Parent-child relationship is becoming a topic of high interest in the Permian Basin as more infill wells are being drilled at various times after the parent well has been produced. This paper uses an advanced modelling workflow to determine the impact of parent depletion on infill well spacing at various periods of the parent well production. As the parent well is being produced, constant well spacing based on virgin condition becomes problematic because pressure depletion around the well leads to change in stress magnitude and orientations. This change in reservoir conditions, is critical for planning infill well. Parent well depletion results in potential negative impact including: –Asymmetric fracture propagation from the child well into the depleted area around the parent well–Potential detrimental fracturing hits to the parent well These effects would potentially impair the production performance of both parent and infill wells, further reducing the overall pad efficiency of the pad completions. Parent well behavior is simulated using an unconventional fracture model (UFM), and the model is calibrated with available treating data. The resulting hydraulic fracture uses an advanced unstructured gridding algorithm that accounts for a fine complex fracture network along the lateral. A high-resolution, numerical reservoir simulator that combines the unstructured grid, rock physics, and reservoir fluid data is then used to match historical production data. The reservoir pressure depletion profile at various timesteps (6, 12, 24, and 36 months) is used as an input to calculate the resulting stress field state via a finite element model. The resulting updated geomechanical properties are used to simulate the infill well hydraulic fracture geometries at various spacing; subsequent unstructured grids are created and used to forecast production. Results are then compared to quantify the impact of depletion. –Initial reservoir pressure and horizontal stress reduce progressively with increasing time of production of the parent well; the average minimum stress change in the stimulated area reaches 18% decrease after 36 months of parent production.–Hydraulic fractures of infill wells grow preferentially towards the adjacent depleted area, reducing fracture extension in virgin rock by more than 60%.–Parent well depletion impacts fracture geometry and production performance of child wells.–Wells closer to the parent are more affected with increasing depletion time; these wells see up to 50% in production reduction as compared to the parent well.–At larger well spacing, little impact is observed due to limited interference between wells.–To help mitigate the impact of parent depletion on infill wells, an innovative spacing scheme that consists of using varying spacing on infill wells closest to the depleted parent well can be used. For this study and with current reservoir properties and completion design, if the parent well has been produced for less t
{"title":"Time Dependent Depletion of Parent Well and Impact on Well Spacing in the Wolfcamp Delaware Basin","authors":"Cyrille Defeu, Giselle Garcia Ferrer, Efe Ejofodomi, Dan Shan, Farhan Alimahomed","doi":"10.2118/191799-MS","DOIUrl":"https://doi.org/10.2118/191799-MS","url":null,"abstract":"\u0000 Parent-child relationship is becoming a topic of high interest in the Permian Basin as more infill wells are being drilled at various times after the parent well has been produced. This paper uses an advanced modelling workflow to determine the impact of parent depletion on infill well spacing at various periods of the parent well production.\u0000 As the parent well is being produced, constant well spacing based on virgin condition becomes problematic because pressure depletion around the well leads to change in stress magnitude and orientations. This change in reservoir conditions, is critical for planning infill well.\u0000 Parent well depletion results in potential negative impact including: –Asymmetric fracture propagation from the child well into the depleted area around the parent well–Potential detrimental fracturing hits to the parent well\u0000 These effects would potentially impair the production performance of both parent and infill wells, further reducing the overall pad efficiency of the pad completions.\u0000 Parent well behavior is simulated using an unconventional fracture model (UFM), and the model is calibrated with available treating data. The resulting hydraulic fracture uses an advanced unstructured gridding algorithm that accounts for a fine complex fracture network along the lateral. A high-resolution, numerical reservoir simulator that combines the unstructured grid, rock physics, and reservoir fluid data is then used to match historical production data. The reservoir pressure depletion profile at various timesteps (6, 12, 24, and 36 months) is used as an input to calculate the resulting stress field state via a finite element model. The resulting updated geomechanical properties are used to simulate the infill well hydraulic fracture geometries at various spacing; subsequent unstructured grids are created and used to forecast production. Results are then compared to quantify the impact of depletion. –Initial reservoir pressure and horizontal stress reduce progressively with increasing time of production of the parent well; the average minimum stress change in the stimulated area reaches 18% decrease after 36 months of parent production.–Hydraulic fractures of infill wells grow preferentially towards the adjacent depleted area, reducing fracture extension in virgin rock by more than 60%.–Parent well depletion impacts fracture geometry and production performance of child wells.–Wells closer to the parent are more affected with increasing depletion time; these wells see up to 50% in production reduction as compared to the parent well.–At larger well spacing, little impact is observed due to limited interference between wells.–To help mitigate the impact of parent depletion on infill wells, an innovative spacing scheme that consists of using varying spacing on infill wells closest to the depleted parent well can be used. For this study and with current reservoir properties and completion design, if the parent well has been produced for less t","PeriodicalId":11155,"journal":{"name":"Day 2 Thu, September 06, 2018","volume":"109 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-09-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85385425","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}
E. Bruesewitz, J. Iriarte, J. Mazza, Carrie Glaser, E. Marshall, Scott H. Brooks
