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}
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}
S. Hadidi, Hilal Yaarubi, U. Baaske, Sakharin Suwannathatsa, S. Farsi, L. Bazalgette, L. Hamdoun
The infill potential of one of the most complex fractured carbonate reservoirs in the Sultanate of Oman has been evaluated through the integration, visualization and analysis of different data sources. The field has been split into different simplified genetic geobodies which contain the culmination of facies changes that define rock quality, fluid fill, oil saturation distribution and fracture network, amongst other properties that affect fluid flow. The long production history of more than 45 years, along with the large number of logged long horizontal wells scattered around the field, were key enabler for the analytical methodology. Production data, coupled with resistivity logs in horizontal wells, viewed through time were the backbone of the analysis. Data analysis was achieved by combining these data in a single platform and performing the analysis at different slices of time. At each timeslice, different interpretations were inferred that explain the observed production behaviour and remaining oil saturation from the logged wells. The interpretations were narrowed down into a minimum number of realizations by combining interpretations from the same area gathered from different slices of time. The analysis has resulted in the identification of four genetic performance regions in the field. Each region approximates a primary depositional facies belt and has a general defined relative behaviour of initial wells potential, water-cut development, initial and remaining oil saturation and, most importantly, infill wells potential. The analysis has aided in narrowing the subsurface uncertainties and has given a promising explanation for the large variations in wells behaviour. Infill wells opportunities have been identified, selected and ranked relatively in each of the regions. The value of data analytics on large volumes of acquired information normally not used was demonstrated. Visualization of different data sources in one platform is a challenging task that usually stops engineers from experimenting. The team has found fit for purpose solutions to visualize different data sources through time. The shift of mind-set from uncertain complex models and evaluations into finding simple genetic performance regions of the reservoir was vital in unravelling infill potential.
{"title":"Beyond One-Dimensional Evaluations: The Search for Genetic Reservoir Regions through Time & Space","authors":"S. Hadidi, Hilal Yaarubi, U. Baaske, Sakharin Suwannathatsa, S. Farsi, L. Bazalgette, L. Hamdoun","doi":"10.2118/194844-MS","DOIUrl":"https://doi.org/10.2118/194844-MS","url":null,"abstract":"\u0000 The infill potential of one of the most complex fractured carbonate reservoirs in the Sultanate of Oman has been evaluated through the integration, visualization and analysis of different data sources. The field has been split into different simplified genetic geobodies which contain the culmination of facies changes that define rock quality, fluid fill, oil saturation distribution and fracture network, amongst other properties that affect fluid flow. The long production history of more than 45 years, along with the large number of logged long horizontal wells scattered around the field, were key enabler for the analytical methodology.\u0000 Production data, coupled with resistivity logs in horizontal wells, viewed through time were the backbone of the analysis. Data analysis was achieved by combining these data in a single platform and performing the analysis at different slices of time. At each timeslice, different interpretations were inferred that explain the observed production behaviour and remaining oil saturation from the logged wells. The interpretations were narrowed down into a minimum number of realizations by combining interpretations from the same area gathered from different slices of time.\u0000 The analysis has resulted in the identification of four genetic performance regions in the field. Each region approximates a primary depositional facies belt and has a general defined relative behaviour of initial wells potential, water-cut development, initial and remaining oil saturation and, most importantly, infill wells potential. The analysis has aided in narrowing the subsurface uncertainties and has given a promising explanation for the large variations in wells behaviour. Infill wells opportunities have been identified, selected and ranked relatively in each of the regions.\u0000 The value of data analytics on large volumes of acquired information normally not used was demonstrated. Visualization of different data sources in one platform is a challenging task that usually stops engineers from experimenting. The team has found fit for purpose solutions to visualize different data sources through time. The shift of mind-set from uncertain complex models and evaluations into finding simple genetic performance regions of the reservoir was vital in unravelling infill potential.","PeriodicalId":11031,"journal":{"name":"Day 4 Thu, March 21, 2019","volume":"13 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"83187946","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}
Maher Rahayyem, P. Mostaghimi, Yara A. Alzahid, Amalia Halim, Lucas Evangelista, R. Armstrong
Enzyme Enhanced Oil Recovery (EEOR) has recently been categorized as one of the most effective EOR mechanisms. Laboratory and field studies have reported up to 16% of incremental oil recovery rates. EEOR recovers oil mainly by two main mechanisms: lowering the interfacial tension between brine and oil and altering the wettability on rock grains to a more water-wet condition. Therefore, EEOR would promote mobilization of capillary-trapped oil after regular waterflooding. Since capillary-trapped oil resides at the micro-scale, it is essential to assess EEOR fluid-fluid interaction at that scale. To further investigate the ways in which these enzymes contribute to EOR, an experimental micro-scale approach was developed in which EEOR was analyzed using polydimethylsiloxane (PDMS) microfluidic devices. The PDMS microfluidics device was based on X-ray micro-CT images of a Bentheimer sandstone with resolution of 4.95 μm. We first compared the IFT reduction capabilities of one class of enzyme (Apollo GreenZyme ®) and a commercial surfactant (J13131) obtained from Shell Chemicals. For GreenZyme concentrations of 0.5, 1.5 and 2 wt%, the IFT values between GreenZyme solution and oil are 4.2, 0.7 and 0.6 mN/m, respectively. Whereas the IFT values for 0.5 wt% surfactant solutions and deionized water are 1.1 and 32 mN/m, respectively. We then compared the oil recovery of the two systems using the aforementioned sandstone PDMS microfluidics device. Recovery values up to 92% of oilwere obtained using GreenZyme. Surfactant and waterflooding on the same PDMS chips had recovery values of 86 and 80%, respectively. This study provides insights and direct visualization of the micro-scale oil recovery mechanisms of EEOR that can be used for design of effective EEOR flooding.
