R. Cornwall, S. Nuimi, Deepak Tripathi, M. Hidalgo, Sandeep Soni
This paper describes an efficient approach for estimating well potential using advanced, automated workflows for a large field with more than a thousand well strings from multi-layered reservoirs having different characteristics. This paper provides insight into reservoir guidelines, well performance, and surface facility constraints using the integrated asset operations model (IAOM) to compute well potential. The IAOM tool automates an engineering approach in which reservoir management guidelines, in conjunction with calibrated wells and a network model, are used to estimate well potentials. This process incorporates the interaction among various components including wellbore dynamics (Inflow performance and well performance), surface network backpressure effects and well performance key parameters, such as GOR and water cut. This engineered workflow computes the well potential corresponding to each guideline and constraint. This engineered workflow has reduced the time to compute the well potential rate from 3-4 weeks to just 2 hours for this large field, reducing computation time by more than 95%. This workflow helped engineers to avoid tedious manual calculations on a well-by-well basis and allowed them to focus on engineering, analytical, and optimization problems. The confirmation of calculated well potential rates using the updated surface network model helped in finalizing the business scenarios such as field-capacity tests. For example, the accuracy of predicted results in a zonal capacity test was approximately 98% using this engineered workflow approach. The value derived from this engineering logic using validated physical models supported the business plan and further identified key candidates for production optimization without heavy dependence on drilling additional wells, leading to cost optimization. This automated workflow ensures the use of updated physical models and maintains higher accuracy of results. This digital system-based data-management process supports data governance objectives. This enhanced workflow supports corporate objectives of standardization for a work process to set well allowable, in line with the operator's integrated reservoir management (IRM) initiative.
{"title":"Improving Efficiency and Accuracy in Estimating Well Potential Using an Integrated Asset Operations Model","authors":"R. Cornwall, S. Nuimi, Deepak Tripathi, M. Hidalgo, Sandeep Soni","doi":"10.2118/194877-MS","DOIUrl":"https://doi.org/10.2118/194877-MS","url":null,"abstract":"\u0000 This paper describes an efficient approach for estimating well potential using advanced, automated workflows for a large field with more than a thousand well strings from multi-layered reservoirs having different characteristics. This paper provides insight into reservoir guidelines, well performance, and surface facility constraints using the integrated asset operations model (IAOM) to compute well potential.\u0000 The IAOM tool automates an engineering approach in which reservoir management guidelines, in conjunction with calibrated wells and a network model, are used to estimate well potentials. This process incorporates the interaction among various components including wellbore dynamics (Inflow performance and well performance), surface network backpressure effects and well performance key parameters, such as GOR and water cut. This engineered workflow computes the well potential corresponding to each guideline and constraint.\u0000 This engineered workflow has reduced the time to compute the well potential rate from 3-4 weeks to just 2 hours for this large field, reducing computation time by more than 95%. This workflow helped engineers to avoid tedious manual calculations on a well-by-well basis and allowed them to focus on engineering, analytical, and optimization problems. The confirmation of calculated well potential rates using the updated surface network model helped in finalizing the business scenarios such as field-capacity tests. For example, the accuracy of predicted results in a zonal capacity test was approximately 98% using this engineered workflow approach. The value derived from this engineering logic using validated physical models supported the business plan and further identified key candidates for production optimization without heavy dependence on drilling additional wells, leading to cost optimization. This automated workflow ensures the use of updated physical models and maintains higher accuracy of results. This digital system-based data-management process supports data governance objectives.\u0000 This enhanced workflow supports corporate objectives of standardization for a work process to set well allowable, in line with the operator's integrated reservoir management (IRM) initiative.","PeriodicalId":11031,"journal":{"name":"Day 4 Thu, March 21, 2019","volume":"11 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90206464","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}
Amjed Hassan, M. Mahmoud, Abdulaziz Al-Majed, O. Alade, A. Al-Nakhli, M. Bataweel, Salaheldin Elktatany
In petroleum industry, great challenges are associated with producing hydrocarbon from unconventional reservoirs. Tight reservoirs are characterized with low permeability which reduces the hydrocarbon flow into the wellbore. Water blockage is considered as a potential damage issue in tight reservoirs due to increasing the water saturation around wellbore region and eventually decreasing the relative permeability of hydrocarbons. Acid fracturing or hydraulic fracturing are required to remove the damage and enhance the formation conductivity. The objective of this paper is to propose a new technique to remove the water blockage from tight formations using thermochemical treatment. Chemicals that generate pressure and heat at reservoir conditions are used to remove the water bank from tight core samples. Coreflooding experiments, capillary pressure and NMR measurements were conducted as well as routine core analysis. The impact of thermochemical treatment on improving the formation productivity was quantified. The effect of thermochemical injection on rock integrity was analyzed by evaluating the pore geometry before and after the chemical treatment. Thermochemical treatment resulted in a significant improvement in the core conductivity. NMR indicated that, tiny fractures were created in the core samples due the thermochemical flooding. Capillary pressure measurements showed that, the capillary pressure was reduced by 55.6% after the chemical treatment. The results of this study highlight that water blockage is great challenge in tight gas reservoirs. Injecting thermochemical fluids into tight samples reduces the capillary forces significantly, which leads to remove the water accumulation. Therefore, considerable enhancement was observed in the rock conductivity. This study provides a novel approach for removing the water blockage from tight formations using environmentally friendly chemicals. Chemicals that generate heat and pressure at downhole conditions were used to create tiny fractures. This treatment was able to remove the water blockage from tight sandstone cores and improve the productivity index by reducing the capillary forces.
