Tariq Mohammed, A. Ghanizadeh, C. Clarkson, Zhengru Yang
Calibration of reservoir models for unconventional hydrocarbon reservoirs requires permeability data as input. Accurate permeability prediction from velocity data is desirable due to the relative abundance of velocity data that is typically available during exploration and development programs (e.g., through seismic imaging and well logging). Therefore, the development of fast and inexpensive ‘screening’ techniques tha can provide reliable estimation of permeability at high-resolution (cm-scale) using velocity data could be valuable to exploration/development programs in unconventional reservoirs. A new experimental apparatus is described herein for measuring ultrasonic velocities (P- and S-wave) along the length of slabbed cores of low-permeability rocks at high-resolution (cm-scale). A statistical approach that combines along-core (profile) ultrasonic velocity testing and non-destructive experimental techniques (X-ray fluorescence, mechanical hardness, and profile permeability) is employed to develop predictive models for estimating permeability. Two slabbed cores from the Canadian Montney and Bakken formations, covering multiple geological intervals (tight siltstones/sandstones units), were analyzed for validation purposes. Reasonable agreement is found between log- and lab-derived (ultra)sonic velocity data, indicating similar trends with depth. However, the exact log- and lab-derived (ultra)sonic velocity values are different due to the differences in stress conditions between the field and laboratory measurements and the direction of wave travel. A maximum variation of ±20 m/s is observed for both P- and S-wave velocities when measurements were repeated on the same points, providing evidence of experimental repeatability and reproducibility. Relationships exist between laboratory-measured profile ultrasonic velocities (S-wave), profile permeability, mechanical hardness, and clay content (inferred from elemental composition data). The profile S-wave velocities decrease with increasing permeability (R2 = 0.6, n = 230). Advanced statistical methods (e.g., genetic algorithms) are employed to improve the velocity-permeability relationship and develop models for indirect estimation of permeability from S-wave velocities. The performance of these models is dependent upon lithology and rock fabric (e.g., silt vs. sand, degree of cementation), with a better correlation achieved for intervals with lower porosity and permeability (<±15% maximum discrepancy between measured and predicted permeability values; R2 = 0.78, n = 230). This study introduces a new experimental apparatus, and a practical ‘screening’ workflow, that can be used for permeability prediction using S-wave velocities collected on slabbed cores. This predictive model can be used to estimate permeability below the lower limit (0.001 md) of pressure-decay profile permeability measurements. The findings are beneficial to operators developing tight siltstone/sandstone resources by all
非常规油气储层模型的标定需要渗透率数据作为输入。由于在勘探和开发计划中(例如，通过地震成像和测井)通常可以获得相对丰富的速度数据，因此需要通过速度数据进行准确的渗透率预测。因此，开发快速、廉价的“筛选”技术，利用速度数据在高分辨率(厘米尺度)上提供可靠的渗透率估计，对于非常规油藏的勘探/开发计划来说是有价值的。本文描述了一种新的实验装置，用于高分辨率(厘米尺度)测量低渗透岩石板状岩心沿长度的超声波速度(P波和s波)。采用沿岩心(剖面)超声速度测试和非破坏性实验技术(x射线荧光、机械硬度和剖面渗透率)相结合的统计方法，建立渗透率预测模型。为了验证目的，研究人员对加拿大Montney和Bakken地层的两个板状岩心进行了分析，涵盖了多个地质层段(致密粉砂岩/砂岩单元)。测井和实验室得到的(超)声速数据基本一致，随深度变化趋势相似。然而，由于现场和实验室测量的应力条件以及波传播方向的差异，精确的测井和实验室推导的(超)声速值是不同的。当在同一点上重复测量时，观察到P波和s波速度的最大变化为±20 m/s，提供了实验可重复性和再现性的证据。实验室测量的剖面超声速度(s波)、剖面渗透率、机械硬度和粘土含量(从元素组成数据推断)之间存在关系。剖面横波速度随渗透率的增加而减小(R2 = 0.6, n = 230)。采用先进的统计方法(如遗传算法)来改进速度-渗透率关系，并建立了从横波速度间接估计渗透率的模型。这些模型的性能取决于岩性和岩石结构(如淤泥与砂、胶结程度)，对于孔隙度和渗透率较低的层段(渗透率实测值与预测值之间的最大差异<±15%;R2 = 0.78, n = 230)。本研究介绍了一种新的实验装置和一种实用的“筛选”工作流程，可用于利用收集到的板状岩心s波速度进行渗透率预测。该预测模型可用于估计低于压力衰减剖面渗透率测量下限(0.001 md)的渗透率。该研究结果有利于致密粉砂岩/砂岩资源的开发，使他们能够表征低渗透层段(<0.001 md)的渗透率，从而优化增产设计和地下流体注入等应用。
{"title":"Profile Ultrasonic Velocity Measurements Performed on Slabbed Core: Implications for High-Resolution Permeability Prediction in Low-Permeability Rocks","authors":"Tariq Mohammed, A. Ghanizadeh, C. Clarkson, Zhengru Yang","doi":"10.2118/208901-ms","DOIUrl":"https://doi.org/10.2118/208901-ms","url":null,"abstract":"\u0000 Calibration of reservoir models for unconventional hydrocarbon reservoirs requires permeability data as input. Accurate permeability prediction from velocity data is desirable due to the relative abundance of velocity data that is typically available during exploration and development programs (e.g., through seismic imaging and well logging). Therefore, the development of fast and inexpensive ‘screening’ techniques tha can provide reliable estimation of permeability at high-resolution (cm-scale) using velocity data could be valuable to exploration/development programs in unconventional reservoirs.\u0000 A new experimental apparatus is described herein for measuring ultrasonic velocities (P- and S-wave) along the length of slabbed cores of low-permeability rocks at high-resolution (cm-scale). A statistical approach that combines along-core (profile) ultrasonic velocity testing and non-destructive experimental techniques (X-ray fluorescence, mechanical hardness, and profile permeability) is employed to develop predictive models for estimating permeability. Two slabbed cores from the Canadian Montney and Bakken formations, covering multiple geological intervals (tight siltstones/sandstones units), were analyzed for validation purposes.\u0000 Reasonable agreement is found between log- and lab-derived (ultra)sonic velocity data, indicating similar trends with depth. However, the exact log- and lab-derived (ultra)sonic velocity values are different due to the differences in stress conditions between the field and laboratory measurements and the direction of wave travel. A maximum variation of ±20 m/s is observed for both P- and S-wave velocities when measurements were repeated on the same points, providing evidence of experimental repeatability and reproducibility. Relationships exist between laboratory-measured profile ultrasonic velocities (S-wave), profile permeability, mechanical hardness, and clay content (inferred from elemental composition data). The profile S-wave velocities decrease with increasing permeability (R2 = 0.6, n = 230). Advanced statistical methods (e.g., genetic algorithms) are employed to improve the velocity-permeability relationship and develop models for indirect estimation of permeability from S-wave velocities. The performance of these models is dependent upon lithology and rock fabric (e.g., silt vs. sand, degree of cementation), with a better correlation achieved for intervals with lower porosity and permeability (<±15% maximum discrepancy between measured and predicted permeability values; R2 = 0.78, n = 230).\u0000 This study introduces a new experimental apparatus, and a practical ‘screening’ workflow, that can be used for permeability prediction using S-wave velocities collected on slabbed cores. This predictive model can be used to estimate permeability below the lower limit (0.001 md) of pressure-decay profile permeability measurements. The findings are beneficial to operators developing tight siltstone/sandstone resources by all","PeriodicalId":146458,"journal":{"name":"Day 1 Wed, March 16, 2022","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2022-03-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"116309704","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}
