S. Perrier, A. Araman, Ashis Shrestha, Zulibukaer Shawuti
Rate Transient Analysis (RTA) is a classic characterization method for unconventional wells. In this paper, we propose to leverage RTA rate-pressure transforms by analyzing the data at play scale, using pattern and anomaly classification algorithms, to derive new quantitative and qualitative indicators for more than 600 wells operated by Chesapeake Energy on Utica gas shale play. This paper will present:a workflow of automated classification and extraction of RTA characteristics, including the collection of weak signals associated to well-to-well interferences.the major large-scale observation of this study: Stimulated Rock Volume (SRV) characteristics change over time The comprehensive review of the context of occurrence of these evolutions in SRV characteristics introduces a new field of discussion on hydraulic fracture geomechanical behavior under depletion. In particular, these evolutions of SRV characteristics occur in a fairly structured way (in term of timing and geographic distribution), and the late RTA slopes (in transient flow regime) show a strong trend of convergence toward an apparent geomechanical stable state. These evolutions in SRV characteristics have multiple implications for the reservoir engineer as well as for the understanding/benchmarking of the performance of fracturing techniques. A new stimulation indicator is proposed, 1_m2_clusters.
{"title":"Innovative Play-Scale Integration of Rate Transient Analysis Data: New Stimulation Indicator and Insights on Stimulated Rock Volume Behavior With Depletion","authors":"S. Perrier, A. Araman, Ashis Shrestha, Zulibukaer Shawuti","doi":"10.2118/191805-18ERM-MS","DOIUrl":"https://doi.org/10.2118/191805-18ERM-MS","url":null,"abstract":"\u0000 Rate Transient Analysis (RTA) is a classic characterization method for unconventional wells. In this paper, we propose to leverage RTA rate-pressure transforms by analyzing the data at play scale, using pattern and anomaly classification algorithms, to derive new quantitative and qualitative indicators for more than 600 wells operated by Chesapeake Energy on Utica gas shale play.\u0000 This paper will present:a workflow of automated classification and extraction of RTA characteristics, including the collection of weak signals associated to well-to-well interferences.the major large-scale observation of this study: Stimulated Rock Volume (SRV) characteristics change over time\u0000 The comprehensive review of the context of occurrence of these evolutions in SRV characteristics introduces a new field of discussion on hydraulic fracture geomechanical behavior under depletion.\u0000 In particular, these evolutions of SRV characteristics occur in a fairly structured way (in term of timing and geographic distribution), and the late RTA slopes (in transient flow regime) show a strong trend of convergence toward an apparent geomechanical stable state.\u0000 These evolutions in SRV characteristics have multiple implications for the reservoir engineer as well as for the understanding/benchmarking of the performance of fracturing techniques. A new stimulation indicator is proposed, 1_m2_clusters.","PeriodicalId":298489,"journal":{"name":"Day 4 Wed, October 10, 2018","volume":"9 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-10-07","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"117047277","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 present study used the workflow presented in Al-Ameri et al. (2018a, 2018b) to evaluate the impact of the fracturing fluid imbibition on the near fracture face shale matrix. Al-Ameri et al. (2018b) used carbonate-rich outcrop shale core samples that had very low and no clay content. However, in this workflow, core samples from the Barnett reservoir that had an abundant amount of quartz and clay were used. The primary aspect of the current study is to investigate the mutual effect of the shale rock petrophysical properties and the polymer adsorption; moreover, the effect of the shale mineralogical composition on the rock prone to adsorb polymer. The effect of the non-ionic surfactant on the imbibition rates, and also the anisotropy on the rock ability for polymer adsorption were also investigated. The results of this workflow were compared to the Marcellus samples results presented in Al-Ameri et al. (2018b). The workflow incorporates conducting three systematic imbibition experiments for a same shale core sample using brine, slickwater, and brine again. The sample brine permeability was measured before and after the imbibition experiments using a constant rate steady-state permeability setup. The results showed that the polymer adsorption reduces the brine spontaneous imbibition volumes. Moreover, the shale petrophysical properties could dominate the polymer adsorption more than the mineralogical composition. Adding a non-ionic surfactant to the slickwater enhanced the imbibition rate considerably into both of the Barnett and Marcellus shale samples, and that improves the fluid flowback in these shales. The bedding planes and their orientation are among the factors that control the effect of the polymer adsorption on the fluid imbibition rate. The more obvious are the bedding planes, the higher impact of the polymer adsorption on the fluid imbibition rate. However, the petrophysical properties have more effect on the shale prone to adsorb the polymer than the bedding plane orientation. The effect of the polymer adsorption slightly increased the capillary pressure curve. However, as the porosity and permeability increase, the effect of the polymer adsorption on the capillary pressure increases. In comparison to the Eagle Ford shale, the Barnett and Marcellus shales had lower capillary pressure, and that could be one of the reasons of their higher fluid flowback. The impact of the polymer adsorption on the water relative permeability was less for the Barnett sample in comparison to the Marcellus sample because of its lower porosity and permeability.