{"title":"Development of A New Chemical Treatment for Removing Water Blockage in Tight Reservoirs","authors":"Amjed Hassan, M. Mahmoud, Abdulaziz Al-Majed, O. Alade, A. Al-Nakhli, M. Bataweel, Salaheldin Elktatany","doi":"10.2118/194879-MS","DOIUrl":"https://doi.org/10.2118/194879-MS","url":null,"abstract":"\u0000 In petroleum industry, great challenges are associated with producing hydrocarbon from unconventional reservoirs. Tight reservoirs are characterized with low permeability which reduces the hydrocarbon flow into the wellbore. Water blockage is considered as a potential damage issue in tight reservoirs due to increasing the water saturation around wellbore region and eventually decreasing the relative permeability of hydrocarbons. Acid fracturing or hydraulic fracturing are required to remove the damage and enhance the formation conductivity. The objective of this paper is to propose a new technique to remove the water blockage from tight formations using thermochemical treatment. Chemicals that generate pressure and heat at reservoir conditions are used to remove the water bank from tight core samples.\u0000 Coreflooding experiments, capillary pressure and NMR measurements were conducted as well as routine core analysis. The impact of thermochemical treatment on improving the formation productivity was quantified. The effect of thermochemical injection on rock integrity was analyzed by evaluating the pore geometry before and after the chemical treatment. Thermochemical treatment resulted in a significant improvement in the core conductivity. NMR indicated that, tiny fractures were created in the core samples due the thermochemical flooding. Capillary pressure measurements showed that, the capillary pressure was reduced by 55.6% after the chemical treatment.\u0000 The results of this study highlight that water blockage is great challenge in tight gas reservoirs. Injecting thermochemical fluids into tight samples reduces the capillary forces significantly, which leads to remove the water accumulation. Therefore, considerable enhancement was observed in the rock conductivity. This study provides a novel approach for removing the water blockage from tight formations using environmentally friendly chemicals. Chemicals that generate heat and pressure at downhole conditions were used to create tiny fractures. This treatment was able to remove the water blockage from tight sandstone cores and improve the productivity index by reducing the capillary forces.","PeriodicalId":11031,"journal":{"name":"Day 4 Thu, March 21, 2019","volume":"29 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79612529","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}
Reinaldo Jose Angulo Yznaga, L. Quintero, Francisco J. Arevalo, Ehab Negm
This paper discusses an optimum approach to design and execution of a robust chemical enhanced oil recovery (EOR) surveillance program considering the physics and uncertainties involved during the implementation of a chemical EOR (CEOR) application at reservoir scale. The surveillance includes techniques, measuring points, and frequency of data acquisition. Based on field experience, a robust surveillance plan plays a key role in ensuring high performance of a CEOR application during implementation and execution at reservoir conditions. A proper surveillance program should focus on acquiring information associated with the main uncertainties related to fluid-fluid and rock-fluid interactions, the impact of reservoir heterogeneities at reservoir scale, fluid dynamics, and the composition and stability of the chemical formulation. The acquired information should be given to the CEOR modeling team to follow up, interpret, and adjust the CEOR process and reservoir model. Also, the information should be given to the reservoir operation team to tune up the CEOR injection and production process to help optimize performance. Typically, specialized literature focuses on describing CEOR formulation design and evaluation; laboratory requirements, experimental settings, and analysis results; field application design and implementation; and overall results of field applications. This work emphasizes CEOR process surveillance, its importance, and impact with respect to oilfield scale applications. There are multiple uncertainties regarding the physical parameters and phenomena that control the performance of the CEOR at reservoir scale (e.g., are uncertainties associated with fluid saturation and properties, rock-fluid interactions, reservoir heterogeneities, and alkali-surfactant-polymer (ASP) formulation behavior at reservoir conditions). A proper surveillance design and implementation help mitigate the impact of the mentioned uncertainties. Therefore, surveillance is paramount for the success of a CEOR application. The design and execution of a robust surveillance program should consider the main uncertainties associated with the CEOR formulation operating window, fluid-fluid and rock-fluid interactions, reservoir heterogeneities, reservoir conditions, injection-production environment, and various time scales for the timely use of the acquired information and the interpretation feedback to the CEOR modeling and operation teams. This work discusses the physics and uncertainties considered during the design and execution of an optimized surveillance program. A systematic approach is provided considering fluid-fluid and rock-fluid interactions, reservoir heterogeneities, CEOR formulation operating window, injection – production environment, and time scales to feedback the acquired and interpreted information during the surveillance program execution.