A horizontal well landed in a single formation rarely encounters homogeneous rock from the heel to the toe of the wellbore. When analyzing treatment responses that occur during hydraulic fracturing, a decreasing trend in surface treating pressure in sequential stages is typically attributed to reduced friction within the casing or frac string. However, there are several variances in treating pressure that are not readily explained by examining the surface pressures and pipe friction in isolation. These variances are also apparent when looking at bottom hole injectivity. Combining surface data and geomechanical data quickly reveals the degree of variability in rock properties along a lateral and the impact that variability can have on a completion, leading to a more optimal design. This paper demonstrates how engineers can take advantage of their most detailed completions and geomechanical data by looking for trends arising from past detailed treatment analyses and applying that gained knowledge to future completions. This study relies on the analysis of proprietary high-resolution geomechanical data derived from the processing of accelerations measured at the drillbit and high-frequency fracture treatment data recorded at one-second intervals. The data were standardized to a common format, screened for quality control, normalized, and analyzed using a data management platform. The methodology combines critical mechanical rock properties such as Young's Modulus, and Poisson's ratio with high-frequency fracture treatment data, including treating pressures, rates, and fluid and proppant volumes. Further application of the geomechanical data to derive brittleness allows for construction of a more predictive petromechanical model to optimize completion approaches. A brief analysis of past completions indicated virtually no correlation between gamma ray measurements along the stage and fracture treating conditions. However, when evaluating high-resolution mechanical rock properties along the lateral, a much more useful correlation exists between minimum horizontal stress variations (calculated from Poisson's Ratio) and eventual treating pressure and proppant placement difficulties. Calculated brittleness and bottomhole injectivity (which accounts for changes in slurry rate and pipe friction) also show a relationship, especially when cluster efficiency factors are included. This study of six Eagle Ford wells suggests that rock properties are the dominant variables affecting fracture treatment pressure and bottomhole injectivity. This method can be used to predict trouble stages, improve operational efficiencies, and optimize proppant placement. This paper proposes a process to improve completion efficiency while demonstrating the value of information contained in high-resolution and high-frequency datasets. Historically underutilized, these datasets are playing an increasingly prevalent role in advanced analytics due to improved and novel technolog
在单一地层中钻井的水平井很少会遇到从井筒跟部到趾部的均质岩石。在分析水力压裂过程中发生的处理响应时，地面处理压力在连续阶段呈下降趋势，这通常归因于套管或压裂管柱内部摩擦的减少。然而，在处理压力时存在一些差异，这些差异不容易通过单独检查表面压力和管道摩擦来解释。在观察井底注入能力时，这些差异也很明显。结合地面数据和地质力学数据，可以快速揭示沿水平段岩石性质的变化程度，以及这种变化对完井作业的影响，从而实现更优化的设计。本文展示了工程师如何利用他们最详细的完井和地质力学数据，从过去的详细处理分析中寻找趋势，并将所获得的知识应用于未来的完井。该研究依赖于对高分辨率地质力学数据的分析，这些数据来自于对钻头上测量的加速度和每隔一秒记录的高频压裂数据的处理。数据被标准化为通用格式，经过质量控制筛选，规范化，并使用数据管理平台进行分析。该方法结合了关键的岩石力学特性，如杨氏模量和泊松比，以及高频压裂数据，包括处理压力、速率、流体和支撑剂体积。进一步应用地质力学数据来推导脆性，可以建立更具预测性的岩石力学模型，以优化完井方法。对以往完井作业的简要分析表明，压裂段的伽马射线测量值与压裂处理条件之间几乎没有相关性。然而，当评估沿侧向的高分辨率岩石力学特性时，最小水平应力变化(由泊松比计算)与最终处理压力和支撑剂放置困难之间存在更有用的相关性。计算出的脆性和井底注入能力(考虑泥浆速率和管柱摩擦力的变化)也显示出相关性，特别是在考虑簇效率因素时。对Eagle Ford 6口井的研究表明，岩石性质是影响压裂压力和井底注入能力的主要变量。该方法可用于预测故障阶段，提高作业效率，并优化支撑剂的放置。本文提出了一个提高完井效率的过程，同时展示了高分辨率和高频数据集中包含的信息的价值。由于数据管理和解释的改进和新技术，这些数据集在高级分析中发挥着越来越普遍的作用。这个过程有助于提出更好的问题，并根据真实数据改进关键决策。
{"title":"Integrating Rock Properties and Fracture Treatment Data to Optimize Completions Design","authors":"E. Bruesewitz, J. Iriarte, J. Mazza, Carrie Glaser, E. Marshall, Scott H. Brooks","doi":"10.2118/191768-MS","DOIUrl":"https://doi.org/10.2118/191768-MS","url":null,"abstract":"\u0000 A horizontal well landed in a single formation rarely encounters homogeneous rock from the heel to the toe of the wellbore. When analyzing treatment responses that occur during hydraulic fracturing, a decreasing trend in surface treating pressure in sequential stages is typically attributed to reduced friction within the casing or frac string. However, there are several variances in treating pressure that are not readily explained by examining the surface pressures and pipe friction in isolation. These variances are also apparent when looking at bottom hole injectivity. Combining surface data and geomechanical data quickly reveals the degree of variability in rock properties along a lateral and the impact that variability can have on a completion, leading to a more optimal design. This paper demonstrates how engineers can take advantage of their most detailed completions and geomechanical data by looking for trends arising from past detailed treatment analyses and applying that gained knowledge to future completions.\u0000 This study relies on the analysis of proprietary high-resolution geomechanical data derived from the processing of accelerations measured at the drillbit and high-frequency fracture treatment data recorded at one-second intervals. The data were standardized to a common format, screened for quality control, normalized, and analyzed using a data management platform. The methodology combines critical mechanical rock properties such as Young's Modulus, and Poisson's ratio with high-frequency fracture treatment data, including treating pressures, rates, and fluid and proppant volumes. Further application of the geomechanical data to derive brittleness allows for construction of a more predictive petromechanical model to optimize completion approaches.\u0000 A brief analysis of past completions indicated virtually no correlation between gamma ray measurements along the stage and fracture treating conditions. However, when evaluating high-resolution mechanical rock properties along the lateral, a much more useful correlation exists between minimum horizontal stress variations (calculated from Poisson's Ratio) and eventual treating pressure and proppant placement difficulties. Calculated brittleness and bottomhole injectivity (which accounts for changes in slurry rate and pipe friction) also show a relationship, especially when cluster efficiency factors are included. This study of six Eagle Ford wells suggests that rock properties are the dominant variables affecting fracture treatment pressure and bottomhole injectivity. This method can be used to predict trouble stages, improve operational efficiencies, and optimize proppant placement.\u0000 This paper proposes a process to improve completion efficiency while demonstrating the value of information contained in high-resolution and high-frequency datasets. Historically underutilized, these datasets are playing an increasingly prevalent role in advanced analytics due to improved and novel technolog","PeriodicalId":11155,"journal":{"name":"Day 2 Thu, September 06, 2018","volume":"202 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-09-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78121480","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}