{"title":"A Workflow to Investigate the Impact of the Spontaneous Imbibition of a Slickwater Fracturing Fluid on the Near Fracture Face Shale Matrix","authors":"A. Al-Ameri, T. Gamadi, I. Ispas, M. Watson","doi":"10.2118/191830-18ERM-MS","DOIUrl":"https://doi.org/10.2118/191830-18ERM-MS","url":null,"abstract":"\u0000 The present study used the workflow presented in Al-Ameri et al. (2018a, 2018b) to evaluate the impact of the fracturing fluid imbibition on the near fracture face shale matrix. Al-Ameri et al. (2018b) used carbonate-rich outcrop shale core samples that had very low and no clay content. However, in this workflow, core samples from the Barnett reservoir that had an abundant amount of quartz and clay were used. The primary aspect of the current study is to investigate the mutual effect of the shale rock petrophysical properties and the polymer adsorption; moreover, the effect of the shale mineralogical composition on the rock prone to adsorb polymer. The effect of the non-ionic surfactant on the imbibition rates, and also the anisotropy on the rock ability for polymer adsorption were also investigated. The results of this workflow were compared to the Marcellus samples results presented in Al-Ameri et al. (2018b).\u0000 The workflow incorporates conducting three systematic imbibition experiments for a same shale core sample using brine, slickwater, and brine again. The sample brine permeability was measured before and after the imbibition experiments using a constant rate steady-state permeability setup.\u0000 The results showed that the polymer adsorption reduces the brine spontaneous imbibition volumes. Moreover, the shale petrophysical properties could dominate the polymer adsorption more than the mineralogical composition.\u0000 Adding a non-ionic surfactant to the slickwater enhanced the imbibition rate considerably into both of the Barnett and Marcellus shale samples, and that improves the fluid flowback in these shales.\u0000 The bedding planes and their orientation are among the factors that control the effect of the polymer adsorption on the fluid imbibition rate. The more obvious are the bedding planes, the higher impact of the polymer adsorption on the fluid imbibition rate. However, the petrophysical properties have more effect on the shale prone to adsorb the polymer than the bedding plane orientation.\u0000 The effect of the polymer adsorption slightly increased the capillary pressure curve. However, as the porosity and permeability increase, the effect of the polymer adsorption on the capillary pressure increases. In comparison to the Eagle Ford shale, the Barnett and Marcellus shales had lower capillary pressure, and that could be one of the reasons of their higher fluid flowback. The impact of the polymer adsorption on the water relative permeability was less for the Barnett sample in comparison to the Marcellus sample because of its lower porosity and permeability.","PeriodicalId":298489,"journal":{"name":"Day 4 Wed, October 10, 2018","volume":"8 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-10-07","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"126312148","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 ability of degradable fibers to reduce the settling rate of ceramic proppant in a guar-based solution was studied as a function of fiber composition and shape. Various cellulose ester fibers were benchmarked against a PLA standard. Aqueous (2 wt% KCl in DI water) mixtures of degradable fiber, ceramic proppant, and guar were consistently mixed then allowed to settle. The position of the interface between the solids-rich bottom layer and solids-poor top layer was measured as a function of time for various fiber compositions, shapes, and loadings. Settling experiments were also repeated to determine measurement error. Viscosity measurements were performed both to determine appropriate guar loading and to investigate the effect of fibers on viscosity. Consistent with recent results published in the patent literature for PLA, fiber shape was found to have a strong effect on proppant suspension. However, these effects went well beyond those found for aspect ratio and degree of crimping reported previously. Indeed, fiber cross-sectional shape was found to have a very strong effect with "X" and trilobal shapes showing better proppant suspension capability than round fibers. Fiber loading with shaped fibers could be reduced up to half of that round fibers with the same proppant suspension performance. The degradable polymer composition may play some role in proppant suspension but it appears to be secondary relative to that of fiber shape. Degradable fibers with improved performance should enable broader consideration of their use for proppant transport, proppant suspension, and heterogeneous proppant placement in fiber-based hydraulic fracturing. Other stimulation applications may also value alternative degradable materials.