Steam quality surveillance is important for steam injection since the oil production response expected depends on the heat injected to the reservoir. This paper focuses on the evaluation of a mechanical device whose target is to increase the steam quality by means of physical principles such as centrifugal force and gravity, removing the water liquid phase not converted into steam as a result of the design limitations that a steam generator has in terms of steam dryness by scale deposition in the boiler piping. The following program was implemented to test the device, a cyclonic condensate separator, including different operational ways for disposing of the liquid phase removed by the separator. To begin, the separator was engaged to a steam generator outlet (25 MMBTU/hr capacity). A group of 3 wells close to the steam generator was selected to compare three operative ways for handling the hard and hot water removed by the cyclonic separator. An additional liquid phase sampling trap was installed downstream of the separator in the steam line to verify the steam quality by means of digital conductivity measurements. Steam injection on selected wells started sequentially and operational parameters as pressure, temperature, conductivity, steam quality, and gallons per minute (GPM) were collected from the steam generator and the cyclonic separator. Theoretical calculations for determining the heat generated, removed (via the liquid phase) and finally injected into the wells in MMBTU were done by using variables such as feeding water, operation time, enthalpy and steam quality, contrasting results obtained against the values given by the cyclonic separator. Finally, production results are shown and analyzed although they are not considered as relevant for evaluating the cyclonic separator effectiveness, since the main objective of the pilot was to check the steam quality increasing (above 95%) at field conditions. By using the cyclonic condensate separator, the injected steam quality increased from 81% to 98% on average during 41 operation days in a row. This improvement also was confirmed by the steam-trap installed downstream of the cyclonic separator (only 1.6% difference). The steam pressure and temperature losses caused by the cyclonic separator were 17% and 5% on average, respectively. From the cyclonic separator data and theoretical calculations, it was determined the cyclonic steam separator removed 227 bbl of water per day (17%) on average from the initial volumetric flow rate given by the generator (1407 water bbl/day at 41 GPM). In terms of energy, the cyclonic separator removed as liquid condensate 8% (41 MMBTU/day) of the initial energy given by the generator (527 MMBTU/day), in search of increasing the steam quality. From the three disposal options considered for the liquid phase that was removed, it was determined that injecting the liquid directly into the main production line was the most efficient way for handling this fluid, si
{"title":"Improving the Steam Quality injected in a Heavy Oil Reservoir by Using a Cyclonic-Type Condensate Separator: A Field Pilot","authors":"Andres Solano Arias","doi":"10.2118/208936-ms","DOIUrl":"https://doi.org/10.2118/208936-ms","url":null,"abstract":"\u0000 Steam quality surveillance is important for steam injection since the oil production response expected depends on the heat injected to the reservoir. This paper focuses on the evaluation of a mechanical device whose target is to increase the steam quality by means of physical principles such as centrifugal force and gravity, removing the water liquid phase not converted into steam as a result of the design limitations that a steam generator has in terms of steam dryness by scale deposition in the boiler piping. The following program was implemented to test the device, a cyclonic condensate separator, including different operational ways for disposing of the liquid phase removed by the separator. To begin, the separator was engaged to a steam generator outlet (25 MMBTU/hr capacity). A group of 3 wells close to the steam generator was selected to compare three operative ways for handling the hard and hot water removed by the cyclonic separator. An additional liquid phase sampling trap was installed downstream of the separator in the steam line to verify the steam quality by means of digital conductivity measurements.\u0000 Steam injection on selected wells started sequentially and operational parameters as pressure, temperature, conductivity, steam quality, and gallons per minute (GPM) were collected from the steam generator and the cyclonic separator. Theoretical calculations for determining the heat generated, removed (via the liquid phase) and finally injected into the wells in MMBTU were done by using variables such as feeding water, operation time, enthalpy and steam quality, contrasting results obtained against the values given by the cyclonic separator. Finally, production results are shown and analyzed although they are not considered as relevant for evaluating the cyclonic separator effectiveness, since the main objective of the pilot was to check the steam quality increasing (above 95%) at field conditions.\u0000 By using the cyclonic condensate separator, the injected steam quality increased from 81% to 98% on average during 41 operation days in a row. This improvement also was confirmed by the steam-trap installed downstream of the cyclonic separator (only 1.6% difference). The steam pressure and temperature losses caused by the cyclonic separator were 17% and 5% on average, respectively. From the cyclonic separator data and theoretical calculations, it was determined the cyclonic steam separator removed 227 bbl of water per day (17%) on average from the initial volumetric flow rate given by the generator (1407 water bbl/day at 41 GPM). In terms of energy, the cyclonic separator removed as liquid condensate 8% (41 MMBTU/day) of the initial energy given by the generator (527 MMBTU/day), in search of increasing the steam quality.\u0000 From the three disposal options considered for the liquid phase that was removed, it was determined that injecting the liquid directly into the main production line was the most efficient way for handling this fluid, si","PeriodicalId":146458,"journal":{"name":"Day 1 Wed, March 16, 2022","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2022-03-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"128928993","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}
C. Temizel, C. Yegin, F. Hosgor, Hakki Aydin, Shahana Kabir