{"title":"Optimizing Surveillance: A Practice for a Successful Chemical EOR Oilfield Application","authors":"Reinaldo Jose Angulo Yznaga, L. Quintero, Francisco J. Arevalo, Ehab Negm","doi":"10.2118/195107-MS","DOIUrl":"https://doi.org/10.2118/195107-MS","url":null,"abstract":"\u0000 This paper discusses an optimum approach to design and execution of a robust chemical enhanced oil recovery (EOR) surveillance program considering the physics and uncertainties involved during the implementation of a chemical EOR (CEOR) application at reservoir scale. The surveillance includes techniques, measuring points, and frequency of data acquisition.\u0000 Based on field experience, a robust surveillance plan plays a key role in ensuring high performance of a CEOR application during implementation and execution at reservoir conditions. A proper surveillance program should focus on acquiring information associated with the main uncertainties related to fluid-fluid and rock-fluid interactions, the impact of reservoir heterogeneities at reservoir scale, fluid dynamics, and the composition and stability of the chemical formulation. The acquired information should be given to the CEOR modeling team to follow up, interpret, and adjust the CEOR process and reservoir model. Also, the information should be given to the reservoir operation team to tune up the CEOR injection and production process to help optimize performance.\u0000 Typically, specialized literature focuses on describing CEOR formulation design and evaluation; laboratory requirements, experimental settings, and analysis results; field application design and implementation; and overall results of field applications. This work emphasizes CEOR process surveillance, its importance, and impact with respect to oilfield scale applications.\u0000 There are multiple uncertainties regarding the physical parameters and phenomena that control the performance of the CEOR at reservoir scale (e.g., are uncertainties associated with fluid saturation and properties, rock-fluid interactions, reservoir heterogeneities, and alkali-surfactant-polymer (ASP) formulation behavior at reservoir conditions). A proper surveillance design and implementation help mitigate the impact of the mentioned uncertainties.\u0000 Therefore, surveillance is paramount for the success of a CEOR application. The design and execution of a robust surveillance program should consider the main uncertainties associated with the CEOR formulation operating window, fluid-fluid and rock-fluid interactions, reservoir heterogeneities, reservoir conditions, injection-production environment, and various time scales for the timely use of the acquired information and the interpretation feedback to the CEOR modeling and operation teams.\u0000 This work discusses the physics and uncertainties considered during the design and execution of an optimized surveillance program. A systematic approach is provided considering fluid-fluid and rock-fluid interactions, reservoir heterogeneities, CEOR formulation operating window, injection – production environment, and time scales to feedback the acquired and interpreted information during the surveillance program execution.","PeriodicalId":11031,"journal":{"name":"Day 4 Thu, March 21, 2019","volume":"66 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75923509","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}
Surfactants have been used in the oil industry for decades as multi-functions additive in stimulation fluids. In hydraulic fracturing, surfactants and microemulsions have been extensively reported numerously as flowback additives to lower surface and interfacial tension to aid water recovery. Fracturing fluids invade the matrix during the fracturing, and if not recovered, leads to water blockage and a reduction to relative permeability to gas or oil. This problem is more challenging in low- permeability formations since capillary forces have more profound impact on water retention, and hence water recovery and subsequent oil productivity. In this work, surface tension, interfacial tension, foam stability, sand-packed columns, and coreflood experiments were performed on a selected environmentally friendly water-based surfactant formulation. The performance of the surfactant of interest was compared to two commercial microemulsion and one non-ionic alcohol ethoxylated. The results confirmed the benefit of using surfactants for flowback compared to non-surfactant case. Surface tension (ST) alone cannot be used as a selecting criterion for flow back. The alcohol exthoxylated, while reducing the ST to same level as the two microemulsions, showed very poor performance in packed column and coreflood tests. Although interfacial tension (IFT) seems to be more reasonable criteria, adsorption and emulsion tendency are other challenges that can hinder the performance of good surfactants with low IFT. Based on the data, a surfactant that lowers the IFT with the selected oil to below 1 mN/m is more likely to outperform other surfactants with higher IFT.