{"title":"Effect of Degradable Fiber Composition and Shape on Proppant Suspension","authors":"N. A. Collins, R. Grim, Koushik Ghosh, J. Dorgan","doi":"10.2118/191821-18ERM-MS","DOIUrl":"https://doi.org/10.2118/191821-18ERM-MS","url":null,"abstract":"\u0000 The ability of degradable fibers to reduce the settling rate of ceramic proppant in a guar-based solution was studied as a function of fiber composition and shape. Various cellulose ester fibers were benchmarked against a PLA standard.\u0000 Aqueous (2 wt% KCl in DI water) mixtures of degradable fiber, ceramic proppant, and guar were consistently mixed then allowed to settle. The position of the interface between the solids-rich bottom layer and solids-poor top layer was measured as a function of time for various fiber compositions, shapes, and loadings. Settling experiments were also repeated to determine measurement error. Viscosity measurements were performed both to determine appropriate guar loading and to investigate the effect of fibers on viscosity.\u0000 Consistent with recent results published in the patent literature for PLA, fiber shape was found to have a strong effect on proppant suspension. However, these effects went well beyond those found for aspect ratio and degree of crimping reported previously. Indeed, fiber cross-sectional shape was found to have a very strong effect with \"X\" and trilobal shapes showing better proppant suspension capability than round fibers. Fiber loading with shaped fibers could be reduced up to half of that round fibers with the same proppant suspension performance. The degradable polymer composition may play some role in proppant suspension but it appears to be secondary relative to that of fiber shape.\u0000 Degradable fibers with improved performance should enable broader consideration of their use for proppant transport, proppant suspension, and heterogeneous proppant placement in fiber-based hydraulic fracturing. Other stimulation applications may also value alternative degradable materials.","PeriodicalId":298489,"journal":{"name":"Day 4 Wed, October 10, 2018","volume":"15 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-10-07","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"115360204","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}
Traditionally, in order to estimate the production potential at a new, prospective field site via simulation or material balance, one needs to collect various forms of expensive field data and/or make assumptions about the nature of the formation at that site. Decline curve analysis would not be applicable in this scenario, as producing wells need to pre-exist in the target field. The objective of our work is to make first-order forecasts of production rates at prospective, undrilled sites using only production data from existing wells in the entire play. This is accomplished through co-kriging of decline curve parameter values, where the parameter values are obtained at each existing well by fitting an appropriate decline model to the production history. Co-kriging gives the best linear unbiased prediction of parameter values at undrilled locations, and also estimates uncertainty in those predictions. Thus, we can obtain production forecasts at P10, P50, and P90, as well as calculate EUR at those same levels, across the spatial domain of the play. To demonstrate the proposed methodology, we used monthly gas flow rates and well locations from the Marcellus shale gas play in this research. Looking only at horizontal and directional wells, the gas production rates at each well were carefully filtered and screened. Also, we normalized the rates by perforation interval length. We kept only production histories of 24 months or longer in duration to ensure good decline curve fits. Ultimately, we were left with 5,637 production records. Here, we chose Duong’s decline model to represent production decline in this shale gas play, and fitting of this decline curve was accomplished through ordinary least square regression. Interpolation was done by universal co-kriging with consideration to correlate the four parameters in Duongs’ model, which also showed a linear trend (the parameters show dependency on the x and y spatial coordinates). Kriging gave us the optimal decline curve coefficients at new locations (P50 curve), as well as the variance in these coefficient estimates (used to establish P10 and P90 curves). We were also able to map EUR across the study area. Finally, the co-kriging model was cross-validated with leave-one-out scheme, which showed significant but not unreasonable error in decline curve coefficient prediction. We forecasted potential gas production in the study area using co-kriging. Heat maps of decline curve parameters as well as EUR were constructed to give operators a big picture of the production potential in the play. The methods proposed are easy to implement and do not require various expensive data like permeability, bottom hole pressure, etc., giving operators a risk-based analysis of prospective sites. We also made this analysis available to the public in a user-friendly web app.
{"title":"Combining Decline Curve Analysis and Geostatistics to Forecast Gas Production in the Marcellus Shale","authors":"Zhenke Xi, E. Morgan","doi":"10.2118/191793-18ERM-MS","DOIUrl":"https://doi.org/10.2118/191793-18ERM-MS","url":null,"abstract":"\u0000 Traditionally, in order to estimate the production potential at a new, prospective field site via simulation or material balance, one needs to collect various forms of expensive field data and/or make assumptions about the nature of the formation at that site. Decline curve analysis would not be applicable in this scenario, as producing wells need to pre-exist in the target field. The objective of our work is to make first-order forecasts of production rates at prospective, undrilled sites using only production data from existing wells in the entire play. This is accomplished through co-kriging of decline curve parameter values, where the parameter values are obtained at each existing well by fitting an appropriate decline model to the production history. Co-kriging gives the best linear unbiased prediction of parameter values at undrilled locations, and also estimates uncertainty in those predictions. Thus, we can obtain production forecasts at P10, P50, and P90, as well as calculate EUR at those same levels, across the spatial domain of the play.\u0000 To demonstrate the proposed methodology, we used monthly gas flow rates and well locations from the Marcellus shale gas play in this research. Looking only at horizontal and directional wells, the gas production rates at each well were carefully filtered and screened. Also, we normalized the rates by perforation interval length. We kept only production histories of 24 months or longer in duration to ensure good decline curve fits. Ultimately, we were left with 5,637 production records. Here, we chose Duong’s decline model to represent production decline in this shale gas play, and fitting of this decline curve was accomplished through ordinary least square regression.