With the ongoing paradigm shift in the Oil and Gas industry towards greener alternatives with net-zero objectives, several developing technologies have been recently deployed or proposed as promising solutions. The overall goals are to decrease carbon footprint and improve the projects’ economics and net present value (NPV). This study outlines the latest developments with underlying principles, practices, and economics. This holistic approach encompasses the overall feasibility with the challenges and the benefits. A comprehensive literature survey has been carried out on publicly available data to provide the theoretical background, rationale of use, screening and selection criteria, difficulties, and the workarounds. Systems to integrate the green methods with the respective oil and gas processes appear in detail, from screening to implementation. We outline economics under various scenarios with CAPEX methods and OPEX-intensive approaches to maximize the NPV. The technical details of the integration under multiple conditions that affect the system's efficiency, such as weather, seasonal temperature changes, wind, and solar exposure, have been investigated. Efficient integration of the selected green methods with the associated oil and gas process proves to be a concrete step towards a net-zero objective. Such integration brings additional benefits of improved economics with minimal effects in terms of capital intensiveness or other burdens on the overall economics. These items range from solar thermal applications in heavy oil recovery to heat recovery from the produced fluids, biomass, geothermal, wind, and wave for offshore processes. Cases with multigreen energy methods, such as solar and heat recovery, demonstrate promising outcomes. This article examines some of the latest green methods with various aspects corresponding to the selected oil and gas processes. We specifically focus on energy generation through standalone green methods and extracting energy from oil and gas processes in a greenway. The overall objective is to close the current gap in the literature.
{"title":"Exploring Green Energy Applications in the Oil and Gas Industry","authors":"C. Temizel, C. Yegin, F. Hosgor, Hakki Aydin, Shahana Kabir","doi":"10.2118/208900-ms","DOIUrl":"https://doi.org/10.2118/208900-ms","url":null,"abstract":"\u0000 With the ongoing paradigm shift in the Oil and Gas industry towards greener alternatives with net-zero objectives, several developing technologies have been recently deployed or proposed as promising solutions. The overall goals are to decrease carbon footprint and improve the projects’ economics and net present value (NPV). This study outlines the latest developments with underlying principles, practices, and economics. This holistic approach encompasses the overall feasibility with the challenges and the benefits.\u0000 A comprehensive literature survey has been carried out on publicly available data to provide the theoretical background, rationale of use, screening and selection criteria, difficulties, and the workarounds. Systems to integrate the green methods with the respective oil and gas processes appear in detail, from screening to implementation. We outline economics under various scenarios with CAPEX methods and OPEX-intensive approaches to maximize the NPV. The technical details of the integration under multiple conditions that affect the system's efficiency, such as weather, seasonal temperature changes, wind, and solar exposure, have been investigated.\u0000 Efficient integration of the selected green methods with the associated oil and gas process proves to be a concrete step towards a net-zero objective. Such integration brings additional benefits of improved economics with minimal effects in terms of capital intensiveness or other burdens on the overall economics. These items range from solar thermal applications in heavy oil recovery to heat recovery from the produced fluids, biomass, geothermal, wind, and wave for offshore processes. Cases with multigreen energy methods, such as solar and heat recovery, demonstrate promising outcomes.\u0000 This article examines some of the latest green methods with various aspects corresponding to the selected oil and gas processes. We specifically focus on energy generation through standalone green methods and extracting energy from oil and gas processes in a greenway. The overall objective is to close the current gap in the literature.","PeriodicalId":146458,"journal":{"name":"Day 1 Wed, March 16, 2022","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2022-03-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"130766878","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}
This paper develops a new method for estimation of rock fabric number (RFN) from well logs in unconventional tight oil carbonates with less than 0.1 md. The objective is to investigate the oil potential of a Middle Cretaceous tight carbonate in Mexico. Development of a method for these conditions is challenging as the current approach developed by Lucia (1983) has been explained for carbonates with more than 0.1md. The method is calibrated with data from cores and cuttings and allows estimating the presence of grainstone, packstone and wackstone rocks in unconventional tight carbonates from well logs. A crossplot of RFN vs rp35 (pore throat radius at 35% cumulative pore volume) permits delimiting intervals with good production potential that is supported by well testing data. Information for analysis of the Mexican carbonate comes from well logs of 9 wells and 2 re-entry wells, four buildup tests and a limited amount of core and drill cuttings information. All data were provided by a petroleum company and have been used, for transparency, without any modifications. An unconventional tight carbonate as defined in this paper has a permeability smaller than 0.1 md. The unconventional tight oil carbonate reservoir considered in this study includes 95 percent of data with permeabilities smaller than 0.1 md and only 5% with permeabilities larger than 0.1 md. The method introduced by Lucia (1983) and Jennings and Lucia (2003) for determining RFN is powerful, but they explained it only for permeabilities larger than 0.1 md. Thus, the need for a methodology that allows estimating from well logs the presence of grainstone, packstone and/or wackstone in unconventional tight carbonate reservoirs with permeabilities smaller than 0.1 md. Results indicate that the RFN provides a useful approach for distinguishing grainstone, packstone and wackstone rocks in unconventional tight carbonate reservoirs. Furthermore, rock fabric can be linked with Pickett plots to provide an integrated quantitative evaluation of RFN, porosity, water saturation, permeability, pore throat radius, and capillary pressure. This integration indicates that there is good oil potential in the Middle Cretaceous unconventional tight carbonate in Mexico. The novelty of this paper is the use of rock fabric (RFN) in unconventional tight carbonates with permeabilities smaller than 0.1 md for estimating the presence of grainstone, packstone and wackstone rocks from well logs. In addition, a crossplot of RFN vs rp35 provides a good indication of intervals with oil production potential.
