Thermal EOR projects are technically and economically challenging projects. Improving the geological understanding and implementing these geological concepts into the static model were key to increase the robustness of, not only the geological model but also of the dynamic simulation. The initial believe was that fine grained and mm scale laminated sediments act as vertical baffles for the steam distribution. The fine grained sands were low in permeability and the lamination were further reducing the vertical permeability. Grain size had the main impact on permeability and grain size was correlated with V-shale. Then, V-shale was used as a proxy for grain size and was integrated into a V-shale base porosity-permeability transformation. After modeling the baffles explicitly, it was shown that against the initial belief, the main control on fluid flow was not a patchy baffle distribution. Instead the reservoir was overall reduced in vertical permeability. A lager impact had the V-shale base poro-perm transform, predicting an order of magnitude permeability range for a given porosity. Reducing the impact of the facies also reduced overall the uncertainty and improved the predictive power of the models. This in turn, helped to take development decisions with much higher confidence.
{"title":"Integrated Geological Modeling for Higher Confidence Development Decisions, Sultanate of Oman","authors":"Bellmann Lars Hendrik","doi":"10.2118/193043-ms","DOIUrl":"https://doi.org/10.2118/193043-ms","url":null,"abstract":"\u0000 Thermal EOR projects are technically and economically challenging projects. Improving the geological understanding and implementing these geological concepts into the static model were key to increase the robustness of, not only the geological model but also of the dynamic simulation.\u0000 The initial believe was that fine grained and mm scale laminated sediments act as vertical baffles for the steam distribution. The fine grained sands were low in permeability and the lamination were further reducing the vertical permeability. Grain size had the main impact on permeability and grain size was correlated with V-shale. Then, V-shale was used as a proxy for grain size and was integrated into a V-shale base porosity-permeability transformation.\u0000 After modeling the baffles explicitly, it was shown that against the initial belief, the main control on fluid flow was not a patchy baffle distribution. Instead the reservoir was overall reduced in vertical permeability. A lager impact had the V-shale base poro-perm transform, predicting an order of magnitude permeability range for a given porosity. Reducing the impact of the facies also reduced overall the uncertainty and improved the predictive power of the models. This in turn, helped to take development decisions with much higher confidence.","PeriodicalId":11079,"journal":{"name":"Day 4 Thu, November 15, 2018","volume":"58 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"80511789","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 paper is continuation of our previous work published in the SPE-192896. This work illustrates horizontal well placement sensitivity analysis that was conducted on a complex Valanginian (Cretaceous) unsaturated oil carbonate reservoir with strong water drive. Existing producer wells are 80% horizontal and the remaining 20% are vertical to deviated producers. The production history is the approximately 20 years and currently a peripheral water injection is implemented, all injector wells are horizontals. The well placement is very challenging due to the presence of some thin high permeability streaks intervals with permeability value of up to 1 Darcy. Early water breakthrough encountered in the existing oil producers is a serious problem which results in lower recovery factor and costly lifting treatment. In addition, premature breakthrough would leave behind the potential oil accumulation. Therefore defining the optimum placement location of the producers is a crucial decision to be decided during well plan and field development. In this paper we applied novel approach for stochastically modeling complex carbonate reservoir lithofacies and properties distribution using a pre-defined High Resolution Sequence Stratigraphy (HRSS) model subzonation. The key static geological elements that must be well defined are HRSS framework, lithofacies architecture, and field wide rock properties. In this study, we apply integrated geosciences, geostatistical, and flow simulations to assess options for well placement. This new holistic approach has recently been successfully implemented in the studied field. The resulted geostatistical model was able to explain pressure depletion and production rate as shown in historical production data of the field. The resulting dynamic model will hence provide reliable production forecast and reservoirs development plan which will eventually allow accomplishing the mandate recovery target. Flow simulation was used to analyze the performance of the well considering horizontal the well azimuth, well inclination, wells length, wells position relative to the sequence stratigraphic zonation, and well position relative to the water contact. In addition, multi-scenarios of well placement were created to see the impact on the oil rate, plateau, and water breakthrough time. Some producers in the studied reservoirs have been drilled using the multidiscipline study recommendation. Actual property and rate derived from the newly drilled wells displayed a very reasonable match to the expected property from the model.