{"title":"Evaluation of a New Environmentally Friendly Flowback Surfactant and Its Application to Enhance Oil and Gas Productivity","authors":"Ahmed I. Rabie, Jian Zhou, Q. Qu","doi":"10.2118/195045-MS","DOIUrl":"https://doi.org/10.2118/195045-MS","url":null,"abstract":"\u0000 Surfactants have been used in the oil industry for decades as multi-functions additive in stimulation fluids. In hydraulic fracturing, surfactants and microemulsions have been extensively reported numerously as flowback additives to lower surface and interfacial tension to aid water recovery. Fracturing fluids invade the matrix during the fracturing, and if not recovered, leads to water blockage and a reduction to relative permeability to gas or oil. This problem is more challenging in low- permeability formations since capillary forces have more profound impact on water retention, and hence water recovery and subsequent oil productivity.\u0000 In this work, surface tension, interfacial tension, foam stability, sand-packed columns, and coreflood experiments were performed on a selected environmentally friendly water-based surfactant formulation. The performance of the surfactant of interest was compared to two commercial microemulsion and one non-ionic alcohol ethoxylated.\u0000 The results confirmed the benefit of using surfactants for flowback compared to non-surfactant case. Surface tension (ST) alone cannot be used as a selecting criterion for flow back. The alcohol exthoxylated, while reducing the ST to same level as the two microemulsions, showed very poor performance in packed column and coreflood tests. Although interfacial tension (IFT) seems to be more reasonable criteria, adsorption and emulsion tendency are other challenges that can hinder the performance of good surfactants with low IFT. Based on the data, a surfactant that lowers the IFT with the selected oil to below 1 mN/m is more likely to outperform other surfactants with higher IFT.","PeriodicalId":11031,"journal":{"name":"Day 4 Thu, March 21, 2019","volume":"33 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75258922","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}
How to improve oil recovery for ultra-high water cut reservoir efficiently is a major technical problem needed to resolve in oilfield development at home and abroad. Currently, the water cut of reservoir and average oil recovery recovery factor have been as high as 95% and 56% after polymer flooding in Daqing Oilfeild, respectively, with 44% of the remaining geological reserves underground showing a great potential for further tapping. During the development of ultra-high water cut oilfield, we should consider reducing the investment cost of the new well drilling and stations so as to decrease cost and increase benefit. Specifically, we re-utilize the spare wells and injection distribution system of the injection stations after ASP flooding tests and significantly reduce investment cost. In this paper, we propose a new scheme of combining spare well station reusing and ASP flooding to further enhance oil recovery for the reservoir after polymer flooding. The field test, with 35 injection wells and 44 production wells, has been conducted in B2X block in Daqing Oilfield to reduce the cost of new drilling wells and new injection stations construction by 31.835 million dollars. By implementing physical simulation experiment to optimize the injection parameters and system formula, we determined that ASP formula for this test is to use polymer with 25 million molecular weight, petroleum sulfonate surfactant and sodium carbonate. The numerical simulation forecast shows that ASP flooding could further improve oil recovery by more than 10 percent. This test has been carried out and good response has been seen. The polymer pre-slug and the ASP main slug were injected in February and May 2015 respectively. Up to October 2017, the accumulated injection pore volume has been 0.61 PV, the injection pressure has risen by 4.2 MPa, the fluid absorption thickness ratio has increased by 31.4%, largest water cut decline of single well has reached 20.8% and the stage incremental oil recovery was 8.13%. Due to the reduced cost of no new drilling wells and no new injection station construction, the field test has achieved good technical and economic development effect. Now, the test area has increased oil by 1.161million barrels (158.9 thousand tons), with 58.07 million dollars economic returns. The prediction via numerical simulation shows that the final incremental oil recovery would be increased by 10.44%, the accumulated increasing oil production would be 1.491 million barrels (204 thousand tons), and the economic returns would be 74.57 million dollars (calculated as $50 per barrel). Through combing largely reducing the investment cost by reusing well station with ASP flooding, this field test achieved good technical and economic development effect. It can be broadly applied in ultra-high water cut blocks after polymer flooding in Daqing Oilfield.