{"title":"A New Method for Determination of Rock Fabric Number from Well Logs in Unconventional Tight Oil Carbonates","authors":"Brenda Azuara Diliegros, R. Aguilera","doi":"10.2118/208893-ms","DOIUrl":"https://doi.org/10.2118/208893-ms","url":null,"abstract":"\u0000 This paper develops a new method for estimation of rock fabric number (RFN) from well logs in unconventional tight oil carbonates with less than 0.1 md. The objective is to investigate the oil potential of a Middle Cretaceous tight carbonate in Mexico. Development of a method for these conditions is challenging as the current approach developed by Lucia (1983) has been explained for carbonates with more than 0.1md.\u0000 The method is calibrated with data from cores and cuttings and allows estimating the presence of grainstone, packstone and wackstone rocks in unconventional tight carbonates from well logs. A crossplot of RFN vs rp35 (pore throat radius at 35% cumulative pore volume) permits delimiting intervals with good production potential that is supported by well testing data. Information for analysis of the Mexican carbonate comes from well logs of 9 wells and 2 re-entry wells, four buildup tests and a limited amount of core and drill cuttings information. All data were provided by a petroleum company and have been used, for transparency, without any modifications.\u0000 An unconventional tight carbonate as defined in this paper has a permeability smaller than 0.1 md. The unconventional tight oil carbonate reservoir considered in this study includes 95 percent of data with permeabilities smaller than 0.1 md and only 5% with permeabilities larger than 0.1 md. The method introduced by Lucia (1983) and Jennings and Lucia (2003) for determining RFN is powerful, but they explained it only for permeabilities larger than 0.1 md. Thus, the need for a methodology that allows estimating from well logs the presence of grainstone, packstone and/or wackstone in unconventional tight carbonate reservoirs with permeabilities smaller than 0.1 md.\u0000 Results indicate that the RFN provides a useful approach for distinguishing grainstone, packstone and wackstone rocks in unconventional tight carbonate reservoirs. Furthermore, rock fabric can be linked with Pickett plots to provide an integrated quantitative evaluation of RFN, porosity, water saturation, permeability, pore throat radius, and capillary pressure. This integration indicates that there is good oil potential in the Middle Cretaceous unconventional tight carbonate in Mexico.\u0000 The novelty of this paper is the use of rock fabric (RFN) in unconventional tight carbonates with permeabilities smaller than 0.1 md for estimating the presence of grainstone, packstone and wackstone rocks from well logs. In addition, a crossplot of RFN vs rp35 provides a good indication of intervals with oil production potential.","PeriodicalId":146458,"journal":{"name":"Day 1 Wed, March 16, 2022","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2022-03-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"122246048","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}
Wilson Ekpotu, Queendarlene A. Nwabueze, J. Akintola, M. Obialor, I. Ansa
Carbon Capture processes have been utilized in various sectors, but limitations in its large parasitic load have been observed in its use in Natural Gas Process Plants, and that is mostly associated with the energy penalty incurred during its processes. The energy penalty is mainly caused by the solvent regeneration in the stripper column, the CO2 compression process, and the low amount of CO2 levels in the combustion flue gas, which is usually less than 15% (7-14 % for coal-fired and as low as 3% for gas-fired). This research work, therefore, has the objective of solving the challenges of solvent regeneration time in the stripper column, as the packing arrangement, corrugation angle, and crimp height can influence the capture efficiency through the solvent. Aspen HYSYS was adopted for modeling the absorption rate through the stripper column in order to understand the hydrodynamic phenomenon in absorbers using solid absorbents under plug flow and well-mixed flow conditions. The rate fraction was analyzed at various process configurations and staged regeneration simulation processes in a packed column considering enthalpy changes at both gas and liquid phases. The results showed a 20% reduction in the solvent regeneration time, as against existing processes & technologies. It was observed that operating at a lower circulating rate results in a lower utility requirement on the reboiler hence increasing the circulation flow rate, which has little to no effect on the condenser utility. And this additionally led to a reduction in the energy penalty, as low-pressure steam was used as the energy input for the solvent regeneration process, thus posing a significant efficiency penalty. In conclusion, the modeling by the process optimization and modification of the post-combustion carbon capture plant reduced the regeneration energy requirements. Novel/Additive Infirmation: The solvent solution flowrate in the absorber was optimally considered with various lean CO2 solvent loadings in order to achieve higher CO2 capture and removal efficiency.