Ryan A. Hassen, D. S. Fulford, Clayton T. Burrows, G. Starley
Engineers and leaders who must decide on development strategies for unconventional resource projects face a challenging design problem. While we must make decisions on well and completion design, including well-spacing in three-dimensions, the complexity of the physical system and the interactions between these parameters can become overwhelming. The technical optimization problem can be difficult; however, asking the right questions can make the business decision clearer than it first appears. The typical approach to design optimization problems is to build models, with a tendency toward including an ever-increasing number of parameters to describe the system in exhaustive detail. However, our uncertainty in the model parameters often makes it impossible to identify the true optimum. In this work, we focus instead on reducing the number of model parameters and capturing the impact of these critical uncertainties on our business decisions. This allows us to answer the right questions in order to define and choose the best well-spacing strategy. For well-spacing optimization, a critical uncertainty is the relationship between the chosen well-spacing and the potential well-performance degradation, in terms of estimated ultimate recovery (EUR) and initial production (IP). Rather than attempting to describe fracture geometry and well interference from a mechanistic standpoint, we introduce a lumped parameter, the shared reservoir (SR) factor, to account for this complex relationship. The parameter distribution may be calibrated to (a) well results in a play, (b) well results in carefully selected analogue plays, or (c) simulated well results from probabilistic analyses. An example of a Monte-Carlo simulation using the uncertainty of the SR factor, as well as the mean EUR and IP, highlights the utility of the method. We also illustrate how the spacing decision impacts key risk and financial metrics, including the expected monetary value of the project, the probability of regretting the decision, and the probability of commercial success of the project. The shared reservoir factor is proposed to capture the complex relationships between the well-spacing decision and the EUR and IP that result from this decision. Using the shared reservoir factor, we can develop simple stochastic models to clarify an otherwise frustratingly complex optimization problem.
{"title":"Decision-Focused Optimization: Asking the Right Questions About Well-Spacing","authors":"Ryan A. Hassen, D. S. Fulford, Clayton T. Burrows, G. Starley","doi":"10.2118/191783-MS","DOIUrl":"https://doi.org/10.2118/191783-MS","url":null,"abstract":"\u0000 Engineers and leaders who must decide on development strategies for unconventional resource projects face a challenging design problem. While we must make decisions on well and completion design, including well-spacing in three-dimensions, the complexity of the physical system and the interactions between these parameters can become overwhelming. The technical optimization problem can be difficult; however, asking the right questions can make the business decision clearer than it first appears.\u0000 The typical approach to design optimization problems is to build models, with a tendency toward including an ever-increasing number of parameters to describe the system in exhaustive detail. However, our uncertainty in the model parameters often makes it impossible to identify the true optimum. In this work, we focus instead on reducing the number of model parameters and capturing the impact of these critical uncertainties on our business decisions. This allows us to answer the right questions in order to define and choose the best well-spacing strategy.\u0000 For well-spacing optimization, a critical uncertainty is the relationship between the chosen well-spacing and the potential well-performance degradation, in terms of estimated ultimate recovery (EUR) and initial production (IP). Rather than attempting to describe fracture geometry and well interference from a mechanistic standpoint, we introduce a lumped parameter, the shared reservoir (SR) factor, to account for this complex relationship. The parameter distribution may be calibrated to (a) well results in a play, (b) well results in carefully selected analogue plays, or (c) simulated well results from probabilistic analyses. An example of a Monte-Carlo simulation using the uncertainty of the SR factor, as well as the mean EUR and IP, highlights the utility of the method. We also illustrate how the spacing decision impacts key risk and financial metrics, including the expected monetary value of the project, the probability of regretting the decision, and the probability of commercial success of the project.\u0000 The shared reservoir factor is proposed to capture the complex relationships between the well-spacing decision and the EUR and IP that result from this decision. Using the shared reservoir factor, we can develop simple stochastic models to clarify an otherwise frustratingly complex optimization problem.","PeriodicalId":11155,"journal":{"name":"Day 2 Thu, September 06, 2018","volume":"13 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-09-05","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"84185760","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}
Leonid Vigderman, A. Bogdan, Lingjuan Shen, D. Heller, Tony Yeung, Diankui Fu
Fracture geometry control and increased fracture complexity have been recognized to be critical factors in optimizing unconventional well completion design as well as preventing detrimental frac hits. A major challenge of far-field diversion in slickwater fracturing is ensuring transport of material to the fracture tip or secondary fracture in a low-viscosity fluid. This paper will present a novel far-field diverter system for fracturing with low-viscosity fluids to address these challenges composed of an engineered mixture of unique ultra-lightweight proppant and degradable material. Not only can the system effectively divert fracturing to control fracture geometry and enforce complexity, but will also maintain fracture conductivity. Several types of tests were performed to determine the effectiveness and optimize the design of the far-field diverter system. First, a series of slot plugging tests were carried out to optimize diversion performance of the system by blocking fluid flow through targeted fracture widths while maintaining flow through the larger portions of a fracture. Next, the diverter was pumped