\u0000 Interpolation was done by universal co-kriging with consideration to correlate the four parameters in Duongs’ model, which also showed a linear trend (the parameters show dependency on the x and y spatial coordinates). Kriging gave us the optimal decline curve coefficients at new locations (P50 curve), as well as the variance in these coefficient estimates (used to establish P10 and P90 curves). We were also able to map EUR across the study area. Finally, the co-kriging model was cross-validated with leave-one-out scheme, which showed significant but not unreasonable error in decline curve coefficient prediction.\u0000 We forecasted potential gas production in the study area using co-kriging. Heat maps of decline curve parameters as well as EUR were constructed to give operators a big picture of the production potential in the play. The methods proposed are easy to implement and do not require various expensive data like permeability, bottom hole pressure, etc., giving operators a risk-based analysis of prospective sites. We also made this analysis available to the public in a user-friendly web app.","PeriodicalId":298489,"journal":{"name":"Day 4 Wed, October 10, 2018","volume":"6 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-10-07","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"128345790","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}
Feng Xu, Wei Yu, Xiangling Li, J. Miao, G. Zhao, K. Sepehrnoori, Xianbin Li, Jianli Jin, Guangyao Wen
Natural fractures are the main producibility factor in the weathered granite reservoirs (basement rock) and volcanic-rock reservoirs. Production practices show that these reservoirs could have high production rate, but the difference of well productivity between single wells is obvious. These reservoirs have complex natural fractures oriented at medium-high angles, which could bring high complexity and heterogeneity to the reservoirs, adding anisotropy to reservoir permeability. It is very hard to effectively simulate complex fractures in naturally fractured reservoirs and study the applicability of different well type and well pattern by using common reservoir simulators. A fast EDFM (Embedded Discrete Fracture Model) method was put forward for production simulation of complex fractures in naturally fractured reservoirs. The EDFM processor combining commercial reservoir simulators (ECLIPSE or CMG) is fully integrated to forecast production performance of the weathered granite reservoir. With a new set of EDFM formulations, the non-neighboring connections (NNCs) in the EDFM are converted into regular connections in traditional reservoir simulators, and the NNCs factors are linked with gridblock permeabilities. So complex dynamic behaviors of natural fractures can be captured, which can maintain the accuracy of DFMs (discrete fracture models) and keep the efficiency offered by structured gridding. In this paper, a 3D model with complex natural fractures was built to model the performance of different well types and well patterns. The results show that wells with higher density of natural fractures produce higher oil production, and horizontal wells with higher density of natural fractures have larger oil production than vertical wells because horizontal wells have a larger contact area than vertical wells. What’s more, heterogeneity and anisotropy have a great effect on well pattern and well type, which need to be studied carefully in the oilfield development.
{"title":"A Fast EDFM Method for Production Simulation of Complex Fractures in Naturally Fractured Reservoirs","authors":"Feng Xu, Wei Yu, Xiangling Li, J. Miao, G. Zhao, K. Sepehrnoori, Xianbin Li, Jianli Jin, Guangyao Wen","doi":"10.2118/191800-18ERM-MS","DOIUrl":"https://doi.org/10.2118/191800-18ERM-MS","url":null,"abstract":"\u0000 Natural fractures are the main producibility factor in the weathered granite reservoirs (basement rock) and volcanic-rock reservoirs. Production practices show that these reservoirs could have high production rate, but the difference of well productivity between single wells is obvious. These reservoirs have complex natural fractures oriented at medium-high angles, which could bring high complexity and heterogeneity to the reservoirs, adding anisotropy to reservoir permeability. It is very hard to effectively simulate complex fractures in naturally fractured reservoirs and study the applicability of different well type and well pattern by using common reservoir simulators. A fast EDFM (Embedded Discrete Fracture Model) method was put forward for production simulation of complex fractures in naturally fractured reservoirs. The EDFM processor combining commercial reservoir simulators (ECLIPSE or CMG) is fully integrated to forecast production performance of the weathered granite reservoir. With a new set of EDFM formulations, the non-neighboring connections (NNCs) in the EDFM are converted into regular connections in traditional reservoir simulators, and the NNCs factors are linked with gridblock permeabilities. So complex dynamic behaviors of natural fractures can be captured, which can maintain the accuracy of DFMs (discrete fracture models) and keep the efficiency offered by structured gridding. In this paper, a 3D model with complex natural fractures was built to model the performance of different well types and well patterns. The results show that wells with higher density of natural fractures produce higher oil production, and horizontal wells with higher density of natural fractures have larger oil production than vertical wells because horizontal wells have a larger contact area than vertical wells. What’s more, heterogeneity and anisotropy have a great effect on well pattern and well type, which need to be studied carefully in the oilfield development.","PeriodicalId":298489,"journal":{"name":"Day 4 Wed, October 10, 2018","volume":"3 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-10-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"114979270","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}
T. Budney, Chirinos Jose, H. Jacot, Tim Svarczkopf
Large volume slick-water stimulations have become the de facto standard for completion strategy in the Upper Devonian, Marcellus, and Utica/Point Pleasant. Current completion optimization work has focused on optimizing stage spacing, sand loading, and injection rate which have shown increases in well productivity. One commonly overlooked variable in the design equation is stimulation fluid chemistry and rock/fluid interaction. Friction reducers, the primary additive of a slickwater system, have become a commodity with many service companies providing similar systems. Premium slickwater systems in the Marcellus are generally characterized by the ability to tolerate high percentages of produced water. We have developed an alternative approach to the design of stimulation fluid chemistry. This approach consists of creating a comprehensive laboratory workflow justification for multiple fluid combinations with consideration for specific thermal maturity windows. The laboratory workflow includes proprietary rock/ fluid interaction tests that insure formation compatibility, lever imbibition/displacement production mechanisms, insure compatibility of fluid components inclusive of available water sources, and insure optimization of the fluid based on stimulation intensity (Budney 2017) objectives. After extensive testing, a new stimulation fluid chemistry has been