{"title":"A Novel Approach to Post-Combustion Carbon Capture Processes in Natural Gas Plants By Reduction of Solvent Regeneration Time","authors":"Wilson Ekpotu, Queendarlene A. Nwabueze, J. Akintola, M. Obialor, I. Ansa","doi":"10.2118/208887-ms","DOIUrl":"https://doi.org/10.2118/208887-ms","url":null,"abstract":"\u0000 \u0000 \u0000 Carbon Capture processes have been utilized in various sectors, but limitations in its large parasitic load have been observed in its use in Natural Gas Process Plants, and that is mostly associated with the energy penalty incurred during its processes. The energy penalty is mainly caused by the solvent regeneration in the stripper column, the CO2 compression process, and the low amount of CO2 levels in the combustion flue gas, which is usually less than 15% (7-14 % for coal-fired and as low as 3% for gas-fired). This research work, therefore, has the objective of solving the challenges of solvent regeneration time in the stripper column, as the packing arrangement, corrugation angle, and crimp height can influence the capture efficiency through the solvent.\u0000 \u0000 \u0000 \u0000 Aspen HYSYS was adopted for modeling the absorption rate through the stripper column in order to understand the hydrodynamic phenomenon in absorbers using solid absorbents under plug flow and well-mixed flow conditions. The rate fraction was analyzed at various process configurations and staged regeneration simulation processes in a packed column considering enthalpy changes at both gas and liquid phases.\u0000 \u0000 \u0000 \u0000 The results showed a 20% reduction in the solvent regeneration time, as against existing processes & technologies. It was observed that operating at a lower circulating rate results in a lower utility requirement on the reboiler hence increasing the circulation flow rate, which has little to no effect on the condenser utility. And this additionally led to a reduction in the energy penalty, as low-pressure steam was used as the energy input for the solvent regeneration process, thus posing a significant efficiency penalty. In conclusion, the modeling by the process optimization and modification of the post-combustion carbon capture plant reduced the regeneration energy requirements. Novel/Additive Infirmation: The solvent solution flowrate in the absorber was optimally considered with various lean CO2 solvent loadings in order to achieve higher CO2 capture and removal efficiency.\u0000","PeriodicalId":146458,"journal":{"name":"Day 1 Wed, March 16, 2022","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2022-03-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"122503006","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 oil/steam ratio for both Cyclic Steam Stimulation (CSS) and Steam Flooding (SF) has almost reached economic limits in Liaohe, China's largest heavy oilfield. Complex displacement of CSS and SF assisted with foaming agents and CO2 has been applied at commercial scale to increase the oil production. In this paper, we will present a field case study of the complex displacement operation. We will discuss the details from the foaming agent selection, completion design, operation management and performance data analysis. To improve production rates for the low producing CSS and SF wells, a recovery method of complex displacement has been implemented at commercial scale in Liaohe oilfield. The application of the method depends on the reservoir condition, well completion design, injection time, types of foaming agents and so on. After a complicated optimization and careful field implementation, a satisfactory result was achieved. A complete field case will be studied in detail and comprehensive field performance data will be presented and analyzed. For both CSS and SF operations, the type of foaming agent and especially its injection rates for each of these operations is the key to the success of the project. Different types of foaming agents and injection rates have been trialed. The injection rates of CO2,and steam to form the agent have been optimized. Relatively mature complex displacement development technology has been developed for both CSS and SF and will be presented in the paper. As of today, more than 480 CSS wells have been operated with the assistance of CO2. The oil/steam ratio in those application well groups has increased by 7%, while the operating cost has decreased by 7.9%. Three SF well groups assisted with hot air foam have been tested. The incremental oil production was more than 60%. The goals of cost reduction and oil production increase have been achieved with the complex displacement method in both CSS and SF. As far as we know, this is the first paper to comprehensively introduce this type of complex displacement recovery method for CSS and SF in heavy oil operations. This complex displacement recovery method has been proved to be an effective method to improve the heavy oil recovery in Liaohe. It is believed the learning and experience can be beneficial for the other heavy oilfields around the world. In the meantime, it could also facilitate the utilization and storage of CO2.
{"title":"The Application of Complex Displacement in Cyclic Steam Stimulation CSS & Steam Flooding SF Development in Liaohe Oilfield: A Field Performance Study","authors":"Jianfeng Liu, Xiaoming Wu, Shouguo Sun, Ling Hao","doi":"10.2118/208940-ms","DOIUrl":"https://doi.org/10.2118/208940-ms","url":null,"abstract":"\u0000 The oil/steam ratio for both Cyclic Steam Stimulation (CSS) and Steam Flooding (SF) has almost reached economic limits in Liaohe, China's largest heavy oilfield. Complex displacement of CSS and SF assisted with foaming agents and CO2 has been applied at commercial scale to increase the oil production. In this paper, we will present a field case study of the complex displacement operation. We will discuss the details from the foaming agent selection, completion design, operation management and performance data analysis.\u0000 To improve production rates for the low producing CSS and SF wells, a recovery method of complex displacement has been implemented at commercial scale in Liaohe oilfield. The application of the method depends on the reservoir condition, well completion design, injection time, types of foaming agents and so on. After a complicated optimization and careful field implementation, a satisfactory result was achieved. A complete field case will be studied in detail and comprehensive field performance data will be presented and analyzed.\u0000 For both CSS and SF operations, the type of foaming agent and especially its injection rates for each of these operations is the key to the success of the project. Different types of foaming agents and injection rates have been trialed. The injection rates of CO2,and steam to form the agent have been optimized. Relatively mature complex displacement development technology has been developed for both CSS and SF and will be presented in the paper. As of today, more than 480 CSS wells have been operated with the assistance of CO2. The oil/steam ratio in those application well groups has increased by 7%, while the operating cost has decreased by 7.9%. Three SF well groups assisted with hot air foam have been tested. The incremental oil production was more than 60%. The goals of cost reduction and oil production increase have been achieved with the complex displacement method in both CSS and SF.\u0000 As far as we know, this is the first paper to comprehensively introduce this type of complex displacement recovery method for CSS and SF in heavy oil operations.\u0000 This complex displacement recovery method has been proved to be an effective method to improve the heavy oil recovery in Liaohe. It is believed the learning and experience can be beneficial for the other heavy oilfields around the world. In the meantime, it could also facilitate the utilization and storage of CO2.","PeriodicalId":146458,"journal":{"name":"Day 1 Wed, March 16, 2022","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2022-03-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"133266925","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}