through a flow apparatus to demonstrate its far-field transportability in low-viscosity fluids. Finally, conductivity of the diverter system after degradation was tested. The new far-field diverter system was designed to create a permeability barrier at the fracture tip to contain fracture length growth as well as to be used in the middle of a stage to control growth of secondary/tertiary fractures to allow redistribution of fracturing fluid within the rock to further increase complexity. Lab tests demonstrated that by controlling the particle size of the engineered proppant and diverter mixture, the diverter system can be tailored to plug different fracture widths. Significantly, flow tests using a low-viscosity, slickwater fluid demonstrated the excellent transport properties and limited settling rate of the diverter. Finally, conductivity tests showed that by using an engineered mixture of non-degradable, ultra-lightweight proppant and degradable material, conductivity in the fracture is maintained after particle degradation, which is critical when applied in the middle of a stage to increase fracture complexity. To the authors’ knowledge, this is the first published paper of a far-field diverter that is optimized for slickwater fracturing for both fracture geometry and complexity control. The new diverter technology overcomes the significant limitations of other available systems such as fracture closure, inadequate transport to the far field, or the requirement to use high viscosity fluids.
{"title":"Far-Field Diversion System Designed for Slickwater Fracturing","authors":"Leonid Vigderman, A. Bogdan, Lingjuan Shen, D. Heller, Tony Yeung, Diankui Fu","doi":"10.2118/191769-MS","DOIUrl":"https://doi.org/10.2118/191769-MS","url":null,"abstract":"\u0000 Fracture geometry control and increased fracture complexity have been recognized to be critical factors in optimizing unconventional well completion design as well as preventing detrimental frac hits. A major challenge of far-field diversion in slickwater fracturing is ensuring transport of material to the fracture tip or secondary fracture in a low-viscosity fluid. This paper will present a novel far-field diverter system for fracturing with low-viscosity fluids to address these challenges composed of an engineered mixture of unique ultra-lightweight proppant and degradable material. Not only can the system effectively divert fracturing to control fracture geometry and enforce complexity, but will also maintain fracture conductivity.\u0000 Several types of tests were performed to determine the effectiveness and optimize the design of the far-field diverter system. First, a series of slot plugging tests were carried out to optimize diversion performance of the system by blocking fluid flow through targeted fracture widths while maintaining flow through the larger portions of a fracture. Next, the diverter was pumped through a flow apparatus to demonstrate its far-field transportability in low-viscosity fluids. Finally, conductivity of the diverter system after degradation was tested.\u0000 The new far-field diverter system was designed to create a permeability barrier at the fracture tip to contain fracture length growth as well as to be used in the middle of a stage to control growth of secondary/tertiary fractures to allow redistribution of fracturing fluid within the rock to further increase complexity. Lab tests demonstrated that by controlling the particle size of the engineered proppant and diverter mixture, the diverter system can be tailored to plug different fracture widths. Significantly, flow tests using a low-viscosity, slickwater fluid demonstrated the excellent transport properties and limited settling rate of the diverter. Finally, conductivity tests showed that by using an engineered mixture of non-degradable, ultra-lightweight proppant and degradable material, conductivity in the fracture is maintained after particle degradation, which is critical when applied in the middle of a stage to increase fracture complexity.\u0000 To the authors’ knowledge, this is the first published paper of a far-field diverter that is optimized for slickwater fracturing for both fracture geometry and complexity control. The new diverter technology overcomes the significant limitations of other available systems such as fracture closure, inadequate transport to the far field, or the requirement to use high viscosity fluids.","PeriodicalId":11155,"journal":{"name":"Day 2 Thu, September 06, 2018","volume":"77 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-08-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"75990576","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}
Fracture networks present a critical influence on to better assess oil recovery and to optimize production of hydraulically fractured reservoirs. We established a novel workflow for fracture uncertainty analysis and prediction, in which multiple fracture pattern realizations are created from the geostatistical analysis. The original fracture networks were created using geomechanics tools. Then the fracture network is reconstrued for uncertainty analysis and history matching. For different realizations of the fracture distributions created in this workflow, we successfully maintain the continuity of the fractures, as well as the connections from the matrix to fractures. The generated grid can be further used for treatment simulation to determine fractures geometry, height growth and respected proppant transport in the induced fracture network. In this paper, we also apply Embedded Discrete Fracture Model (EDFM) to capture the realistic geometry of fractures. Within the EDFM, each fracture plane is embedded inside the matrix grid and is discretized by the cell boundaries. We study a series of reservoir simulation realizations, in which the complex hydraulic fracture networks are created in the workflow. We investigate different fracture realizations in both planar and complex fracture configurations while maintaining the continuity within the fracture networks. This study also includes the influence of the network geometry and fractures properties on the overall performance of the reservoir. From the uncertainty analysis results, we find that the overall reservoir performance is controlled by the fracture connectivity and the distribution of conductivity within the network. A good match of production history can be achieved by adjusting the fracture connectivity. Modeling with multiple realizations of fracture networks acknowledge that a reliable production forecast is achievable using geostatistical analysis for fracture connection reconstructions. Applying Embedded Discrete Fracture Model (EDFM) on the fracture-related model simulation provides a robust and effective means of investigating multiple fracture realizations.