{"title":"Well Placement Assessment Using Sequence Stratigraphic Zonation in a Complex Carbonate Reservoir","authors":"A. Salahuddin, K. Khan, R. A. Ali, K. Hammadi","doi":"10.2118/193057-MS","DOIUrl":"https://doi.org/10.2118/193057-MS","url":null,"abstract":"\u0000 The paper is continuation of our previous work published in the SPE-192896. This work illustrates horizontal well placement sensitivity analysis that was conducted on a complex Valanginian (Cretaceous) unsaturated oil carbonate reservoir with strong water drive. Existing producer wells are 80% horizontal and the remaining 20% are vertical to deviated producers. The production history is the approximately 20 years and currently a peripheral water injection is implemented, all injector wells are horizontals. The well placement is very challenging due to the presence of some thin high permeability streaks intervals with permeability value of up to 1 Darcy. Early water breakthrough encountered in the existing oil producers is a serious problem which results in lower recovery factor and costly lifting treatment. In addition, premature breakthrough would leave behind the potential oil accumulation. Therefore defining the optimum placement location of the producers is a crucial decision to be decided during well plan and field development.\u0000 In this paper we applied novel approach for stochastically modeling complex carbonate reservoir lithofacies and properties distribution using a pre-defined High Resolution Sequence Stratigraphy (HRSS) model subzonation. The key static geological elements that must be well defined are HRSS framework, lithofacies architecture, and field wide rock properties. In this study, we apply integrated geosciences, geostatistical, and flow simulations to assess options for well placement.\u0000 This new holistic approach has recently been successfully implemented in the studied field. The resulted geostatistical model was able to explain pressure depletion and production rate as shown in historical production data of the field. The resulting dynamic model will hence provide reliable production forecast and reservoirs development plan which will eventually allow accomplishing the mandate recovery target.\u0000 Flow simulation was used to analyze the performance of the well considering horizontal the well azimuth, well inclination, wells length, wells position relative to the sequence stratigraphic zonation, and well position relative to the water contact. In addition, multi-scenarios of well placement were created to see the impact on the oil rate, plateau, and water breakthrough time. Some producers in the studied reservoirs have been drilled using the multidiscipline study recommendation. Actual property and rate derived from the newly drilled wells displayed a very reasonable match to the expected property from the model.","PeriodicalId":11079,"journal":{"name":"Day 4 Thu, November 15, 2018","volume":"1 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77299672","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 wet gas flowmeter based on field-proven flowmeters and flow computers has been developed. The flowmeter is engineered by integrating the well-established SmartCone meter, a Pitot tube meter and filed mounted Flow Computer technologies in one wet gas metering solution. This combination exploits the characteristics of these two flow metering elements in wet gas flowrate measurement; The Cone measurement in wet gas is characterized by its relatively large gas measurement over-read with increasing liquid-loading, whereas this has a significantly lower impact on the gas flowrate measured by the Pitot tube. The DynaCone wet gas flowmeter has been in development over the past several years with particular emphasis being placed on developing a flexible flowmeter for broad operating conditions and applications including high turndown ratio, minimal pressure loss, measurement quality diagnostic, and performance characterization in industry-recognized wet gas flow loop. The wet gas performance has been demonstrated at CEESI wet gas flow loop yielding gas flowrates better than ±3% in Type I wet gas range, and better than ±5% in Type II without the input of liquid flowrate to correct for over-reading. Furthermore, uncertainties better than 2% and 3% for Type I & II respectively can be achieved if periodic liquid flowrate information is available for input.
