstone core was completely plugged after pumping the 5-pore volume nanosilica based fluid system at 200°F. During nanosilica based fluid system injection through the core, differential pressure was increased to only 10 psi showing better injectivity. The SEM images showed the presence of glass like material filling the porosity, which showed in-situ generation of glass-like material inside pores. The nanosilica based fluid system has a low viscosity and can penetrate deeper into the formation matrix before transforming into a gel. Undesirable gas flow can dehydrate nanosilica gel to form in-situ glass-like material inside matrix for permanent sealing. This is environmentally friendly and can serve as an alternative to currently used conformance polymers for gas shutoff applications.
{"title":"In-situ Pore Plugging Using Nanosilica Based Fluid System for Gas Shutoff","authors":"Prasad B. Karadkar, Ayman Almohsin, M. Bataweel, Jin Huang","doi":"10.2118/197578-ms","DOIUrl":"https://doi.org/10.2118/197578-ms","url":null,"abstract":"\u0000 A nanosilica based fluid system was evaluated for forming in-situ glass-like material inside matrix for permanent gas shutoff. This novel method involves two steps; firstly, pumping low viscosity aqueous nanosilica mixture into the formation and allowing it to gel up. Secondly, gas production dehydrates nanosilica to form glass-like material inside the matrix. For this paper, a nanosilica-based fluid system was assessed for pumping strategy and performance evaluation.\u0000 A nanosilica based fluid system consists of a mixture of colloidal silica and activators. It possesses low viscosity, which assists in deeper penetration during placement. With time and temperature, it can lead to in-situ gelation to form a rigid gel to block the pore space. Gas production can dehydrate nanosilica gel to form in-situ glass-like material inside formation porosity for permanent gas shutoff. The nanosilica based fluid system was optimized using gelation tests and core flooding tests to evaluate its performance under high-pressure, high-temperature conditions. Formation of in-situ glass-like material inside pores was analyzed using a scanning electron microscope (SEM).\u0000 The gelation time can be tailored by varying the activator type and concentration to match the field operation requirements. Kinetics of colloidal silica gelation at elevated temperatures showed faster viscosity buildup. Before gelation, the viscosity for the nanosilica based fluid system was recorded less than 5 cp at a 10 1/s shear rate, whereas the viscosity was increased more than 500 cp at a 10 1/s shear rate. Using core flow tests, N2 gas permeability of the Berea sandstone core was completely plugged after pumping the 5-pore volume nanosilica based fluid system at 200°F. During nanosilica based fluid system injection through the core, differential pressure was increased to only 10 psi showing better injectivity. The SEM images showed the presence of glass like material filling the porosity, which showed in-situ generation of glass-like material inside pores.\u0000 The nanosilica based fluid system has a low viscosity and can penetrate deeper into the formation matrix before transforming into a gel. Undesirable gas flow can dehydrate nanosilica gel to form in-situ glass-like material inside matrix for permanent sealing. This is environmentally friendly and can serve as an alternative to currently used conformance polymers for gas shutoff applications.","PeriodicalId":11061,"journal":{"name":"Day 1 Mon, November 11, 2019","volume":"146 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76747447","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 Saudi Aramco department operates 12 gas oil separation plants (GOSPs) that have water-oil separators (WOSEPs) for produced water deoiling. The water is then injected back into the reservoir to maintain pressure. This paper provides details of the operational best practices and technologies for ensuring that the produced water is within specification. A thorough analysis was conducted to determine the areas of improvement by adjusting process parameters, enhancing the upstream process controls and implementing modifications in the WOSEP. The impact of all changes was measured by monitoring the quality of produced water, particularly the oil in water concentration, through frequent sampling. Moreover, design deficiencies were observed, which led to the proposal of specific WOSEP internal upgrades and new technologies for enhancing the deoiling performance. All recommendations were combined into a single roadmap for the department. Significant improvements in produced water quality were observed. This includes an 80% reduction in off-spec samples and a lower average oil in water concentration. The roadmap also includes proposals for major upgrades to the existing WOSEP design. The WOSEP performance roadmap provides innovative yet simple best practices that can improve the deoiling efficiency. Moreover, it links WOSEP performance to process flow stability.
{"title":"Best Practices and Technologies for Enhancing Produced Water Quality","authors":"R. White, Abdullah H Alhamoud","doi":"10.2118/197155-ms","DOIUrl":"https://doi.org/10.2118/197155-ms","url":null,"abstract":"\u0000 \u0000 \u0000 A Saudi Aramco department operates 12 gas oil separation plants (GOSPs) that have water-oil separators (WOSEPs) for produced water deoiling. The water is then injected back into the reservoir to maintain pressure. This paper provides details of the operational best practices and technologies for ensuring that the produced water is within specification.\u0000 \u0000 \u0000 \u0000 A thorough analysis was conducted to determine the areas of improvement by adjusting process parameters, enhancing the upstream process controls and implementing modifications in the WOSEP. The impact of all changes was measured by monitoring the quality of produced water, particularly the oil in water concentration, through frequent sampling. Moreover, design deficiencies were observed, which led to the proposal of specific WOSEP internal upgrades and new technologies for enhancing the deoiling performance. All recommendations were combined into a single roadmap for the department.\u0000 \u0000 \u0000 \u0000 Significant improvements in produced water quality were observed. This includes an 80% reduction in off-spec samples and a lower average oil in water concentration. The roadmap also includes proposals for major upgrades to the existing WOSEP design.\u0000 \u0000 \u0000 \u0000 The WOSEP performance roadmap provides innovative yet simple best practices that can improve the deoiling efficiency. Moreover, it links WOSEP performance to process flow stability.\u0000","PeriodicalId":11061,"journal":{"name":"Day 1 Mon, November 11, 2019","volume":"4 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-11-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"76978783","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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