developed that offers several advantages verified by laboratory testing. The new stimulation fluid chemistry consists of a multifunctional additive with the following characteristics: salt tolerant, viscosifying, formation stabilizing, wettability enhancing friction reducer technology paired with a compatible scale inhibitor and biocide. This new stimulation fluid chemistry was field tested against an incumbent fluid chemistry provided by the stimulation service company. Well production data from the first multiple well experiment demonstrated the new stimulation fluid chemistry resulted in significantly improved well performance. A second multi-well experiment in a different area was conducted and proved the well performance improvement associated with the new stimulation fluid chemistry was repeatable. Economic analyses on wells from both field experiments demonstrate an excellent return on investment with the new stimulation fluid chemistry. This study highlights the importance of justifying stimulation fluid chemistry utilizing a laboratory workflow. The laboratory workflow incorporates rock/fluid interaction testing to maximize the imbibition/displacement production mechanism. The laboratory workflow must also prove that the stimulation fluid chemistry satisfies the stimulation intensity objectives of high rate, high sand concentration, and reduced fluid volumes while enabling reliable field execution.
{"title":"Optimized Rock Fluid Interaction and Stimulation Intensity Enhancement Improves Well Performance: A Marcellus Case Study","authors":"T. Budney, Chirinos Jose, H. Jacot, Tim Svarczkopf","doi":"10.2118/191798-18ERM-MS","DOIUrl":"https://doi.org/10.2118/191798-18ERM-MS","url":null,"abstract":"\u0000 Large volume slick-water stimulations have become the de facto standard for completion strategy in the Upper Devonian, Marcellus, and Utica/Point Pleasant. Current completion optimization work has focused on optimizing stage spacing, sand loading, and injection rate which have shown increases in well productivity. One commonly overlooked variable in the design equation is stimulation fluid chemistry and rock/fluid interaction. Friction reducers, the primary additive of a slickwater system, have become a commodity with many service companies providing similar systems. Premium slickwater systems in the Marcellus are generally characterized by the ability to tolerate high percentages of produced water.\u0000 We have developed an alternative approach to the design of stimulation fluid chemistry. This approach consists of creating a comprehensive laboratory workflow justification for multiple fluid combinations with consideration for specific thermal maturity windows. The laboratory workflow includes proprietary rock/ fluid interaction tests that insure formation compatibility, lever imbibition/displacement production mechanisms, insure compatibility of fluid components inclusive of available water sources, and insure optimization of the fluid based on stimulation intensity (Budney 2017) objectives. After extensive testing, a new stimulation fluid chemistry has been developed that offers several advantages verified by laboratory testing. The new stimulation fluid chemistry consists of a multifunctional additive with the following characteristics: salt tolerant, viscosifying, formation stabilizing, wettability enhancing friction reducer technology paired with a compatible scale inhibitor and biocide. This new stimulation fluid chemistry was field tested against an incumbent fluid chemistry provided by the stimulation service company. Well production data from the first multiple well experiment demonstrated the new stimulation fluid chemistry resulted in significantly improved well performance. A second multi-well experiment in a different area was conducted and proved the well performance improvement associated with the new stimulation fluid chemistry was repeatable. Economic analyses on wells from both field experiments demonstrate an excellent return on investment with the new stimulation fluid chemistry.\u0000 This study highlights the importance of justifying stimulation fluid chemistry utilizing a laboratory workflow. The laboratory workflow incorporates rock/fluid interaction testing to maximize the imbibition/displacement production mechanism. The laboratory workflow must also prove that the stimulation fluid chemistry satisfies the stimulation intensity objectives of high rate, high sand concentration, and reduced fluid volumes while enabling reliable field execution.","PeriodicalId":298489,"journal":{"name":"Day 4 Wed, October 10, 2018","volume":"59 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-10-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"130305009","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}
Drilling problems such as stick slip vibration/hole cleaning, pipe failures, loss of circulation, BHA whirl, stuck pipe incidents, excessive torque and drag, low ROP, bit wear, formation damage and borehole instability, and the drilling of highly tortuous wells have only been tackled using physics-based models. Despite the mammoth generation of real-time metadata, there is a tremendous gap between statistical based models and empirical, mathematical, and physical-based models. Data mining techniques have made prominent contributions across a broad spectrum of industries. Its value is widely appreciated in a variety of applications, but its potential has not been fully tapped in the oil and gas industry. This paper presents a review compiling several years of Data Analytics applications in the drilling operations. This review discusses the benefits, deficiencies of the present practices, challenges, and novel applications under development to overcome industry deficiencies. This study encompasses a comprehensive compilation of data mining algorithms and industry applications from a predictive analytics standpoint using supervised and unsupervised advanced analytics algorithms to identify hidden patterns and help mitigate drilling challenges. Traditional data preparation and analysis methods are not sufficiently capable of rapid information extraction and clear visualization of big complicated data sets. Due to the petroleum industry's unfulfilled demand, Machine Learning (ML)-assisted industry workflow in the fields of drilling optimization and real time parameter analysis and mitigation is presented. This paper summarizes data analytics case studies, workflows, and lessons learnt that would allow field personnel, engineers, and management to quickly interpret trends, detect failure patterns in operations, diagnose problems, and execute remedial actions to monitor and safeguard operations. The presence of such a comprehensive workflow can minimize tool failure, save millions in replacement costs and maintenance, NPV, lost production, minimize industry bias, and drive intelligent business decisions. This study will identify areas of improvement and opportunities to mitigate malpractices. Data exploitation via the proposed platform is based on well-established ML and data mining algorithms in computer sciences and statistical literature. This approach enables safe operations and handling of extremely large data bases, hence, facilitating tough decision-making processes.