{"title":"A Novel Workflow for Fracture Reconstruction and Uncertainty Analysis for Unconventional Reservoir Development","authors":"Baosheng Liang, S. Du","doi":"10.2118/191795-MS","DOIUrl":"https://doi.org/10.2118/191795-MS","url":null,"abstract":"\u0000 Fracture networks present a critical influence on to better assess oil recovery and to optimize production of hydraulically fractured reservoirs. We established a novel workflow for fracture uncertainty analysis and prediction, in which multiple fracture pattern realizations are created from the geostatistical analysis. The original fracture networks were created using geomechanics tools. Then the fracture network is reconstrued for uncertainty analysis and history matching. For different realizations of the fracture distributions created in this workflow, we successfully maintain the continuity of the fractures, as well as the connections from the matrix to fractures. The generated grid can be further used for treatment simulation to determine fractures geometry, height growth and respected proppant transport in the induced fracture network.\u0000 In this paper, we also apply Embedded Discrete Fracture Model (EDFM) to capture the realistic geometry of fractures. Within the EDFM, each fracture plane is embedded inside the matrix grid and is discretized by the cell boundaries. We study a series of reservoir simulation realizations, in which the complex hydraulic fracture networks are created in the workflow. We investigate different fracture realizations in both planar and complex fracture configurations while maintaining the continuity within the fracture networks. This study also includes the influence of the network geometry and fractures properties on the overall performance of the reservoir.\u0000 From the uncertainty analysis results, we find that the overall reservoir performance is controlled by the fracture connectivity and the distribution of conductivity within the network. A good match of production history can be achieved by adjusting the fracture connectivity. Modeling with multiple realizations of fracture networks acknowledge that a reliable production forecast is achievable using geostatistical analysis for fracture connection reconstructions. Applying Embedded Discrete Fracture Model (EDFM) on the fracture-related model simulation provides a robust and effective means of investigating multiple fracture realizations.","PeriodicalId":11155,"journal":{"name":"Day 2 Thu, September 06, 2018","volume":"52 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-08-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"73556315","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}
Hydraulic fracturing in the Marcellus Shale play has moved to produced water only scenarios because of prohibitive water disposal costs. Well completion under produced water only conditions increases the demand on chemical additive performance. In addition, water reuse selects deleterious microorganisms through natural selection, which may increase the likelihood of formation souring. Conventional biocides are typically used to mitigate these risks, but to some extent, they present health, safety, and environmental (HSE) concerns. In addition, several conventional biocides have side reactions with sulfide, notably tetrakis(hydroxymethyl)phosphonium sulfate (THPS) and 2,2-dibromo-3-nitrilopropionamide (DBNPA). This paper describes an improved method for the effective control of deleterious microorganisms without the use of conventional biocides. An environmentally friendly system that includes nitrate-reducing bacteria (NRB) coupled with nitrate co-introduction was previously shown to mitigate souring as effectively as a biocide alternative for more than 1,000 assets. The NRB inhibit growth of the deleterious sulfate-reducing bacteria (SRB) primarily by competing for the available carbon source if the source is limited. This paper describes an improved NRB/nitrate system that incorporates a sulfate analog, which presumably inhibits dissimilatory sulfate reduction and enhances mitigation. Laboratory experiments were performed to measure the amount of hydrogen sulfide (H2S) produced in field brine samples inoculated with SRB. The improved NRB/nitrate system was shown to inhibit the production of H2S under worst-case scenarios in laboratory competitive exclusion experiments. Results for the new treatment at four trial wells are presented. Sulfate-reducing bacteria populations, acid-reducing bacteria populations, and a gaseous H2S concentration were monitored over three months and were found to satisfy the operator's set key performance indicators. Overall, the amount of chemical required for treatment was reduced for this improved system, which substantially reduced the operator costs to treat the wells. The combination of chemistries with mutually exclusive cellular targets highlights the value of synergistic effects, specifically reducing system cost to treat while retaining low aquatic toxicity, as compared to traditional biocides used in the oilfield.