{"title":"A Cost-Effective Dual-Element Metering System for Wet Gas Flowrate Measurement","authors":"Sami Halilah, K. Mokhtari","doi":"10.2118/192865-MS","DOIUrl":"https://doi.org/10.2118/192865-MS","url":null,"abstract":"\u0000 A wet gas flowmeter based on field-proven flowmeters and flow computers has been developed. The flowmeter is engineered by integrating the well-established SmartCone meter, a Pitot tube meter and filed mounted Flow Computer technologies in one wet gas metering solution. This combination exploits the characteristics of these two flow metering elements in wet gas flowrate measurement; The Cone measurement in wet gas is characterized by its relatively large gas measurement over-read with increasing liquid-loading, whereas this has a significantly lower impact on the gas flowrate measured by the Pitot tube.\u0000 The DynaCone wet gas flowmeter has been in development over the past several years with particular emphasis being placed on developing a flexible flowmeter for broad operating conditions and applications including high turndown ratio, minimal pressure loss, measurement quality diagnostic, and performance characterization in industry-recognized wet gas flow loop.\u0000 The wet gas performance has been demonstrated at CEESI wet gas flow loop yielding gas flowrates better than ±3% in Type I wet gas range, and better than ±5% in Type II without the input of liquid flowrate to correct for over-reading. Furthermore, uncertainties better than 2% and 3% for Type I & II respectively can be achieved if periodic liquid flowrate information is available for input.","PeriodicalId":11079,"journal":{"name":"Day 4 Thu, November 15, 2018","volume":"65 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"86405853","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}
Zhixiang Cai, Hui Zhang, Jun Li, Jiadong Zheng, Qing Yu, Kerou Liu, Yongsheng Liu
The rate of penetration is very low during the development of unconventional gas resources such as tight gas and marine shale gas, owing to high rock hardness and strength as well as heterogeneities at all scales. To improve the efficiency and reduce costs of developing unconventional gas resources, this paper proposed a new technology to assist drilling, Pulsed Arc Plasma Shockwave Technology (PAPST). This technology converts electrical energy into mechanical energy to generate dynamic loads shockwave which can assist rock-breaking. Firstly, based on the fluid mechanics and bubble dynamics, the mechanism of shockwave generation was analyzed. Then, to verify the feasibility of PAPST technology, this paper conducted rock breaking experiment with shale samples from Longmaxi formation, China. Meanwhile, based on impact and damage mechanics, the mechanism of rock damage caused by dynamic load was analyzed. The results show that shale samples were destroyed and there were cracks and collapse pits on shale samples after the impact of shockwave. Therefore, the application of PAPST technology to assist drilling is feasible, and the greater the discharge energy, the higher the efficiency of rock failure. Through theoretical analysis, it is found that the radial cracks of rock are caused by the tangential tensile stress, which is caused by the shockwave impacting the rock. The secant cracks are caused by the resultant force of the three component forces: the tangential and radial components of the force on the rock particle caused by the shockwave and the radial tensile force generated by the reflection of stress wave at the rock-water interface. The collapse pits are most likely caused by stress concentration. For the first time, this paper proposed an idea of applying shockwave generated by PAPST to assist drilling for increasing the ROP in unconventional gas resources. And it also provided a theoretical basis for the application of PAPST in the field of oil drilling by analyzing the mechanism of shockwave generation in drilling fluids and the mechanism of rock breaking by shockwave.
{"title":"New Technology to Assist Drilling to Improve Drilling Rate in Unconventional Gas Resources: Pulsed Arc Plasma Shockwave Technology","authors":"Zhixiang Cai, Hui Zhang, Jun Li, Jiadong Zheng, Qing Yu, Kerou Liu, Yongsheng Liu","doi":"10.2118/193279-MS","DOIUrl":"https://doi.org/10.2118/193279-MS","url":null,"abstract":"\u0000 The rate of penetration is very low during the development of unconventional gas resources such as tight gas and marine shale gas, owing to high rock hardness and strength as well as heterogeneities at all scales. To improve the efficiency and reduce costs of developing unconventional gas resources, this paper proposed a new technology to assist drilling, Pulsed Arc Plasma Shockwave Technology (PAPST).\u0000 This technology converts electrical energy into mechanical energy to generate dynamic loads shockwave which can assist rock-breaking. Firstly, based on the fluid mechanics and bubble dynamics, the mechanism of shockwave generation was analyzed. Then, to verify the feasibility of PAPST technology, this paper conducted rock breaking experiment with shale samples from Longmaxi formation, China. Meanwhile, based on impact and damage mechanics, the mechanism of rock damage caused by dynamic load was analyzed.\u0000 The results show that shale samples were destroyed and there were cracks and collapse pits on shale samples after the impact of shockwave. Therefore, the application of PAPST technology to assist drilling is feasible, and the greater the discharge energy, the higher the efficiency of rock failure. Through theoretical analysis, it is found that the radial cracks of rock are caused by the tangential tensile stress, which is caused by the shockwave impacting the rock. The secant cracks are caused by the resultant force of the three component forces: the tangential and radial components of the force on the rock particle caused by the shockwave and the radial tensile force generated by the reflection of stress wave at the rock-water interface. The collapse pits are most likely caused by stress concentration.\u0000 For the first time, this paper proposed an idea of applying shockwave generated by PAPST to assist drilling for increasing the ROP in unconventional gas resources. And it also provided a theoretical basis for the application of PAPST in the field of oil drilling by analyzing the mechanism of shockwave generation in drilling fluids and the mechanism of rock breaking by shockwave.","PeriodicalId":11079,"journal":{"name":"Day 4 Thu, November 15, 2018","volume":"157 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"73738217","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}