{"title":"The Role of Machine Learning in Drilling Operations; A Review","authors":"C. Noshi, J. Schubert","doi":"10.2118/191823-18ERM-MS","DOIUrl":"https://doi.org/10.2118/191823-18ERM-MS","url":null,"abstract":"\u0000 Drilling problems such as stick slip vibration/hole cleaning, pipe failures, loss of circulation, BHA whirl, stuck pipe incidents, excessive torque and drag, low ROP, bit wear, formation damage and borehole instability, and the drilling of highly tortuous wells have only been tackled using physics-based models. Despite the mammoth generation of real-time metadata, there is a tremendous gap between statistical based models and empirical, mathematical, and physical-based models. Data mining techniques have made prominent contributions across a broad spectrum of industries. Its value is widely appreciated in a variety of applications, but its potential has not been fully tapped in the oil and gas industry. This paper presents a review compiling several years of Data Analytics applications in the drilling operations. This review discusses the benefits, deficiencies of the present practices, challenges, and novel applications under development to overcome industry deficiencies. This study encompasses a comprehensive compilation of data mining algorithms and industry applications from a predictive analytics standpoint using supervised and unsupervised advanced analytics algorithms to identify hidden patterns and help mitigate drilling challenges.\u0000 Traditional data preparation and analysis methods are not sufficiently capable of rapid information extraction and clear visualization of big complicated data sets. Due to the petroleum industry's unfulfilled demand, Machine Learning (ML)-assisted industry workflow in the fields of drilling optimization and real time parameter analysis and mitigation is presented.\u0000 This paper summarizes data analytics case studies, workflows, and lessons learnt that would allow field personnel, engineers, and management to quickly interpret trends, detect failure patterns in operations, diagnose problems, and execute remedial actions to monitor and safeguard operations. The presence of such a comprehensive workflow can minimize tool failure, save millions in replacement costs and maintenance, NPV, lost production, minimize industry bias, and drive intelligent business decisions. This study will identify areas of improvement and opportunities to mitigate malpractices. Data exploitation via the proposed platform is based on well-established ML and data mining algorithms in computer sciences and statistical literature. This approach enables safe operations and handling of extremely large data bases, hence, facilitating tough decision-making processes.","PeriodicalId":298489,"journal":{"name":"Day 4 Wed, October 10, 2018","volume":"4 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-10-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"123320946","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 development of shale assets has reached a point where operators face the challenge of infill drilling. The scope of this project is to investigate the impact of neighboring well pads on the performance of a newly developed well/pad. This paper highlights the differences in production performance of "old" pads versus "new" well and analyzes how the depletion history of the existing pads affects the performance of new well. The study area covers two pads: Pad A and Pad B which have 10 and 12 wells respectively; these wells have been producing since 2016 from the dry gas region of Marcellus Shale in southwestern Pennsylvania. Pad A and Pad B are more than 9000 ft apart, and the region between these two pads has potential for future development. For this project, a 3-D reservoir simulation model that includes both pads was built and calibrated to match past performance of Pad A and Pad B. The calibrated simulation model then was utilized for developing new wells. The reservoir simulation model was used to perform a sensitivity analysis on reservoir characteristics and the impact of Pad A and Pad B's depletion history on the performance of new well(s). The workflow involves optimizing the well spacing of proposed well(s) with/without considering the depletion history. Usually, with the very low permeability of shale reservoirs, the depletion history of neighboring wells is expected to affect the performance of newly developed wells. The new wells are considered as a different well pad, and their stimulated reservoir volume does not overlap with the Pad A and Pad B. However, the region average reservoir pressure is reduced due to the Pad A and Pad B production history. In most of shale reservoir numeral simulation studies, the reservoir is considered virgin. The average reservoir pressure potentially impacts the well spacing optimization workflow as well as the designing of an effective well completion job. In this study we compare two scenarios. One scenario considers the depletion history of neighboring well pads and the other one does not. The net present value optimization was done with and without considering the impact of depletion history. This project studies the effects of neighboring well pads on production performance of newly developed pad. Compared to the interaction of parent/child well in a single well pad, multi-pad studies are rare primarily because of the high computational cost associated with a multi-pad numerical simulation analysis.