{"title":"Enhanced Oil Recovery Test Based on Wells and Stations Utilization to Reduce Cost After Polymer Flooding","authors":"Shuling Gao, Shukai Peng, Peihui Han, Guo Chen, Haibo Liu, Wei Yan, E. Gao","doi":"10.2118/194752-MS","DOIUrl":"https://doi.org/10.2118/194752-MS","url":null,"abstract":"\u0000 How to improve oil recovery for ultra-high water cut reservoir efficiently is a major technical problem needed to resolve in oilfield development at home and abroad. Currently, the water cut of reservoir and average oil recovery recovery factor have been as high as 95% and 56% after polymer flooding in Daqing Oilfeild, respectively, with 44% of the remaining geological reserves underground showing a great potential for further tapping. During the development of ultra-high water cut oilfield, we should consider reducing the investment cost of the new well drilling and stations so as to decrease cost and increase benefit. Specifically, we re-utilize the spare wells and injection distribution system of the injection stations after ASP flooding tests and significantly reduce investment cost. In this paper, we propose a new scheme of combining spare well station reusing and ASP flooding to further enhance oil recovery for the reservoir after polymer flooding. The field test, with 35 injection wells and 44 production wells, has been conducted in B2X block in Daqing Oilfield to reduce the cost of new drilling wells and new injection stations construction by 31.835 million dollars. By implementing physical simulation experiment to optimize the injection parameters and system formula, we determined that ASP formula for this test is to use polymer with 25 million molecular weight, petroleum sulfonate surfactant and sodium carbonate. The numerical simulation forecast shows that ASP flooding could further improve oil recovery by more than 10 percent. This test has been carried out and good response has been seen. The polymer pre-slug and the ASP main slug were injected in February and May 2015 respectively. Up to October 2017, the accumulated injection pore volume has been 0.61 PV, the injection pressure has risen by 4.2 MPa, the fluid absorption thickness ratio has increased by 31.4%, largest water cut decline of single well has reached 20.8% and the stage incremental oil recovery was 8.13%. Due to the reduced cost of no new drilling wells and no new injection station construction, the field test has achieved good technical and economic development effect. Now, the test area has increased oil by 1.161million barrels (158.9 thousand tons), with 58.07 million dollars economic returns. The prediction via numerical simulation shows that the final incremental oil recovery would be increased by 10.44%, the accumulated increasing oil production would be 1.491 million barrels (204 thousand tons), and the economic returns would be 74.57 million dollars (calculated as $50 per barrel). Through combing largely reducing the investment cost by reusing well station with ASP flooding, this field test achieved good technical and economic development effect. It can be broadly applied in ultra-high water cut blocks after polymer flooding in Daqing Oilfield.","PeriodicalId":11031,"journal":{"name":"Day 4 Thu, March 21, 2019","volume":"44 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84235106","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
The Bahrain Oil Field is located in a desert environment in the south-central area of the Kingdom of Bahrain and spans approximately 25% of the island. The Bahrain Field was discovered in the early 1930s and is recognized as the first oil field developed in the Arabian Gulf. Recently, Tatweer Petroleum introduced advanced Unmanned Aerial Vehicles (UAV), also known as (Drones), to address the unique needs of its daily operation by providing a safe, efficient, and cost-effective maintenance and inspection solutions. This paper demonstrates the valuable benefits of utilizing UAV (Drones) in the oil and gas industry in three main areas: ‘Security, Surveillance, and Emergency Response,’ ‘Inspection and Maintenance,’ and ‘Surveying and Mapping.’ Under the Security and Surveillance front, Tatweer Petroleum is facing operational safety issues and security threats that require real-time response solutions, and the need to provide rapid, precise, and reliable situational awareness. Tatweer’s Drones support the Security team with dynamic perimeter surveillance, intruder alerts, and critical equipment and process monitoring. Additionally, the Drones are used to support the emergency response team as a professional tool for rapid aerial incident investigation, evacuation, monitoring, and remote hazard detection. Preventive maintenance inspection is another application area where Drones can play a vital role. This is especially true when it comes to inaccessible operational assets due to their physical location (e.g. overhead power lines insulators), sheer magnitude (e.g. solar cell farm), or an inherent process hazard (e.g. flare stacks). Airborne cameras with advanced spectral imaging technology and powerful magnification optics can capture, analyze, and identify particular anomalies such as oil or gas leaks and pre-failure overheats, and provide vivid close-up images of fatigued structures and micro failures in plants and assets. This is a great cost-effective and efficient method for inspection and failure prevention. Surveying and mapping an industrial environment is time-consuming, difficult, and often dangerous. Tatweer Petroleum used the Drones to allow surveyors and mappers to collect unlimited aerial data with precise measurements, while saving time, money, and manpower. It also provides premium processing and analytics capabilities to support critical processes such as stock pile volume measurements, terrain mapping, site planning etc. The Drones are preprogrammed to automatically cover any particular area in the Bahrain Field. The survey data produces highly accurate, best-in-class orthophotos and digital elevation models.