Oily sludge is one of the main wastes produced during oilfield development. The composition of oily sludge is complex, resulting in difficult separation and high processing cost. The existing technologies such as landfill, microbiological deterioration, heat treatment and solvent extraction are difficult to meet the needs of oily sludge treatment. It is necessary to develop a highly efficient and cheap reutilization technology for oily sludge. For this reason, we have proposed to recycle the oily sludge which can be utilized to profile control in water injection and thermal recovery wells. In the process of research, we have developed five aspects of work: First, three-phase separation of oily sludge was carried out by distillation, and water quality, oil-phase composition and solid particle size were analyzed. The compatibility of oily sludge and oil reservoir was investigated. Second, the mechanism and influence factors of the oily sludge for profile control were studied by long core model test and microscope observation. Third, suspension analysis and mobility analysis were developed on oily sludge, and experimental results were used to research oily sludge profile control agent. Fourth, numerical simulation was used to optimize the engineering design of Oily Sludge Profile Control (OSPC). Fifth, ground process flow of oily sludge for profile control was designed. The following conclusion can be drawn from the study: OSPC is a Reutilization Technology for oily sludge, which could seal up oily sludge in-situ in oil reservoir and be favorable for increasing production of oil wells through profile control. Through the rheology and plugging test, it was clear that OSPC could greatly reduce the pollution risk of oily sludge and the ground treatment cost, and solid phase and oil phase of mud were retained in the formation. It could plug high permeability channels and high permeability area (the plugging rate was more than 90%) to adjust water/steam injection profile of water/thermal recovery wells. Profile control agent, engineering design method and ground process flow for oily sludge were developed. The technology applied 72 wells in the oilfield, 184 thousand tons of oily sludge were used in total, production of crude oil was increased by 84 thousand barrels, and a lot of sludge treatment costs could be saved.
{"title":"Feasibility Analysis and Field Application of Waste Oily Sludge Resource Utilization Technology in Oilfield","authors":"Yao Wang, Wang Siwen, Rui Li, Hao Wang","doi":"10.2118/192895-MS","DOIUrl":"https://doi.org/10.2118/192895-MS","url":null,"abstract":"\u0000 Oily sludge is one of the main wastes produced during oilfield development. The composition of oily sludge is complex, resulting in difficult separation and high processing cost. The existing technologies such as landfill, microbiological deterioration, heat treatment and solvent extraction are difficult to meet the needs of oily sludge treatment. It is necessary to develop a highly efficient and cheap reutilization technology for oily sludge. For this reason, we have proposed to recycle the oily sludge which can be utilized to profile control in water injection and thermal recovery wells.\u0000 In the process of research, we have developed five aspects of work: First, three-phase separation of oily sludge was carried out by distillation, and water quality, oil-phase composition and solid particle size were analyzed. The compatibility of oily sludge and oil reservoir was investigated. Second, the mechanism and influence factors of the oily sludge for profile control were studied by long core model test and microscope observation. Third, suspension analysis and mobility analysis were developed on oily sludge, and experimental results were used to research oily sludge profile control agent. Fourth, numerical simulation was used to optimize the engineering design of Oily Sludge Profile Control (OSPC). Fifth, ground process flow of oily sludge for profile control was designed.\u0000 The following conclusion can be drawn from the study: OSPC is a Reutilization Technology for oily sludge, which could seal up oily sludge in-situ in oil reservoir and be favorable for increasing production of oil wells through profile control. Through the rheology and plugging test, it was clear that OSPC could greatly reduce the pollution risk of oily sludge and the ground treatment cost, and solid phase and oil phase of mud were retained in the formation. It could plug high permeability channels and high permeability area (the plugging rate was more than 90%) to adjust water/steam injection profile of water/thermal recovery wells. Profile control agent, engineering design method and ground process flow for oily sludge were developed. The technology applied 72 wells in the oilfield, 184 thousand tons of oily sludge were used in total, production of crude oil was increased by 84 thousand barrels, and a lot of sludge treatment costs could be saved.","PeriodicalId":11079,"journal":{"name":"Day 4 Thu, November 15, 2018","volume":"40 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74026775","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. Hamid, A. K. Al-Mulhim, Abdullah A. Al-Ghamdi, V. Unnikrishnan, U. Ahmed
Conventional Coiled tubing well intervention has been carried out in oil and gas wells for more than 30 years with not real-time data acquisition. With the advent of Coiled Tubing Telemetry (CTT) e-line/fiber optics/mono conductors in coiled tubing industry, a wide variety of opportunities has become available - downhole video camera (DVC) being one of them, to go beyond the conventional parameters and optimize the well intervention operation. DVC is used in the oil and gas industry with high success rate reported by several operating companies and service companies around the world. Video cameras have mostly been deployed using e-line; however, Coiled tubing camera runs provide the ability to clean the wellbore (by pumping fresh water or solvent) for capturing clearer, crisper videos and images. As the oil and gas industry is moving towards improving operating efficiency, minimizing the coiled tubing runs based on actual downhole data is of utmost importance. Therefore, having the ability to inspect downhole obstructions using