N. Clegg, Seth Nolan, A. Duriez, Katharine Cunha, Lesley Hunter, Hsu-hsiang Wu, Jin Ma
Identifying a well's stratigraphic position from azimuthal electromagnetic (EM) data requires integrating data from multiple depths of investigation. As a well's position within the stratigraphy can be constantly changing, and formations and fluids show considerable lateral variability, this process is difficult to do manually. To simplify this, inversion algorithms are deployed to represent EM logging while drilling (LWD) measurements as models reflecting the geology. Inversion results are not a direct measurement, therefore confidence in the results is critical. Real-time well placement decisions are routinely made on the output of EM inversions. It is critical to understand that these are models, not direct measurements, therefore verification of the results is essential. This paper discusses the workflows and tools available to interrogate the models generated to give high confidence in the results with a focus on a new deep EM tool deployed in a complex geological environment. The deployment of established EM tools in the same bottom hole assembly (BHA) provides independent verification of the results alongside statistical analysis of the inversion. In many complex depositional environments, the resultant geology is not layer cake. Formations can pinch out or show considerable lateral variability. In these environments it is extremely challenging and sometimes impossible to track a single layer or boundary. We examine a case study from Alaska in a complex shallow marine depositional environment. The target sands were expected to show considerable lateral variability with pinch outs and multiple shale lenses and layers. Deployment of a new, deep azimuthal EM tool with an associated inversion algorithm provided a geological model representing the distribution of the target formations. The stratigraphy was comprised of a complex distribution of sands and shales, many penetrated by the wellbore, with others distributed away from the wellbore based on the depth of investigation of the EM measurements. If this model is the primary tool for mapping the formations and steering to penetrate the most productive zones, it is critical to understand the results and have high confidence in them. The second tool in the BHA, the established azimuthal resistivity tool, provided an opportunity to directly compare the azimuthal data with the inversion result from the new tool to critique the inversion results and help to understand this complex geological environment. The complexity of integrating the data from multiple azimuthal images with different depths of investigation, based on multiple transmitter-receiver spacings and transmission frequencies, demonstrates the need for inversion algorithms to convert the EM field data to a simple-to-understand representation of the geology. This case study provides proof of the quality of the model, especially in such a complex geological environment, allowing high confidence in the deployment of this new tool fo
{"title":"Confidence in Subsurface Inversion Models Generated from Electromagnetic Logging While Drilling Data","authors":"N. Clegg, Seth Nolan, A. Duriez, Katharine Cunha, Lesley Hunter, Hsu-hsiang Wu, Jin Ma","doi":"10.2118/210374-ms","DOIUrl":"https://doi.org/10.2118/210374-ms","url":null,"abstract":"\u0000 Identifying a well's stratigraphic position from azimuthal electromagnetic (EM) data requires integrating data from multiple depths of investigation. As a well's position within the stratigraphy can be constantly changing, and formations and fluids show considerable lateral variability, this process is difficult to do manually. To simplify this, inversion algorithms are deployed to represent EM logging while drilling (LWD) measurements as models reflecting the geology. Inversion results are not a direct measurement, therefore confidence in the results is critical.\u0000 Real-time well placement decisions are routinely made on the output of EM inversions. It is critical to understand that these are models, not direct measurements, therefore verification of the results is essential. This paper discusses the workflows and tools available to interrogate the models generated to give high confidence in the results with a focus on a new deep EM tool deployed in a complex geological environment. The deployment of established EM tools in the same bottom hole assembly (BHA) provides independent verification of the results alongside statistical analysis of the inversion.\u0000 In many complex depositional environments, the resultant geology is not layer cake. Formations can pinch out or show considerable lateral variability. In these environments it is extremely challenging and sometimes impossible to track a single layer or boundary. We examine a case study from Alaska in a complex shallow marine depositional environment. The target sands were expected to show considerable lateral variability with pinch outs and multiple shale lenses and layers. Deployment of a new, deep azimuthal EM tool with an associated inversion algorithm provided a geological model representing the distribution of the target formations. The stratigraphy was comprised of a complex distribution of sands and shales, many penetrated by the wellbore, with others distributed away from the wellbore based on the depth of investigation of the EM measurements. If this model is the primary tool for mapping the formations and steering to penetrate the most productive zones, it is critical to understand the results and have high confidence in them. The second tool in the BHA, the established azimuthal resistivity tool, provided an opportunity to directly compare the azimuthal data with the inversion result from the new tool to critique the inversion results and help to understand this complex geological environment.\u0000 The complexity of integrating the data from multiple azimuthal images with different depths of investigation, based on multiple transmitter-receiver spacings and transmission frequencies, demonstrates the need for inversion algorithms to convert the EM field data to a simple-to-understand representation of the geology. This case study provides proof of the quality of the model, especially in such a complex geological environment, allowing high confidence in the deployment of this new tool fo","PeriodicalId":113697,"journal":{"name":"Day 2 Tue, October 04, 2022","volume":"31 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-09-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"117141334","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 issue of screen erosion is a complex problem that doesn't lend itself very easily to modeling and computer aided design, particularly when it comes to metal mesh screens. Interactions between solid and liquid (settling/suspension) and between the solids and the screen material (plugging) are complex and evolving over time due to wear and fluctuations associated with multiphase flow or other reservoir related changes over the life of the well. As a result, screen development is best performed using pilot testing to simulate downhole conditions and optimize the design. In that regard, the setting of standard performance tests is essential. A series of time lapse erosion tests performed on mesh screens recently highlighted the benefits of shielding the screen from the basepipe perforations to improve erosion resistance. This new feature provided several fold improvements in the mesh screen erosion resistance and was implemented in a novel screen design. It consists in placing a partially perforated inner shroud underneath a regular screen cartridge, with blind spots precisely located over the basepipe holes to prevent direct line of sight flow and reducing local velocity by diffusing flow across the entire screen area. An extended continuous erosion test was used to validate the design and qualify metal meshes, and mechanical testing as per the new API19ss standard for sand control screens was performed to qualify the new screen and demonstrate its reliability. Comparing the performance of the new screen design against similarly built screens confirmed that the addition of the new diffusion shroud does not adversely impact the mechanical performance of the screen while imparting improved erosion resistance to the screen.