{"title":"Improved Efficiency of a Nitrate Reducing Bacteria/Nitrate Treatment by the Incorporation of a Sulfate Analog","authors":"Kiran Gawas, Dana Safarin, H. Riley, J. Ogle","doi":"10.2118/191773-MS","DOIUrl":"https://doi.org/10.2118/191773-MS","url":null,"abstract":"\u0000 Hydraulic fracturing in the Marcellus Shale play has moved to produced water only scenarios because of prohibitive water disposal costs. Well completion under produced water only conditions increases the demand on chemical additive performance. In addition, water reuse selects deleterious microorganisms through natural selection, which may increase the likelihood of formation souring. Conventional biocides are typically used to mitigate these risks, but to some extent, they present health, safety, and environmental (HSE) concerns. In addition, several conventional biocides have side reactions with sulfide, notably tetrakis(hydroxymethyl)phosphonium sulfate (THPS) and 2,2-dibromo-3-nitrilopropionamide (DBNPA). This paper describes an improved method for the effective control of deleterious microorganisms without the use of conventional biocides.\u0000 An environmentally friendly system that includes nitrate-reducing bacteria (NRB) coupled with nitrate co-introduction was previously shown to mitigate souring as effectively as a biocide alternative for more than 1,000 assets. The NRB inhibit growth of the deleterious sulfate-reducing bacteria (SRB) primarily by competing for the available carbon source if the source is limited. This paper describes an improved NRB/nitrate system that incorporates a sulfate analog, which presumably inhibits dissimilatory sulfate reduction and enhances mitigation. Laboratory experiments were performed to measure the amount of hydrogen sulfide (H2S) produced in field brine samples inoculated with SRB. The improved NRB/nitrate system was shown to inhibit the production of H2S under worst-case scenarios in laboratory competitive exclusion experiments.\u0000 Results for the new treatment at four trial wells are presented. Sulfate-reducing bacteria populations, acid-reducing bacteria populations, and a gaseous H2S concentration were monitored over three months and were found to satisfy the operator's set key performance indicators. Overall, the amount of chemical required for treatment was reduced for this improved system, which substantially reduced the operator costs to treat the wells.\u0000 The combination of chemistries with mutually exclusive cellular targets highlights the value of synergistic effects, specifically reducing system cost to treat while retaining low aquatic toxicity, as compared to traditional biocides used in the oilfield.","PeriodicalId":11155,"journal":{"name":"Day 2 Thu, September 06, 2018","volume":"21 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-08-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"90506344","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}
In this work, we estimate the Stimulated Original Oil In Place (SOOIP) of hydraulically fractured horizontal wells in prominent shale plays. This is done by compiling production data from hundreds of wells belonging to the Bakken, Niobrara, Wolfcamp, Eagle Ford, Bone Springs, and Woodford totaling over 2,500 wells. Additionally, we present probabilistic distributions of SOOIP with mean, standard deviation, P10, P50, and P90 estimates for each play. To circumvent the challenge of data availability for each well, we use the findings of a previous study where all reservoir unknowns are grouped into two major parameters. One of these parameters, alpha, is a function of the stimulated reservoir volume, compressibility, and pressure drawdown, where the last two are unknowns. While alpha is determined with high confidence for each well, we account for the uncertainty of compressibility and drawdown values across wells by assuming a normal distribution for these parameters. Lastly, by incorporating 1 million Monte Carlo samplings and a Mersenne Twister random number generator we estimate SOOIP distributions for each play with varying degrees of confidence. The final results show that the Niobrara and Bakken have the highest mean SOOIP values per well while the values for the Woodford and Bone Springs are the lowest among all six plays considered. Volumetric calculations using data from the literature qualitatively corroborate these findings. New insight on the stimulated volumes per well for prominent shale plays can be derived from these results as they correlate to horizontal well length, formation thickness, and hydraulic fracture half-lengths in each play.
{"title":"Stimulated Oil Reservoir Volume Estimation of Prominent US Tight Oil Formations","authors":"P. Panja, R. Velasco, M. Deo","doi":"10.2118/191774-MS","DOIUrl":"https://doi.org/10.2118/191774-MS","url":null,"abstract":"\u0000 In this work, we estimate the Stimulated Original Oil In Place (SOOIP) of hydraulically fractured horizontal wells in prominent shale plays. This is done by compiling production data from hundreds of wells belonging to the Bakken, Niobrara, Wolfcamp, Eagle Ford, Bone Springs, and Woodford totaling over 2,500 wells. Additionally, we present probabilistic distributions of SOOIP with mean, standard deviation, P10, P50, and P90 estimates for each play.\u0000 To circumvent the challenge of data availability for each well, we use the findings of a previous study where all reservoir unknowns are grouped into two major parameters. One of these parameters, alpha, is a function of the stimulated reservoir volume, compressibility, and pressure drawdown, where the last two are unknowns. While alpha is determined with high confidence for each well, we account for the uncertainty of compressibility and drawdown values across wells by assuming a normal distribution for these parameters. Lastly, by incorporating 1 million Monte Carlo samplings and a Mersenne Twister random number generator we estimate SOOIP distributions for each play with varying degrees of confidence.\u0000 The final results show that the Niobrara and Bakken have the highest mean SOOIP values per well while the values for the Woodford and Bone Springs are the lowest among all six plays considered. Volumetric calculations using data from the literature qualitatively corroborate these findings. New insight on the stimulated volumes per well for prominent shale plays can be derived from these results as they correlate to horizontal well length, formation thickness, and hydraulic fracture half-lengths in each play.","PeriodicalId":11155,"journal":{"name":"Day 2 Thu, September 06, 2018","volume":"14 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-08-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"85847498","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}
Permian Basin reserves exceed the reserves of the largest conventional field in the world, Ghawar, Saudi Arabia [1]. To develop this field many companies use ‘factory drilling’ or ‘geometrical approach’. This approach decreases the cost of drilling and make sense for source rocks because these are hydrocarbons saturated rocks or the rocks where hydrocarbons have been cooked. Geometrical approach would be ideal for homogeneous formations, but as it will be shown below shale place are very inhomogeneous vertically and laterally. While a drilling cost for a single well is reduced, this approach significantly increases the overall development costs and environmental impact because of drilling a big number of low producing wells. We found the way to solve this problem developing a technology that uses standard open-hole log data to calculate Production Profile that shows predicted production along the entire well.