{"title":"Impacts of Field Depletion on Future Infill Drilling Plans in the Marcellus Shale","authors":"A. Shahkarami, Guochang Wang, Zachary Rohland","doi":"10.2118/191789-18ERM-MS","DOIUrl":"https://doi.org/10.2118/191789-18ERM-MS","url":null,"abstract":"\u0000 The development of shale assets has reached a point where operators face the challenge of infill drilling. The scope of this project is to investigate the impact of neighboring well pads on the performance of a newly developed well/pad. This paper highlights the differences in production performance of \"old\" pads versus \"new\" well and analyzes how the depletion history of the existing pads affects the performance of new well.\u0000 The study area covers two pads: Pad A and Pad B which have 10 and 12 wells respectively; these wells have been producing since 2016 from the dry gas region of Marcellus Shale in southwestern Pennsylvania. Pad A and Pad B are more than 9000 ft apart, and the region between these two pads has potential for future development. For this project, a 3-D reservoir simulation model that includes both pads was built and calibrated to match past performance of Pad A and Pad B. The calibrated simulation model then was utilized for developing new wells. The reservoir simulation model was used to perform a sensitivity analysis on reservoir characteristics and the impact of Pad A and Pad B's depletion history on the performance of new well(s). The workflow involves optimizing the well spacing of proposed well(s) with/without considering the depletion history.\u0000 Usually, with the very low permeability of shale reservoirs, the depletion history of neighboring wells is expected to affect the performance of newly developed wells. The new wells are considered as a different well pad, and their stimulated reservoir volume does not overlap with the Pad A and Pad B. However, the region average reservoir pressure is reduced due to the Pad A and Pad B production history. In most of shale reservoir numeral simulation studies, the reservoir is considered virgin. The average reservoir pressure potentially impacts the well spacing optimization workflow as well as the designing of an effective well completion job. In this study we compare two scenarios. One scenario considers the depletion history of neighboring well pads and the other one does not. The net present value optimization was done with and without considering the impact of depletion history.\u0000 This project studies the effects of neighboring well pads on production performance of newly developed pad. Compared to the interaction of parent/child well in a single well pad, multi-pad studies are rare primarily because of the high computational cost associated with a multi-pad numerical simulation analysis.","PeriodicalId":298489,"journal":{"name":"Day 4 Wed, October 10, 2018","volume":"6 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-10-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"121574378","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}
Perforation parameters have a great influence on the performance of the multi-stage fracturing horizontal wells in tight oil reservoirs. Optimizing perforation cluster parameters is able to solve many detrimental issues, including many null perforation clusters without the produced oil, the unevenly distributed output in each stage along horizontal wells, and no complex fracture network always created near the fractured wellbore. To achieve the better performance of the volume fracturing, a practical integrated approach is proposed to optimize perforation cluster parameters. First, based on the good logging data, we establish an evaluation method for the fracability and reservoir properties to select the perforation interval. Second, a mathematical model based on the stress shadow and hydraulic fracture propagation are proposed to optimize the cluster spacing and cluster parameters within each cluster in the same stage, and the un-uniform cluster spacing and perforation number in each cluster are studied. Finally, a case well is successfully conducted with the proposed approach in the tight oil reservoir. Results show that i) the lateral with higher fracability index and property index can be treated as perforation intervals; ii) the un-uniform perforation cluster spacing and the uneven perforation number can obtain a more uniform fracture propagation morphology. The approach can better prevent the generation of ineffective perforation clusters and obtain more complex fracture networks and a better SRV. This also guides to design completion strategy and improves the economic benefits.