Steam injection has been widely applied in different forms to recover heavy-oil and bitumen for decades. Even though this method is a proven and effective technology, the steam generation process itself may lead to environmental issues and low economic viability. Also, many worldwide steam projects, including SAGD projects in Canada, have already reached their maturity with a severe decline in production despite continuous steam injection. Escalating greenhouse gas (GHG) emissions is another crucial downside of steam injection application, contributing to an emission growth rate of about 1.1% worldwide and 0.8% annually in Canada. This requires us to search for different techniques to deplete the remaining (conditioned) oil efficiently and in an eco-friendly manner. This paper focuses on the testing of a new technique to minimize GHG emissions resulting from steam generation while enhancing the ultimate recovery post-SAGD. ~50,000 cP heavy crude and processed oil (for visual models) samples were used as an oleic phase in this experimental research. Condensable gases as single and multiple (mixed with methane) components were included as potential solvents to be applied to the already steamed models. Visual Hele-Shaw and glass-bead-pack models were employed to investigate the displacement mechanism, displacement efficiency, and phase distribution in porous media. All experiments were performed at currently existing temperatures in matured SAGD reservoirs to further evaluate the sensitivity of phase behavior of condensable solvents in a heavy-oil/steam system, as well as existing condensed water of which is not compatible with hydrocarbon solvents. We observed that condensable solvents could improve the displacement efficiency/incremental heavy-oil recovery over 30% by mobilizing residual oil and providing favorable conformance to the steam chamber. More importantly, the steam usage was able to be entirely cut off, and the energy efficiency could be ramped up to almost 100%. Additionally, the type (and composition) for applying condensable solvents were determined at a given post-SAGD temperature. Also, the retrieval potential of the condensable solvent with oil was investigated for an efficient process. Condensable gases with different compositions were introduced as potential solvents to recuperate heavy-oil and bitumen recovery and reduce or even completely cut off the steam injection at late-stage SAGD, diminishing its GHG emission and improving energy efficiency. Valuable findings present beneficial recommendations for low-emission and high-efficiency late-stage heavy-oil recovery as post-SAGD applications, as well as other types of steam injection processes.
{"title":"What is Next for SAGD?: Evaluation of Low GHG and High-Efficiency Tertiary Recovery Options","authors":"R. Pratama, T. Babadagli","doi":"10.2118/208876-ms","DOIUrl":"https://doi.org/10.2118/208876-ms","url":null,"abstract":"\u0000 Steam injection has been widely applied in different forms to recover heavy-oil and bitumen for decades. Even though this method is a proven and effective technology, the steam generation process itself may lead to environmental issues and low economic viability. Also, many worldwide steam projects, including SAGD projects in Canada, have already reached their maturity with a severe decline in production despite continuous steam injection. Escalating greenhouse gas (GHG) emissions is another crucial downside of steam injection application, contributing to an emission growth rate of about 1.1% worldwide and 0.8% annually in Canada. This requires us to search for different techniques to deplete the remaining (conditioned) oil efficiently and in an eco-friendly manner. This paper focuses on the testing of a new technique to minimize GHG emissions resulting from steam generation while enhancing the ultimate recovery post-SAGD.\u0000 ~50,000 cP heavy crude and processed oil (for visual models) samples were used as an oleic phase in this experimental research. Condensable gases as single and multiple (mixed with methane) components were included as potential solvents to be applied to the already steamed models. Visual Hele-Shaw and glass-bead-pack models were employed to investigate the displacement mechanism, displacement efficiency, and phase distribution in porous media. All experiments were performed at currently existing temperatures in matured SAGD reservoirs to further evaluate the sensitivity of phase behavior of condensable solvents in a heavy-oil/steam system, as well as existing condensed water of which is not compatible with hydrocarbon solvents.\u0000 We observed that condensable solvents could improve the displacement efficiency/incremental heavy-oil recovery over 30% by mobilizing residual oil and providing favorable conformance to the steam chamber. More importantly, the steam usage was able to be entirely cut off, and the energy efficiency could be ramped up to almost 100%. Additionally, the type (and composition) for applying condensable solvents were determined at a given post-SAGD temperature. Also, the retrieval potential of the condensable solvent with oil was investigated for an efficient process.\u0000 Condensable gases with different compositions were introduced as potential solvents to recuperate heavy-oil and bitumen recovery and reduce or even completely cut off the steam injection at late-stage SAGD, diminishing its GHG emission and improving energy efficiency. Valuable findings present beneficial recommendations for low-emission and high-efficiency late-stage heavy-oil recovery as post-SAGD applications, as well as other types of steam injection processes.","PeriodicalId":146458,"journal":{"name":"Day 1 Wed, March 16, 2022","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2022-03-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"134398656","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}
Enhanced oil recovery by steam injection requires the burning of natural gas, a finite and expensive resource for steam production. However, solar energy can be harnessed for steam production via solar parabolic troughs. In this study, the design and application of a solar parabolic trough, in tandem with a heat exchanger for producing steam for Enhanced Oil Recovery (EOR) in Trinidad and Tobago is presented. Excel spreadsheets were developed to perform the calculations and to optimize the size and design of the parabolic trough collector for maximum heating efficiency. The parabolic trough designed was 36 m in length and consisted of a parabolic aluminum reflector, stainless steel receiver tube, and a glass envelope that surrounded the receiver tube. The heat transfer fluid used was Therminol VP-1, a synthetic oil, which was heated up to 403 °C. Once heated, the heat transfer fluid was then transferred to a heat exchanger whereby steam was produced at 300°C. Overall, 4 of the parabolic trough collector systems were required to heat enough fluid to fill the calculated 343 tubes of the heat exchanger, which were 0.091 m in diameter and 4.9m in length. The total cost of the parabolic troughs and the heat exchanger tubes was calculated to be USD 119,562. By having a mass flow rate of 46 kg/s for the water within the heat exchanger, approximately 1630 barrels of oil were economically produced at a maximum steam oil ratio of 4.5 after one day of steam injection. A cash flow projection was completed using both operational and capital expenditure of the parabolic trough collector. From this study, the parabolic trough system was shown to generate a profit of USD 1.8 MM after six months of steam injection. Profit calculation considered both capital and operating expenditure as well as the income gained from oil recovery due to the parabolic trough collector. The spreadsheet developed can be used to design similar systems of steam generation for enhanced oil recovery projects of different scales.