the video camera, and to observe the downhole conditions is phenomenal. In this paper, the well intervention performed on multiple oil and gas wells in Middle East shall be discussed. Whenever an obstruction is encountered in the well bore, the primary form of detecting it is to run a lead impression block (LIB) on slickline or e-line. In most cases the LIB results do not provide a clear indication of the anomaly or obstruction. Not only that it sometimes adds to further confusion leading to inappropriate job design and planning, which results in potential misruns, inaccurate tool selection resulting in extensive and costly operations. This paper aims to highlight the unique integration of DVC and telecoil application to enhance the reliability of data acquisition and job success. The custom designed downhole camera shroud, along with the robust CTT system is deployed in each of the candidate wells. The camera chosen is designed to withstand the maximum anticipated downhole temperature. All the camera runs were analyzed and the obstruction in the wells was determined, which enabled the team of engineers to decide on the appropriate real-time course of action to gain access into the well bore or detect functionality of downhole jewelry.
{"title":"Improved Decision Making for Coiled Tubing Well Intervention With Downhole Video Camera DVC","authors":"S. Hamid, A. K. Al-Mulhim, Abdullah A. Al-Ghamdi, V. Unnikrishnan, U. Ahmed","doi":"10.2118/192695-MS","DOIUrl":"https://doi.org/10.2118/192695-MS","url":null,"abstract":"\u0000 Conventional Coiled tubing well intervention has been carried out in oil and gas wells for more than 30 years with not real-time data acquisition. With the advent of Coiled Tubing Telemetry (CTT) e-line/fiber optics/mono conductors in coiled tubing industry, a wide variety of opportunities has become available - downhole video camera (DVC) being one of them, to go beyond the conventional parameters and optimize the well intervention operation.\u0000 DVC is used in the oil and gas industry with high success rate reported by several operating companies and service companies around the world. Video cameras have mostly been deployed using e-line; however, Coiled tubing camera runs provide the ability to clean the wellbore (by pumping fresh water or solvent) for capturing clearer, crisper videos and images.\u0000 As the oil and gas industry is moving towards improving operating efficiency, minimizing the coiled tubing runs based on actual downhole data is of utmost importance. Therefore, having the ability to inspect downhole obstructions using the video camera, and to observe the downhole conditions is phenomenal.\u0000 In this paper, the well intervention performed on multiple oil and gas wells in Middle East shall be discussed. Whenever an obstruction is encountered in the well bore, the primary form of detecting it is to run a lead impression block (LIB) on slickline or e-line. In most cases the LIB results do not provide a clear indication of the anomaly or obstruction. Not only that it sometimes adds to further confusion leading to inappropriate job design and planning, which results in potential misruns, inaccurate tool selection resulting in extensive and costly operations.\u0000 This paper aims to highlight the unique integration of DVC and telecoil application to enhance the reliability of data acquisition and job success. The custom designed downhole camera shroud, along with the robust CTT system is deployed in each of the candidate wells. The camera chosen is designed to withstand the maximum anticipated downhole temperature.\u0000 All the camera runs were analyzed and the obstruction in the wells was determined, which enabled the team of engineers to decide on the appropriate real-time course of action to gain access into the well bore or detect functionality of downhole jewelry.","PeriodicalId":11079,"journal":{"name":"Day 4 Thu, November 15, 2018","volume":"49 3 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"89726690","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}
Suhaib Ghatrifi, Ghadna Sulaimi, Maria Jimenez Chavez, Ayca Sivrikoz
Water Shut-Off (WSO) actions are remedial activities that are being implemented in the heavy oil N Field, with the objective of reducing the water inflow of the well by closing zones which are major contributor to the high water cut. WSO are commonly executed as a mitigation action in operating wells with previous economic value. The purpose of this study is to develop a thorough knowledge of the rate of success of WSO activities linked to the time of WSO implementation, type of well (either horizontal or vertical) and the presence or lack of PLT (Production Log Test). Success was evaluated by reviewing the net oil production rate before and after WSO activity with the gained net oil rate being converted to US Dollars. There is no significant difference found in the success ratios between horizontal wells and verticals. However, in the horizontal wells, 74% of the successful ones were the heel shut-offs. WSO activities are found to have a success rate of 100% if the activity is implemented within the first year of the start of high water cut. Moreover, wells with WSO implementation within the first three years of observing high water-cut have a success rate of 65%. Noticeably, the success rate decreased dramatically with time, with wells having high water-cut for seven years and up to eleven years to the time of WSO implementation. These wells show success rates of 50% and 33% for seven and eleven years respectively. A numerical sector model and well model were created to explain these findings. During oil production because of a localized decrease in pressure, the water-oil interface may rise up and deform into a conical shape near the well. This phenomenon is known as ‘water coning’. At the time of water breakthrough, the cone is observed to be narrower than more advanced stages when the water cut has risen to higher levels. At these times, the cone has broadened and, depending on spacing between adjacent wells, has lifted the overall level of the oil/water interface, decreasing the distance between the wellbore and the water. As a result, water shutoff becomes less effective with time. It is recommended to start WSO activities on wells within the first three years of high water-cut indications. In case there is no PLT or other data, heel shutoff for the horizontal wells have a better success rate.