{"title":"Opeimizing Operation Oversight of Bahrain Field through Aerial Survey","authors":"Y. Nooraldeen, Hasan AlNoaimi","doi":"10.2118/195090-MS","DOIUrl":"https://doi.org/10.2118/195090-MS","url":null,"abstract":"\u0000 The Bahrain Oil Field is located in a desert environment in the south-central area of the Kingdom of Bahrain and spans approximately 25% of the island. The Bahrain Field was discovered in the early 1930s and is recognized as the first oil field developed in the Arabian Gulf.\u0000 Recently, Tatweer Petroleum introduced advanced Unmanned Aerial Vehicles (UAV), also known as (Drones), to address the unique needs of its daily operation by providing a safe, efficient, and cost-effective maintenance and inspection solutions.\u0000 This paper demonstrates the valuable benefits of utilizing UAV (Drones) in the oil and gas industry in three main areas: ‘Security, Surveillance, and Emergency Response,’ ‘Inspection and Maintenance,’ and ‘Surveying and Mapping.’\u0000 Under the Security and Surveillance front, Tatweer Petroleum is facing operational safety issues and security threats that require real-time response solutions, and the need to provide rapid, precise, and reliable situational awareness. Tatweer’s Drones support the Security team with dynamic perimeter surveillance, intruder alerts, and critical equipment and process monitoring. Additionally, the Drones are used to support the emergency response team as a professional tool for rapid aerial incident investigation, evacuation, monitoring, and remote hazard detection.\u0000 Preventive maintenance inspection is another application area where Drones can play a vital role. This is especially true when it comes to inaccessible operational assets due to their physical location (e.g. overhead power lines insulators), sheer magnitude (e.g. solar cell farm), or an inherent process hazard (e.g. flare stacks). Airborne cameras with advanced spectral imaging technology and powerful magnification optics can capture, analyze, and identify particular anomalies such as oil or gas leaks and pre-failure overheats, and provide vivid close-up images of fatigued structures and micro failures in plants and assets. This is a great cost-effective and efficient method for inspection and failure prevention.\u0000 Surveying and mapping an industrial environment is time-consuming, difficult, and often dangerous. Tatweer Petroleum used the Drones to allow surveyors and mappers to collect unlimited aerial data with precise measurements, while saving time, money, and manpower. It also provides premium processing and analytics capabilities to support critical processes such as stock pile volume measurements, terrain mapping, site planning etc. The Drones are preprogrammed to automatically cover any particular area in the Bahrain Field. The survey data produces highly accurate, best-in-class orthophotos and digital elevation models.","PeriodicalId":11031,"journal":{"name":"Day 4 Thu, March 21, 2019","volume":"54 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84589562","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}
Kamal Atriby, S. Alghofaili, Andrés Núñez, Mohammed Rayes, Ali AlNaji, Vitor Santos de Araujo, Raed Ghali
In the past decades, new innovations increased the efficiency and economic feasibility of Hydraulic fracturing in the United States. That has opened untapped unconventional shale gas reservoirs and turned the U.S. into one of the world’s largest gas producers. These results eventually led to a global increase in the popularity of Multi-Stage Fracturing (MSF) completion systems. In the middle east, this type of completion is now run in vertical and horizontal holes, with laterals extending up to 7000 ft and with a pressure over balance as high as 3000 psi. These laterals are typically drilled in deep conventional oil and gas reservoirs with significantly higher differential and mechanical sticking risks compared to the impermeable shale reservoirs. This has called for an integrated strategy that prevents and mitigates these catastrophic risks. Tackling these risks starts in the planning phase by evaluating the offset wells, formation characteristics, overbalance, stress direction the well is drilled in and the stress regime in the area. This is done through a comprehensive geomechanical study that produces a Mechanical Earth Model (MEM). Its results are used to reach an optimum design for the drilling fluid and bridging plan that balances the "stable mud window" with the risk of differential sticking. A completely new approach has been taken for entire completion phase of the well, with an emphasis on reducing the open hole exposure time and reducing formation fatigue caused by the fluctuations in downhole equivalent circulating density (ECD). Prior to deploying the Multi-Stage Fracturing (MSF) completion string, its final design is simulated with specific software for an optimized centralization plan that gives the best possible standoff. Finally, during the deployment of the completion string, the Torque and drag measure are taken and any signs of differential or mechanical sticking are dealt with before they evolve into a stuck pipe situation. This paper describes the whole integrated approach together with the results of the implementation carried out in several wells with different subsurface conditions, detailing the steps taken including the risk assessment and the recommendations implemented.