{"title":"Design of a Solar Parabolic Trough Capable of Producing Steam for Enhanced Oil Recovery in Trinidad and Tobago","authors":"Ahiliah Gajadhar, R. Hosein","doi":"10.2118/208903-ms","DOIUrl":"https://doi.org/10.2118/208903-ms","url":null,"abstract":"\u0000 Enhanced oil recovery by steam injection requires the burning of natural gas, a finite and expensive resource for steam production. However, solar energy can be harnessed for steam production via solar parabolic troughs. In this study, the design and application of a solar parabolic trough, in tandem with a heat exchanger for producing steam for Enhanced Oil Recovery (EOR) in Trinidad and Tobago is presented. Excel spreadsheets were developed to perform the calculations and to optimize the size and design of the parabolic trough collector for maximum heating efficiency. The parabolic trough designed was 36 m in length and consisted of a parabolic aluminum reflector, stainless steel receiver tube, and a glass envelope that surrounded the receiver tube. The heat transfer fluid used was Therminol VP-1, a synthetic oil, which was heated up to 403 °C. Once heated, the heat transfer fluid was then transferred to a heat exchanger whereby steam was produced at 300°C. Overall, 4 of the parabolic trough collector systems were required to heat enough fluid to fill the calculated 343 tubes of the heat exchanger, which were 0.091 m in diameter and 4.9m in length. The total cost of the parabolic troughs and the heat exchanger tubes was calculated to be USD 119,562. By having a mass flow rate of 46 kg/s for the water within the heat exchanger, approximately 1630 barrels of oil were economically produced at a maximum steam oil ratio of 4.5 after one day of steam injection. A cash flow projection was completed using both operational and capital expenditure of the parabolic trough collector. From this study, the parabolic trough system was shown to generate a profit of USD 1.8 MM after six months of steam injection. Profit calculation considered both capital and operating expenditure as well as the income gained from oil recovery due to the parabolic trough collector. The spreadsheet developed can be used to design similar systems of steam generation for enhanced oil recovery projects of different scales.","PeriodicalId":146458,"journal":{"name":"Day 1 Wed, March 16, 2022","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2022-03-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"123174570","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}
Thermal oil recovery processes, and more specifically steam assisted gravity drainage (SAGD), is one of the two commercial methods to produce heavy oil. In the later stages of SAGD heat losses increase. One solution to improve heat losses in the steam chamber is to co-inject a foaming solution with non-condensable gases. It is expected that such a scheme will redirect steam towards heating oil and not the overburden. An appropriate foaming agent is required for successful implementation of a steam-foam process. Conventional laboratory techniques have provided some indication of foam stability with different types of surfactants but failed to match the reservoir conditions and time scale. Recently, the use of nanoparticles along with surfactants has gained attention as a method to stabilize foams under thermal operating conditions. The aim of this research is to investigate the thermal stability of foam under steam conditions (temperatures around 200 °C) using mixtures of different surfactants and silica nanoparticles. A series of foam stability tests were conducted at temperature ranges of 170 °C to 212 °C and pressures of 2.78 MPag and 4.22 MPag using two different anionic surfactants and four different bare and coated silica nanoparticles. The foamy solutions were prepared with a combination of different surfactants and nanoparticles, which were co-injected with N2 gas into a sand pack to generate foam at different temperatures and pressures. The generated foam was then transferred to a high pressure and high temperature visual cell and the foam half-life was measured as the indicator of its decay. It was observed that a small deviation from the dew point (decreasing the temperature or increasing the pressure) significantly improved foam stability. Addition of nanoparticles proved to be synergistic as the foam half-life near the steam dew point increased about four-fold compared to surfactant only foams. Among the tested nanoparticles, the use of polyethylene glycol (PEG) coated silica nanoparticles along with an anionic surfactant resulted in the highest foam stability near the steam dew point. To date, most of the foam stability tests have been conducted at temperatures below 200 °C with the focus on using surfactants. This research extended the foam stability tests to temperatures in excess of 200°C using mixtures of surfactants and nanoparticles. Although the foam stability still needs to be improved for reservoir-scale application, our screening methodology presents a realistic process of generating foam in a porous medium with nanoparticles and surfactants under a desired thermodynamic state for subsequent foam thermal stability testing.