{"title":"Oil Gain from Successful Water Shut-Off Strategy","authors":"Suhaib Ghatrifi, Ghadna Sulaimi, Maria Jimenez Chavez, Ayca Sivrikoz","doi":"10.2118/193245-MS","DOIUrl":"https://doi.org/10.2118/193245-MS","url":null,"abstract":"\u0000 Water Shut-Off (WSO) actions are remedial activities that are being implemented in the heavy oil N Field, with the objective of reducing the water inflow of the well by closing zones which are major contributor to the high water cut. WSO are commonly executed as a mitigation action in operating wells with previous economic value. The purpose of this study is to develop a thorough knowledge of the rate of success of WSO activities linked to the time of WSO implementation, type of well (either horizontal or vertical) and the presence or lack of PLT (Production Log Test).\u0000 Success was evaluated by reviewing the net oil production rate before and after WSO activity with the gained net oil rate being converted to US Dollars.\u0000 There is no significant difference found in the success ratios between horizontal wells and verticals. However, in the horizontal wells, 74% of the successful ones were the heel shut-offs. WSO activities are found to have a success rate of 100% if the activity is implemented within the first year of the start of high water cut. Moreover, wells with WSO implementation within the first three years of observing high water-cut have a success rate of 65%. Noticeably, the success rate decreased dramatically with time, with wells having high water-cut for seven years and up to eleven years to the time of WSO implementation. These wells show success rates of 50% and 33% for seven and eleven years respectively.\u0000 A numerical sector model and well model were created to explain these findings. During oil production because of a localized decrease in pressure, the water-oil interface may rise up and deform into a conical shape near the well. This phenomenon is known as ‘water coning’. At the time of water breakthrough, the cone is observed to be narrower than more advanced stages when the water cut has risen to higher levels. At these times, the cone has broadened and, depending on spacing between adjacent wells, has lifted the overall level of the oil/water interface, decreasing the distance between the wellbore and the water. As a result, water shutoff becomes less effective with time.\u0000 It is recommended to start WSO activities on wells within the first three years of high water-cut indications. In case there is no PLT or other data, heel shutoff for the horizontal wells have a better success rate.","PeriodicalId":11079,"journal":{"name":"Day 4 Thu, November 15, 2018","volume":"47 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74697003","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}
To counter the consequences of the wellbore instability problems, a thorough analysis of the borehole conditions is performed throughout the entire life-cycle of a hydrocarbon well from planning during the early stages to completion and production. The analysis comprises the following: first, a rigorous understanding of the rock properties e.g. geochemistry and geomechanics mainly the stress magnitudes and rock strength. Second, the mud properties and the entailed interactions with the formation. For instance, numerous borehole failures in laminated rocks have been attributed to the interaction of the drilling/fracturing fluid with the layered-matrix e.g. interaction of water-based-mud with reactive clay minerals. This paper focuses on the impacts of the pore fluids redistribution on wellbore stability in organic rich carbonate rocks. The experimental method consisted of measuring the Nuclear-Magnetic-Resonance transverse relaxation time (NMR T2) on samples saturated by spontaneous imbibition of oil and brine. The wellbore stability was investigated by analyzing the changes in the NMR T2 distribution of each sample after imbibition sequences. The obtained results demonstrated the elevated impacts the wettability and pore structure characteristics on the spatial distribution of the fluids in these rocks. The type of clay content in the bedding planes and its consequent interaction with the drilling mud was identified as a potential driver of the rock instability problems. The discrepancies in the wetting traits were magnified by the presence of fractures that enhanced the network connectivity of both hydrophobic and hydrophilic pores or even across them. Furthermore, the fractures allowed the fluids to surpass the vertical bedding planes and thus accelerating the fluid distribution processes inside the pore space.