{"title":"Advanced Formation Evaluation to Optimize Shale Development in Permian Basin","authors":"V. Ingerman","doi":"10.2118/191792-MS","DOIUrl":"https://doi.org/10.2118/191792-MS","url":null,"abstract":"\u0000 Permian Basin reserves exceed the reserves of the largest conventional field in the world, Ghawar, Saudi Arabia [1].\u0000 To develop this field many companies use ‘factory drilling’ or ‘geometrical approach’. This approach decreases the cost of drilling and make sense for source rocks because these are hydrocarbons saturated rocks or the rocks where hydrocarbons have been cooked. Geometrical approach would be ideal for homogeneous formations, but as it will be shown below shale place are very inhomogeneous vertically and laterally. While a drilling cost for a single well is reduced, this approach significantly increases the overall development costs and environmental impact because of drilling a big number of low producing wells.\u0000 We found the way to solve this problem developing a technology that uses standard open-hole log data to calculate Production Profile that shows predicted production along the entire well.","PeriodicalId":11155,"journal":{"name":"Day 2 Thu, September 06, 2018","volume":"57 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-08-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"78159742","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}
B. Cherian, M. Shoemaker, S.u Nwoko, S. Narasimhan, O. Olaoye, J. Iqbal, J. Peacock, J. Becher, B. Ferguson, N. Zakhour
The Permian Basin in North American has been the driving force behind global energy growth, resulting from the exploitation of unconventional resources. The combination of high quality stacked resources, horizontal drilling, completion tools, and hydraulic fracturing innovations has accelerated the learning curve in this basin over the past few years: which was the impetus of this study. This paper utilizes an integrated model approach to understand reservoir performance on a pad with four wells completed across multiple horizons in the Midland Basin. Rich multi-domain data sets were utilized that included seismic, wireline triple-combo, compressional and shear log suites, core (rock mechanics testing, geochemical analysis (XRF and XRD) and routine core analysis), completion data (fracture treatments with pre-and post-job shut-in pressures), and production data including 1,500 days of production history with bottom-hole pressure gauge data. 3-D surface seismic, high tier logs, and core data were used initially to create a facies model. Properties were distributed into a geo-model using the existing vertical well-control and seismic as constraints. A sector model was then built that enabled modeling of 4 development wells that consisted of parent well, followed by 3 child-wells. The history matching of fracture treatments and production data with bottom-hole pressure data resulted in significant understanding of key parameters driving subsurface performance. A workflow, representing the seamless integration of said models, is presented that enables an improved understanding of what impact sequence and timing of operations has on the subsurface contact area as well as the implied change in well performance if an optimal strategy is executed. Geomechanical facies that drive vertical connectivity and fracture geometry, as well as reservoir parameters that impact fracture contact with the reservoir, were identified.