{"title":"Enzyme Enhanced Oil Recovery EEOR: A Microfluidics Approach","authors":"Maher Rahayyem, P. Mostaghimi, Yara A. Alzahid, Amalia Halim, Lucas Evangelista, R. Armstrong","doi":"10.2118/195116-MS","DOIUrl":"https://doi.org/10.2118/195116-MS","url":null,"abstract":"\u0000 Enzyme Enhanced Oil Recovery (EEOR) has recently been categorized as one of the most effective EOR mechanisms. Laboratory and field studies have reported up to 16% of incremental oil recovery rates. EEOR recovers oil mainly by two main mechanisms: lowering the interfacial tension between brine and oil and altering the wettability on rock grains to a more water-wet condition. Therefore, EEOR would promote mobilization of capillary-trapped oil after regular waterflooding. Since capillary-trapped oil resides at the micro-scale, it is essential to assess EEOR fluid-fluid interaction at that scale. To further investigate the ways in which these enzymes contribute to EOR, an experimental micro-scale approach was developed in which EEOR was analyzed using polydimethylsiloxane (PDMS) microfluidic devices. The PDMS microfluidics device was based on X-ray micro-CT images of a Bentheimer sandstone with resolution of 4.95 μm. We first compared the IFT reduction capabilities of one class of enzyme (Apollo GreenZyme ®) and a commercial surfactant (J13131) obtained from Shell Chemicals. For GreenZyme concentrations of 0.5, 1.5 and 2 wt%, the IFT values between GreenZyme solution and oil are 4.2, 0.7 and 0.6 mN/m, respectively. Whereas the IFT values for 0.5 wt% surfactant solutions and deionized water are 1.1 and 32 mN/m, respectively. We then compared the oil recovery of the two systems using the aforementioned sandstone PDMS microfluidics device. Recovery values up to 92% of oilwere obtained using GreenZyme. Surfactant and waterflooding on the same PDMS chips had recovery values of 86 and 80%, respectively. This study provides insights and direct visualization of the micro-scale oil recovery mechanisms of EEOR that can be used for design of effective EEOR flooding.","PeriodicalId":11031,"journal":{"name":"Day 4 Thu, March 21, 2019","volume":"172 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77344140","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}
Mohammed Murif Al Rubaii, Abdullah Yami, Eno Omini
Utilization of drilled wells operations’ records is required to perform improvement of performance to minimize drilling cost of planned drilling of new and re-entry wells (workover – wells). Many operators are always interested in finding optimum ways to save on drilling cost. Optimization of Rate of Penetration (ROP) has direct effects on cost reduction. Different Techniques were used to optimize ROP such as regression technique, multiple linear regression technique, neural network, artificial neural network methods, and basic reference of Bayesian networks. There are several factors that will limit application of ROP optimization models in different hole sections with high degree of accuracy. It is the authors’ opinion that modeling on smaller selected section with controlled parameters will give better optimization and validation. In this paper an empirical correlation of rate of penetration (ROP) is presented for a particular hole section. The data selected are from same hole size, formation type and mud type. It is based on monitoring and controlling simultaneously the applied weight on bit (WOB), drill-string's rotation (RPM), Torque (TRQ) and rig pump's flow rate (GPM). During this study will demonstrate the use of this empirical correlation to improve drilling in a hole section by more than 50%. The developed model also has high potential to be automated in real time operating environment to improve drilling performance.
{"title":"A Robust Correlation Improves Well Drilling Performance","authors":"Mohammed Murif Al Rubaii, Abdullah Yami, Eno Omini","doi":"10.2118/195062-MS","DOIUrl":"https://doi.org/10.2118/195062-MS","url":null,"abstract":"\u0000 Utilization of drilled wells operations’ records is required to perform improvement of performance to minimize drilling cost of planned drilling of new and re-entry wells (workover – wells). Many operators are always interested in finding optimum ways to save on drilling cost. Optimization of Rate of Penetration (ROP) has direct effects on cost reduction. Different Techniques were used to optimize ROP such as regression technique, multiple linear regression technique, neural network, artificial neural network methods, and basic reference of Bayesian networks. There are several factors that will limit application of ROP optimization models in different hole sections with high degree of accuracy. It is the authors’ opinion that modeling on smaller selected section with controlled parameters will give better optimization and validation. In this paper an empirical correlation of rate of penetration (ROP) is presented for a particular hole section. The data selected are from same hole size, formation type and mud type. It is based on monitoring and controlling simultaneously the applied weight on bit (WOB), drill-string's rotation (RPM), Torque (TRQ) and rig pump's flow rate (GPM). During this study will demonstrate the use of this empirical correlation to improve drilling in a hole section by more than 50%. The developed model also has high potential to be automated in real time operating environment to improve drilling performance.","PeriodicalId":11031,"journal":{"name":"Day 4 Thu, March 21, 2019","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2019-03-15","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90875820","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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