{"title":"A Comprehensive Study of Wellbore Stability in Laminated Carbonate Rocks by Nuclear Magnetic Resonance Experiments","authors":"H. Kesserwan, Ji Guodong","doi":"10.2118/192871-MS","DOIUrl":"https://doi.org/10.2118/192871-MS","url":null,"abstract":"\u0000 To counter the consequences of the wellbore instability problems, a thorough analysis of the borehole conditions is performed throughout the entire life-cycle of a hydrocarbon well from planning during the early stages to completion and production. The analysis comprises the following: first, a rigorous understanding of the rock properties e.g. geochemistry and geomechanics mainly the stress magnitudes and rock strength. Second, the mud properties and the entailed interactions with the formation. For instance, numerous borehole failures in laminated rocks have been attributed to the interaction of the drilling/fracturing fluid with the layered-matrix e.g. interaction of water-based-mud with reactive clay minerals.\u0000 This paper focuses on the impacts of the pore fluids redistribution on wellbore stability in organic rich carbonate rocks. The experimental method consisted of measuring the Nuclear-Magnetic-Resonance transverse relaxation time (NMR T2) on samples saturated by spontaneous imbibition of oil and brine. The wellbore stability was investigated by analyzing the changes in the NMR T2 distribution of each sample after imbibition sequences. The obtained results demonstrated the elevated impacts the wettability and pore structure characteristics on the spatial distribution of the fluids in these rocks. The type of clay content in the bedding planes and its consequent interaction with the drilling mud was identified as a potential driver of the rock instability problems. The discrepancies in the wetting traits were magnified by the presence of fractures that enhanced the network connectivity of both hydrophobic and hydrophilic pores or even across them. Furthermore, the fractures allowed the fluids to surpass the vertical bedding planes and thus accelerating the fluid distribution processes inside the pore space.","PeriodicalId":11079,"journal":{"name":"Day 4 Thu, November 15, 2018","volume":"119 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"73701678","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}
Bathmanaaban Gopalan, S. Craig, See Yung Jonathan Chong, Cherif Bouzaine, P. Pouget
A six wells campaign to single-run perforate long completion intervals was undertaken in Brunei. The offshore field presented inherent challenges due to high pressure, temperature and long perforating intervals. A major challenge was to perforate underbalance to reduce potential permanent formation damage. The solution proposed for this high pressure and high temperature (HPHT) perforation was to use a high grade of coiled tubing (CT) with live-well gun deployment and retrieval system. The live-well gun deployment system utilizes perforating connections designed to support the gun weight, firing shock loads and ballistic transfer. The connection and break-out are facilitated via specialized rams in a dedicated BOP body in live well conditions. A 130-ksi yield strength CT string was engineered to withstand high tensile forces from running up to 1,150-ft of guns to depths of 18,000-ft in near vertical wells and provide a suitable safety margin when high collapse pressures were present. However, when perforating with long gun lengths, high dynamic shock loads will be experienced by the CT string. Thus, for all the wells, two software systems were used, traditional CT force analysis program and a gun force software for the short duration transients present during perforating. There were numerous continual improvements implemented during the duration of the campaign and one of them was maximizing the underbalance perforation up to 5,500-psi. Although such high underbalance was not a standard practice in the industry with CT, it was carried out after a comprehensive study and review to perform the operation safely and efficiently. There were no recordable safety issue throughout the two years campaign where more than 6,230-ft of guns were ran and live-well reverse deployed. The campaign was successful and operator expectations met. This paper outlines the characteristics of this campaign from the planning stage up to operational execution and efficiencies recorded over the six wells campaign. Well control mitigation practices and general contingencies will be detailed. This paper will act as a suitable reference for future operations.