{"title":"Understanding Development Drivers in Horizontal Wellbores in the Midland Basin","authors":"B. Cherian, M. Shoemaker, S.u Nwoko, S. Narasimhan, O. Olaoye, J. Iqbal, J. Peacock, J. Becher, B. Ferguson, N. Zakhour","doi":"10.2118/191782-MS","DOIUrl":"https://doi.org/10.2118/191782-MS","url":null,"abstract":"\u0000 The Permian Basin in North American has been the driving force behind global energy growth, resulting from the exploitation of unconventional resources. The combination of high quality stacked resources, horizontal drilling, completion tools, and hydraulic fracturing innovations has accelerated the learning curve in this basin over the past few years: which was the impetus of this study.\u0000 This paper utilizes an integrated model approach to understand reservoir performance on a pad with four wells completed across multiple horizons in the Midland Basin. Rich multi-domain data sets were utilized that included seismic, wireline triple-combo, compressional and shear log suites, core (rock mechanics testing, geochemical analysis (XRF and XRD) and routine core analysis), completion data (fracture treatments with pre-and post-job shut-in pressures), and production data including 1,500 days of production history with bottom-hole pressure gauge data. 3-D surface seismic, high tier logs, and core data were used initially to create a facies model. Properties were distributed into a geo-model using the existing vertical well-control and seismic as constraints. A sector model was then built that enabled modeling of 4 development wells that consisted of parent well, followed by 3 child-wells. The history matching of fracture treatments and production data with bottom-hole pressure data resulted in significant understanding of key parameters driving subsurface performance.\u0000 A workflow, representing the seamless integration of said models, is presented that enables an improved understanding of what impact sequence and timing of operations has on the subsurface contact area as well as the implied change in well performance if an optimal strategy is executed. Geomechanical facies that drive vertical connectivity and fracture geometry, as well as reservoir parameters that impact fracture contact with the reservoir, were identified.","PeriodicalId":11155,"journal":{"name":"Day 2 Thu, September 06, 2018","volume":"191 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-08-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"74612238","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}
Naturally fractured reservoirs such as the Marcellus shale require an integrated reservoir modeling approach to determine well spacing and well-to-well interference. The Marcellus Shale Energy and Environment Laboratory (MSEEL) is a joint project between universities, companies, and government to develop and test new completion technologies and acquire a robust understanding of the Marcellus shale. The study presented in this paper aims to reveal an approach to determine reservoir depletion with time through coupled geological modeling and geomechanical evaluation followed by completion and well performance history matching for a multiwell pad in the Marcellus shale. The geomechanical model was prepared with interpreted vertical log data. A discrete natural fracture (DFN) model was created and used to determine the complexity of hydraulic fracture geometry simulated through complex fracture models on a two well pad. The microseismic data obtained during the hydraulic fracture simulations served as a constraining parameter for the hydraulic fracture footprint in these wells. Sensitivity to the DFN is realized by parametric variations of DFN properties to achieve a calibrated fracture geometry. Reservoir simulation and history matching the well production data confirmed the subsurface production response to the hydraulic fractures. Well spacing sensitivity was done to reveal the optimum distance that the wells need to be spaced to maximize recovery and number of wells per section. Hydraulic fracture geometry was found to be a result of the calibration parameters, such as horizontal stress anisotropy, fracturing fluid leakoff, and the DFN. The availability of microseismic data and production history matching through integrated numerical simulation are therefore critical elements to bring unique representation of the subsurface reaction to the injected fracturing fluid. This approach can therefore be consistently applied to evaluate well spacing and interference in time for the subsequent wells completed in the Marcellus. With the current completion design and pumping treatments, the optimal well spacing of 990 ft was determined between the wells in this study. However, wells to be completed in the future need to be modeled due to the heterogeneity in the reservoir properties to ensure that wells are not either underspaced to cause well production interference or overspaced to create upswept hydrocarbon reserves in the formation. By adopting the key learnings and approach followed in this paper, operators can maximize subsurface understanding and will be able to place their wellbore in a nongeometric pattern based on reservoir heterogeneity to optimize well spacing and improve recovery.
{"title":"Hydraulic Fracture and Reservoir Characterization for Determining Optimal Well Spacing in the Marcellus Shale","authors":"P. Pankaj, P. Shukla, P. Kavousi, T. Carr","doi":"10.2118/191802-MS","DOIUrl":"https://doi.org/10.2118/191802-MS","url":null,"abstract":"\u0000 Naturally fractured reservoirs such as the Marcellus shale require an integrated reservoir modeling approach to determine well spacing and well-to-well interference. The Marcellus Shale Energy and Environment Laboratory (MSEEL) is a joint project between universities, companies, and government to develop and test new completion technologies and acquire a robust understanding of the Marcellus shale. The study presented in this paper aims to reveal an approach to determine reservoir depletion with time through coupled geological modeling and geomechanical evaluation followed by completion and well performance history matching for a multiwell pad in the Marcellus shale.\u0000 The geomechanical model was prepared with interpreted vertical log data. A discrete natural fracture (DFN) model was created and used to determine the complexity of hydraulic fracture geometry simulated through complex fracture models on a two well pad. The microseismic data obtained during the hydraulic fracture simulations served as a constraining parameter for the hydraulic fracture footprint in these wells. Sensitivity to the DFN is realized by parametric variations of DFN properties to achieve a calibrated fracture geometry. Reservoir simulation and history matching the well production data confirmed the subsurface production response to the hydraulic fractures. Well spacing sensitivity was done to reveal the optimum distance that the wells need to be spaced to maximize recovery and number of wells per section.\u0000 Hydraulic fracture geometry was found to be a result of the calibration parameters, such as horizontal stress anisotropy, fracturing fluid leakoff, and the DFN. The availability of microseismic data and production history matching through integrated numerical simulation are therefore critical elements to bring unique representation of the subsurface reaction to the injected fracturing fluid. This approach can therefore be consistently applied to evaluate well spacing and interference in time for the subsequent wells completed in the Marcellus. With the current completion design and pumping treatments, the optimal well spacing of 990 ft was determined between the wells in this study. However, wells to be completed in the future need to be modeled due to the heterogeneity in the reservoir properties to ensure that wells are not either underspaced to cause well production interference or overspaced to create upswept hydrocarbon reserves in the formation.\u0000 By adopting the key learnings and approach followed in this paper, operators can maximize subsurface understanding and will be able to place their wellbore in a nongeometric pattern based on reservoir heterogeneity to optimize well spacing and improve recovery.","PeriodicalId":11155,"journal":{"name":"Day 2 Thu, September 06, 2018","volume":"7 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2018-08-28","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"91120829","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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