{"title":"Integrated Approach for Multi-Stage Fracturing MSF Completion Deployment in Deep Carbonate Reservoirs Improved Efficiency, Saved 2 Days Per Well With 100% Success Rate","authors":"Kamal Atriby, S. Alghofaili, Andrés Núñez, Mohammed Rayes, Ali AlNaji, Vitor Santos de Araujo, Raed Ghali","doi":"10.2118/194698-MS","DOIUrl":"https://doi.org/10.2118/194698-MS","url":null,"abstract":"\u0000 In the past decades, new innovations increased the efficiency and economic feasibility of Hydraulic fracturing in the United States. That has opened untapped unconventional shale gas reservoirs and turned the U.S. into one of the world’s largest gas producers. These results eventually led to a global increase in the popularity of Multi-Stage Fracturing (MSF) completion systems. In the middle east, this type of completion is now run in vertical and horizontal holes, with laterals extending up to 7000 ft and with a pressure over balance as high as 3000 psi. These laterals are typically drilled in deep conventional oil and gas reservoirs with significantly higher differential and mechanical sticking risks compared to the impermeable shale reservoirs. This has called for an integrated strategy that prevents and mitigates these catastrophic risks.\u0000 Tackling these risks starts in the planning phase by evaluating the offset wells, formation characteristics, overbalance, stress direction the well is drilled in and the stress regime in the area. This is done through a comprehensive geomechanical study that produces a Mechanical Earth Model (MEM). Its results are used to reach an optimum design for the drilling fluid and bridging plan that balances the \"stable mud window\" with the risk of differential sticking. A completely new approach has been taken for entire completion phase of the well, with an emphasis on reducing the open hole exposure time and reducing formation fatigue caused by the fluctuations in downhole equivalent circulating density (ECD). Prior to deploying the Multi-Stage Fracturing (MSF) completion string, its final design is simulated with specific software for an optimized centralization plan that gives the best possible standoff. Finally, during the deployment of the completion string, the Torque and drag measure are taken and any signs of differential or mechanical sticking are dealt with before they evolve into a stuck pipe situation.\u0000 This paper describes the whole integrated approach together with the results of the implementation carried out in several wells with different subsurface conditions, detailing the steps taken including the risk assessment and the recommendations implemented.","PeriodicalId":11031,"journal":{"name":"Day 4 Thu, March 21, 2019","volume":"36 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78301598","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}
Production data analysis (PDA) by using rate normalized pressure (RNP) and rate normalized pressure derivative (RNP’) is useful for transient rate and pressure analysis of shale gas wells with constant or smooth changing gas rate and pressure. However, some reasons may cause abrupt changes, fluctuation, or even loss of production data. The existing PDA methods can not well address this kind of issue. The paper analyzes the reasons that cause big changes of shale gas production rate and pressure. The reasons include well-interference, well shut-ins, and converting production from casing to tubing. Typical shale gas well cases in China are described. Three methods are proposed to address the non-smooth production data issue. For shale gas wells with severe well-interference from neighbouring fracturing wells or production wells, the segmented production data before well-interference is suggested as well-interference is like an imposed negative or positive force from outside, and this force disturbs the normal production performance only rely on the well's own energy. For wells with frequent shut-ins, a virtual equivalent time method is referenced. The process for this method firstly calculates the formation pressure distributions and the average formation pressures within the SRV area; sencondly, calculate the virtual equivalent time by use of the average formation pressure; thirdly, divided the whole production data into several interconnected segments by rearrange the vitual euivalent time into the actual time axis, and finally do the analysis by using the log-log plot of pressure and pressure derivate vs material balance time. For shale gas wells with converting production from casing to tubing, as there are abrupt rate and pressure changes at the converting point, the material balance time may be no more monotonically increasing with production time. We proposed the average material balance time method to solve this problem. For this method, we use average material balance time instead of the material balance time in the log-log plot of pressure and pressure derivative. Results shows that severe well-interference cause big disturblance and only data before well-interference is suggested for PDA. Both the PDA with average material balance time and PDA with virtual equivalent time can get much better match of production history and log-log plot of pressure and pressure derivative then the exsiting PDA method.
{"title":"Production Data Analysis of Shale Gas Wells with Abrupt Gas Rate or Pressure Changes","authors":"Pang Wei, Juan Du, Tongyi Zhang","doi":"10.2118/195134-MS","DOIUrl":"https://doi.org/10.2118/195134-MS","url":null,"abstract":"\u0000 Production data analysis (PDA) by using rate normalized pressure (RNP) and rate normalized pressure derivative (RNP’) is useful for transient rate and pressure analysis of shale gas wells with constant or smooth changing gas rate and pressure. However, some reasons may cause abrupt changes, fluctuation, or even loss of production data. The existing PDA methods can not well address this kind of issue.\u0000 The paper analyzes the reasons that cause big changes of shale gas production rate and pressure. The reasons include well-interference, well shut-ins, and converting production from casing to tubing. Typical shale gas well cases in China are described.\u0000 Three methods are proposed to address the non-smooth production data issue. For shale gas wells with severe well-interference from neighbouring fracturing wells or production wells, the segmented production data before well-interference is suggested as well-interference is like an imposed negative or positive force from outside, and this force disturbs the normal production performance only rely on the well's own energy. For wells with frequent shut-ins, a virtual equivalent time method is referenced. The process for this method firstly calculates the formation pressure distributions and the average formation pressures within the SRV area; sencondly, calculate the virtual equivalent time by use of the average formation pressure; thirdly, divided the whole production data into several interconnected segments by rearrange the vitual euivalent time into the actual time axis, and finally do the analysis by using the log-log plot of pressure and pressure derivate vs material balance time. For shale gas wells with converting production from casing to tubing, as there are abrupt rate and pressure changes at the converting point, the material balance time may be no more monotonically increasing with production time. We proposed the average material balance time method to solve this problem. For this method, we use average material balance time instead of the material balance time in the log-log plot of pressure and pressure derivative.\u0000 Results shows that severe well-interference cause big disturblance and only data before well-interference is suggested for PDA. Both the PDA with average material balance time and PDA with virtual equivalent time can get much better match of production history and log-log plot of pressure and pressure derivative then the exsiting PDA method.","PeriodicalId":11031,"journal":{"name":"Day 4 Thu, March 21, 2019","volume":"40 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79884320","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. Buenrostro, A. Harbi, Alfredo Arevalo, Jairo Carmona
Study made from the results observed over a particular application objective with one of the recently developed proppant fracturing techniques known as Channel Fracturing. This technique was used in this application to place a proppant fracturing treatment in a tight gas reservoir which pushes the installed well completion to reach its mechanical limit capabilities. Channel (or pillar) fracturing was applied in multiple cases with the intention to constrain the pressure increase commonly observed during a fracture job execution.