{"title":"An Integrated Approach to Optimize Perforation Cluster Parameters for Horizontal Wells in Tight Oil Reservoirs","authors":"Yu Lu, Haitao Li, Cong Lu, Chang Liu, Zhangxin Chen","doi":"10.2118/191790-18ERM-MS","DOIUrl":"https://doi.org/10.2118/191790-18ERM-MS","url":null,"abstract":"\u0000 Perforation parameters have a great influence on the performance of the multi-stage fracturing horizontal wells in tight oil reservoirs. Optimizing perforation cluster parameters is able to solve many detrimental issues, including many null perforation clusters without the produced oil, the unevenly distributed output in each stage along horizontal wells, and no complex fracture network always created near the fractured wellbore. To achieve the better performance of the volume fracturing, a practical integrated approach is proposed to optimize perforation cluster parameters. First, based on the good logging data, we establish an evaluation method for the fracability and reservoir properties to select the perforation interval. Second, a mathematical model based on the stress shadow and hydraulic fracture propagation are proposed to optimize the cluster spacing and cluster parameters within each cluster in the same stage, and the un-uniform cluster spacing and perforation number in each cluster are studied. Finally, a case well is successfully conducted with the proposed approach in the tight oil reservoir. Results show that i) the lateral with higher fracability index and property index can be treated as perforation intervals; ii) the un-uniform perforation cluster spacing and the uneven perforation number can obtain a more uniform fracture propagation morphology. The approach can better prevent the generation of ineffective perforation clusters and obtain more complex fracture networks and a better SRV. This also guides to design completion strategy and improves the economic benefits.","PeriodicalId":298489,"journal":{"name":"Day 4 Wed, October 10, 2018","volume":"455 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-10-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"121095316","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}
During the hydraulic fracturing process, the rough surface of fractures and the viscous proppant suspension flow bring great challenges to the distribution of proppants evenly at the fracture thin apertures. As a result, a detailed understanding of the effect of surface roughness on proppant sedimentation seems essentially indispensable. Apart from that, how the roughness of Nano-scale conduits and their orientations, such as microfracture channels, affect the flow through the damaged fracture process zone (FPZ) have not been well understood. A newfangled developed algorithm using image analysis software (ImageJ) is applied to characterize the morphological features of the damaged fracture system, including surface roughness, microcrack types and microcrack density indicators. Hydraulic fracturing experiment is conducted on a Tennessee sandstone core using a triaxial loading system. The fractured samples are ion milled, and its cross section plane images are recorded by scanning electron microscope (SEM). Statistical analysis of surface roughness, the degree of damage at FPZ, the density of microcracks and effective connection indicator of microfractures to the main fracture are quantitatively investigated, in addition to Young's modulus and Poisson's ratio. We found that the higher roughness of microfracture network significantly enhances the effective conduits open to fluid flow while taking the density of the microfracture within FPZ into account within the fracture processed region, depending upon how much damage is presented. In other words, the overall ease of fluid delivery to the main fracture essentially depends on the level of the damage in FPZ. The heavily deformed rock grains cause a partial blockage at the fracture surface and will be detached on the main fracture. The leftover is the induced intercrystalline microfracture network in the vicinity of the main fracture. Additionally, mechanical moduli were interpreted by image analysis, where a novel approach was developed to calculate the mechanical rock properties. The results from image analysis were compared to other failure criteria and fracturing pressure data interpretation. We also validated the obtained mechanical properties by collating the literature records. The microfracture network creates the significant incremental amount of fluid conduits to hydrocarbons. The better understanding of the fracture network serves as a valuable guide to the fracturing job design and managing the damaged FPZ. This novel approach will commit to supporting the lab measurements, gives field preliminary mechanical property assessment and lower the cost needed for hydraulic fracturing design.
{"title":"Quantification of Fracture Surface Roughness and Its Insights to Mechanical Rock Properties Determination Using Image Analysis Techniques","authors":"Yiwen Gong, Ilham El-monier","doi":"10.2118/191824-18ERM-MS","DOIUrl":"https://doi.org/10.2118/191824-18ERM-MS","url":null,"abstract":"\u0000 During the hydraulic fracturing process, the rough surface of fractures and the viscous proppant suspension flow bring great challenges to the distribution of proppants evenly at the fracture thin apertures. As a result, a detailed understanding of the effect of surface roughness on proppant sedimentation seems essentially indispensable. Apart from that, how the roughness of Nano-scale conduits and their orientations, such as microfracture channels, affect the flow through the damaged fracture process zone (FPZ) have not been well understood.\u0000 A newfangled developed algorithm using image analysis software (ImageJ) is applied to characterize the morphological features of the damaged fracture system, including surface roughness, microcrack types and microcrack density indicators. Hydraulic fracturing experiment is conducted on a Tennessee sandstone core using a triaxial loading system. The fractured samples are ion milled, and its cross section plane images are recorded by scanning electron microscope (SEM). Statistical analysis of surface roughness, the degree of damage at FPZ, the density of microcracks and effective connection indicator of microfractures to the main fracture are quantitatively investigated, in addition to Young's modulus and Poisson's ratio.\u0000 We found that the higher roughness of microfracture network significantly enhances the effective conduits open to fluid flow while taking the density of the microfracture within FPZ into account within the fracture processed region, depending upon how much damage is presented. In other words, the overall ease of fluid delivery to the main fracture essentially depends on the level of the damage in FPZ. The heavily deformed rock grains cause a partial blockage at the fracture surface and will be detached on the main fracture. The leftover is the induced intercrystalline microfracture network in the vicinity of the main fracture. Additionally, mechanical moduli were interpreted by image analysis, where a novel approach was developed to calculate the mechanical rock properties. The results from image analysis were compared to other failure criteria and fracturing pressure data interpretation. We also validated the obtained mechanical properties by collating the literature records.\u0000 The microfracture network creates the significant incremental amount of fluid conduits to hydrocarbons. The better understanding of the fracture network serves as a valuable guide to the fracturing job design and managing the damaged FPZ. This novel approach will commit to supporting the lab measurements, gives field preliminary mechanical property assessment and lower the cost needed for hydraulic fracturing design.","PeriodicalId":298489,"journal":{"name":"Day 4 Wed, October 10, 2018","volume":"245 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2018-10-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"127844249","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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