{"title":"Nanoparticle Assisted Foam Stability Under SAGD Conditions","authors":"S. Maaref, A. Kantzas","doi":"10.2118/208877-ms","DOIUrl":"https://doi.org/10.2118/208877-ms","url":null,"abstract":"\u0000 Thermal oil recovery processes, and more specifically steam assisted gravity drainage (SAGD), is one of the two commercial methods to produce heavy oil. In the later stages of SAGD heat losses increase. One solution to improve heat losses in the steam chamber is to co-inject a foaming solution with non-condensable gases. It is expected that such a scheme will redirect steam towards heating oil and not the overburden. An appropriate foaming agent is required for successful implementation of a steam-foam process. Conventional laboratory techniques have provided some indication of foam stability with different types of surfactants but failed to match the reservoir conditions and time scale. Recently, the use of nanoparticles along with surfactants has gained attention as a method to stabilize foams under thermal operating conditions. The aim of this research is to investigate the thermal stability of foam under steam conditions (temperatures around 200 °C) using mixtures of different surfactants and silica nanoparticles. A series of foam stability tests were conducted at temperature ranges of 170 °C to 212 °C and pressures of 2.78 MPag and 4.22 MPag using two different anionic surfactants and four different bare and coated silica nanoparticles. The foamy solutions were prepared with a combination of different surfactants and nanoparticles, which were co-injected with N2 gas into a sand pack to generate foam at different temperatures and pressures. The generated foam was then transferred to a high pressure and high temperature visual cell and the foam half-life was measured as the indicator of its decay.\u0000 It was observed that a small deviation from the dew point (decreasing the temperature or increasing the pressure) significantly improved foam stability. Addition of nanoparticles proved to be synergistic as the foam half-life near the steam dew point increased about four-fold compared to surfactant only foams. Among the tested nanoparticles, the use of polyethylene glycol (PEG) coated silica nanoparticles along with an anionic surfactant resulted in the highest foam stability near the steam dew point.\u0000 To date, most of the foam stability tests have been conducted at temperatures below 200 °C with the focus on using surfactants. This research extended the foam stability tests to temperatures in excess of 200°C using mixtures of surfactants and nanoparticles. Although the foam stability still needs to be improved for reservoir-scale application, our screening methodology presents a realistic process of generating foam in a porous medium with nanoparticles and surfactants under a desired thermodynamic state for subsequent foam thermal stability testing.","PeriodicalId":146458,"journal":{"name":"Day 1 Wed, March 16, 2022","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2022-03-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"133248002","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}
Optimizing economics for unconventional resource development is a delicate balance among four main factors: reservoir deliverability, commodity price, completion design, and well spacing. For a certain reservoir, commodity price, and completion design, there is a well spacing that will optimize field development net present value (NPV). However, if we consider a different part of the reservoir (area or landing zone), commodity price, or completion design, that optimal well spacing changes. Given that this problem is fraught with uncertainty (in price, reservoir deliverability, and the impact on production of changing completion design or well spacing), we need simple, flexible tools to make better decisions about unconventional pad design. From a technical perspective, teams of subsurface professionals strive to understand the relationship between well productivity and well spacing for a given completion design (or vice versa). If the well spacing is too tight relative to the size of fracture stimulation, the recovery factor will be high, but the development plan will be over-capitalized. If the well spacing is too wide relative to the fracture stimulation, the per-well recovery will be high, but too much resource will be left in the ground and the NPV of the development plan will be low. To search for the optimal pad design, operators often invest in integrated technical workflows with multi-well fracture modeling and reservoir simulation; although useful, these workflows are not practical to apply for every asset in a portfolio because they simply take too long. As an alternative approach, this paper builds on existing tools in the literature to quantify the impact of changing well spacing on well productivity for a given completion design, using a new, simple, intuitive empirical equation. Using real data from the Permian basin, this paper applies the empirical equation to model the relationship between well performance and well spacing, and quantify uncertainty in that relationship. By linking this equation with a simple economic model, the paper shows how to make appropriate well spacing decisions under uncertainty, and how those decisions would change due to changes in reservoir deliverability or commodity price. Compared to similar methods in the literature, this approach better captures the physics associated with overlap in drainage areas for adjacent unconventional wells, while maintaining simplicity and ease of implementation. The paper also discusses how to integrate various diagnostics that give information about fracture geometry, to help guide the bounds of uncertainty in the well performance relationship. Even with limited data, this approach can be applied to yield useful information for decision makers about how to adjust unconventional pad design to improve development plan economics.
{"title":"No Reservoir Model? No Problem. Unconventional Well Spacing Optimization With Simple Tools","authors":"Patrick Miller, Darcy Redpath, Keane Dauncey","doi":"10.2118/208882-ms","DOIUrl":"https://doi.org/10.2118/208882-ms","url":null,"abstract":"\u0000 Optimizing economics for unconventional resource development is a delicate balance among four main factors: reservoir deliverability, commodity price, completion design, and well spacing. For a certain reservoir, commodity price, and completion design, there is a well spacing that will optimize field development net present value (NPV). However, if we consider a different part of the reservoir (area or landing zone), commodity price, or completion design, that optimal well spacing changes. Given that this problem is fraught with uncertainty (in price, reservoir deliverability, and the impact on production of changing completion design or well spacing), we need simple, flexible tools to make better decisions about unconventional pad design.\u0000 From a technical perspective, teams of subsurface professionals strive to understand the relationship between well productivity and well spacing for a given completion design (or vice versa). If the well spacing is too tight relative to the size of fracture stimulation, the recovery factor will be high, but the development plan will be over-capitalized. If the well spacing is too wide relative to the fracture stimulation, the per-well recovery will be high, but too much resource will be left in the ground and the NPV of the development plan will be low. To search for the optimal pad design, operators often invest in integrated technical workflows with multi-well fracture modeling and reservoir simulation; although useful, these workflows are not practical to apply for every asset in a portfolio because they simply take too long. As an alternative approach, this paper builds on existing tools in the literature to quantify the impact of changing well spacing on well productivity for a given completion design, using a new, simple, intuitive empirical equation.\u0000 Using real data from the Permian basin, this paper applies the empirical equation to model the relationship between well performance and well spacing, and quantify uncertainty in that relationship. By linking this equation with a simple economic model, the paper shows how to make appropriate well spacing decisions under uncertainty, and how those decisions would change due to changes in reservoir deliverability or commodity price.\u0000 Compared to similar methods in the literature, this approach better captures the physics associated with overlap in drainage areas for adjacent unconventional wells, while maintaining simplicity and ease of implementation. The paper also discusses how to integrate various diagnostics that give information about fracture geometry, to help guide the bounds of uncertainty in the well performance relationship. Even with limited data, this approach can be applied to yield useful information for decision makers about how to adjust unconventional pad design to improve development plan economics.","PeriodicalId":146458,"journal":{"name":"Day 1 Wed, March 16, 2022","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2022-03-11","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"133479060","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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