{"title":"Channel Fracturing Technology to Successfully Deploy Proppant Fracturing Stimulation Under Limited BHP Window for Completion Integrity","authors":"A. Buenrostro, A. Harbi, Alfredo Arevalo, Jairo Carmona","doi":"10.2118/195086-MS","DOIUrl":"https://doi.org/10.2118/195086-MS","url":null,"abstract":"\u0000 Study made from the results observed over a particular application objective with one of the recently developed proppant fracturing techniques known as Channel Fracturing. This technique was used in this application to place a proppant fracturing treatment in a tight gas reservoir which pushes the installed well completion to reach its mechanical limit capabilities. Channel (or pillar) fracturing was applied in multiple cases with the intention to constrain the pressure increase commonly observed during a fracture job execution.","PeriodicalId":11031,"journal":{"name":"Day 4 Thu, March 21, 2019","volume":"30 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"73254632","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
The use of water-based drilling fluids to drill shale formations causes wellbore stability problems as a result of the reaction of water with clay minerals. When it comes in contact with water, clay starts to react, swell and/or disperse leading to shale disintegration and sloughing. Consequently, tight hole might develop and/or higher solids loading in the wellbore might be experienced and, hence, the chance to get stuck pipe increases and the hole cleaning efficiency of drilling fluid decreases significantly. This paper describes the experimental work conducted on four shale samples to assess clay-fluid interactions and shale stabilization. After conducting mineralogical analysis using X-ray diffraction, shale inhibition tests including dispersion and swelling tests were carried out using de-ionized water, 5% potassium chloride brine and 5% Polyamines solution. The work has been extended to cover different pure clay samples: sodium montmorillonite, illite and illite smectite mixed layer. Cation exchange capacity results showed high reactivity in sodium montmorillonite and illite-smectite mixed layer as they are more willing to exchange cations and adsorb water at natural conditions. Similarly, shale samples with higher concentration of smectite and illite-smectite showed higher CEC values. Dispersion results showed that shale recovery percentages varied from 30.8% for shale sample dominated by kaolinite to 98.65% for those with low kaolinite content. For the high kaolinite sample, the recovery percentage jumped from 30.8% to 59% with potassium chloride and eventually to 85.5% when the polyamine solution was used. When the samples were tested in the swell meter, results showed higher swelling percentage values for those samples with higher smectite content followed by illite while two samples showed no potential swelling as they have low clay content of less than 15%.
{"title":"Experimental Investigation on Clay-Fluid Interactions for Enhanced Wellbore Stability","authors":"M. Al-Arfaj, Amanullah","doi":"10.2118/194813-MS","DOIUrl":"https://doi.org/10.2118/194813-MS","url":null,"abstract":"\u0000 The use of water-based drilling fluids to drill shale formations causes wellbore stability problems as a result of the reaction of water with clay minerals. When it comes in contact with water, clay starts to react, swell and/or disperse leading to shale disintegration and sloughing. Consequently, tight hole might develop and/or higher solids loading in the wellbore might be experienced and, hence, the chance to get stuck pipe increases and the hole cleaning efficiency of drilling fluid decreases significantly.\u0000 This paper describes the experimental work conducted on four shale samples to assess clay-fluid interactions and shale stabilization. After conducting mineralogical analysis using X-ray diffraction, shale inhibition tests including dispersion and swelling tests were carried out using de-ionized water, 5% potassium chloride brine and 5% Polyamines solution. The work has been extended to cover different pure clay samples: sodium montmorillonite, illite and illite smectite mixed layer.\u0000 Cation exchange capacity results showed high reactivity in sodium montmorillonite and illite-smectite mixed layer as they are more willing to exchange cations and adsorb water at natural conditions. Similarly, shale samples with higher concentration of smectite and illite-smectite showed higher CEC values. Dispersion results showed that shale recovery percentages varied from 30.8% for shale sample dominated by kaolinite to 98.65% for those with low kaolinite content. For the high kaolinite sample, the recovery percentage jumped from 30.8% to 59% with potassium chloride and eventually to 85.5% when the polyamine solution was used. When the samples were tested in the swell meter, results showed higher swelling percentage values for those samples with higher smectite content followed by illite while two samples showed no potential swelling as they have low clay content of less than 15%.","PeriodicalId":11031,"journal":{"name":"Day 4 Thu, March 21, 2019","volume":"394 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"79451546","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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