{"title":"Successfully Deploying & Retrieving 6,200ft of Perforating Guns Over Six Challenging HPHT Wells","authors":"Bathmanaaban Gopalan, S. Craig, See Yung Jonathan Chong, Cherif Bouzaine, P. Pouget","doi":"10.2118/192933-MS","DOIUrl":"https://doi.org/10.2118/192933-MS","url":null,"abstract":"\u0000 A six wells campaign to single-run perforate long completion intervals was undertaken in Brunei. The offshore field presented inherent challenges due to high pressure, temperature and long perforating intervals. A major challenge was to perforate underbalance to reduce potential permanent formation damage. The solution proposed for this high pressure and high temperature (HPHT) perforation was to use a high grade of coiled tubing (CT) with live-well gun deployment and retrieval system. The live-well gun deployment system utilizes perforating connections designed to support the gun weight, firing shock loads and ballistic transfer. The connection and break-out are facilitated via specialized rams in a dedicated BOP body in live well conditions. A 130-ksi yield strength CT string was engineered to withstand high tensile forces from running up to 1,150-ft of guns to depths of 18,000-ft in near vertical wells and provide a suitable safety margin when high collapse pressures were present. However, when perforating with long gun lengths, high dynamic shock loads will be experienced by the CT string. Thus, for all the wells, two software systems were used, traditional CT force analysis program and a gun force software for the short duration transients present during perforating. There were numerous continual improvements implemented during the duration of the campaign and one of them was maximizing the underbalance perforation up to 5,500-psi. Although such high underbalance was not a standard practice in the industry with CT, it was carried out after a comprehensive study and review to perform the operation safely and efficiently. There were no recordable safety issue throughout the two years campaign where more than 6,230-ft of guns were ran and live-well reverse deployed. The campaign was successful and operator expectations met. This paper outlines the characteristics of this campaign from the planning stage up to operational execution and efficiencies recorded over the six wells campaign. Well control mitigation practices and general contingencies will be detailed. This paper will act as a suitable reference for future operations.","PeriodicalId":11079,"journal":{"name":"Day 4 Thu, November 15, 2018","volume":"54 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"77862761","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
M. Nakatsukasa, H. Ban, A. Kato, N. Shimoda, D. White, E. Nickel, T. Daley
Seimic reservoir monitoring is a method to monitor fluid displacement in the reservoir. Long-term monitoring to measure differences over several years has been successful recently. However, short-term monitoring to measure changes in nearly real-time is still challenging because the expected changes in such a short-term are small. Permanent reservoir monitoring might enable short-term monitoring because we can increase data repeatability since sources and receivers are permanently fixed at the same position. This method saves the acquisition cost once the equipment is deployed, but the number of sources and receivers is limited due to the high initial install cost. To address this challenge, we have demonstrated VSP monitoring with a combination of a permanent rotary source and DAS sensor. DAS can record a wavefield at very dense and extensive points along an optical fiber, but the quality is regarded as less than for conventional geophones. By comparing data recorded in 2015 and 2016, we investigated the improvement of the signal-to-noise ratio of DAS. Hourly repeatability was checked by arranging the waveforms by the acquisition time. The depth migrated image of the offset VSP extended the imaging are further away from the receiver well. Our study confirmed the complementary relationship between the permanent source and DAS acquisition. Combining these technologies might enable us to monitor small changes in the reservoir in the short-term.
{"title":"Combined use of Optical-fiber DAS and a Permanent Seismic Source for Vertical Seismic Profiling Demonstrated at the Aquistore CO2 Storage Site","authors":"M. Nakatsukasa, H. Ban, A. Kato, N. Shimoda, D. White, E. Nickel, T. Daley","doi":"10.2118/193268-MS","DOIUrl":"https://doi.org/10.2118/193268-MS","url":null,"abstract":"\u0000 Seimic reservoir monitoring is a method to monitor fluid displacement in the reservoir. Long-term monitoring to measure differences over several years has been successful recently. However, short-term monitoring to measure changes in nearly real-time is still challenging because the expected changes in such a short-term are small. Permanent reservoir monitoring might enable short-term monitoring because we can increase data repeatability since sources and receivers are permanently fixed at the same position. This method saves the acquisition cost once the equipment is deployed, but the number of sources and receivers is limited due to the high initial install cost. To address this challenge, we have demonstrated VSP monitoring with a combination of a permanent rotary source and DAS sensor. DAS can record a wavefield at very dense and extensive points along an optical fiber, but the quality is regarded as less than for conventional geophones. By comparing data recorded in 2015 and 2016, we investigated the improvement of the signal-to-noise ratio of DAS. Hourly repeatability was checked by arranging the waveforms by the acquisition time. The depth migrated image of the offset VSP extended the imaging are further away from the receiver well. Our study confirmed the complementary relationship between the permanent source and DAS acquisition. Combining these technologies might enable us to monitor small changes in the reservoir in the short-term.","PeriodicalId":11079,"journal":{"name":"Day 4 Thu, November 15, 2018","volume":"28 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-11-12","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"82112942","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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