{"title":"Design and Qualification of a New Erosion Resistant Sand Control Screen","authors":"C. Malbrel, Edward Blackburne","doi":"10.2118/209951-ms","DOIUrl":"https://doi.org/10.2118/209951-ms","url":null,"abstract":"\u0000 The issue of screen erosion is a complex problem that doesn't lend itself very easily to modeling and computer aided design, particularly when it comes to metal mesh screens. Interactions between solid and liquid (settling/suspension) and between the solids and the screen material (plugging) are complex and evolving over time due to wear and fluctuations associated with multiphase flow or other reservoir related changes over the life of the well. As a result, screen development is best performed using pilot testing to simulate downhole conditions and optimize the design. In that regard, the setting of standard performance tests is essential.\u0000 A series of time lapse erosion tests performed on mesh screens recently highlighted the benefits of shielding the screen from the basepipe perforations to improve erosion resistance. This new feature provided several fold improvements in the mesh screen erosion resistance and was implemented in a novel screen design. It consists in placing a partially perforated inner shroud underneath a regular screen cartridge, with blind spots precisely located over the basepipe holes to prevent direct line of sight flow and reducing local velocity by diffusing flow across the entire screen area.\u0000 An extended continuous erosion test was used to validate the design and qualify metal meshes, and mechanical testing as per the new API19ss standard for sand control screens was performed to qualify the new screen and demonstrate its reliability.\u0000 Comparing the performance of the new screen design against similarly built screens confirmed that the addition of the new diffusion shroud does not adversely impact the mechanical performance of the screen while imparting improved erosion resistance to the screen.","PeriodicalId":113697,"journal":{"name":"Day 2 Tue, October 04, 2022","volume":"1 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-09-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"130102498","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
A design optimized coated sand screen was developed that increases the erosion resistance of conventional sand screens. Computational fluid dynamics and laboratory testing were conducted to determine the design optimizations and a coating was developed through rigorous testing. The screen has now been deployed and adopted with success.
{"title":"Erosion Resistant Sand Screen: Development and Deployment","authors":"Antonio Lazo, Jeremy Davis, J. Weirich","doi":"10.2118/210128-ms","DOIUrl":"https://doi.org/10.2118/210128-ms","url":null,"abstract":"\u0000 A design optimized coated sand screen was developed that increases the erosion resistance of conventional sand screens. Computational fluid dynamics and laboratory testing were conducted to determine the design optimizations and a coating was developed through rigorous testing. The screen has now been deployed and adopted with success.","PeriodicalId":113697,"journal":{"name":"Day 2 Tue, October 04, 2022","volume":"2 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-09-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"129469122","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}
Performance contracts are increasingly common in the drilling industry, especially in recent years. This incentivized contract structure, established as a partnership between operator and contractor, improves both well performance and operational execution while incorporating the rig contractor as an additional stakeholder in the operational performance of the well. Many performance contract styles exist, with one common goal: if targets are met, all parties involved benefit. An increasingly common performance contract type is a tier-structure KPI (Key Performance Indicator) format. In this format, metrics in the form of KPIs are determined, and goal ranges are set in a tiered system. Prior research and data collection, requiring effort from multiple departments, is needed to determine achievable and stretch metrics. After the goals are agreed upon, field personnel, experienced rig leadership, and comprehensive technology support are determined, forming a foundation for success. Establishing an effective communication structure is crucial for continuous improvement. This is achieved by regular performance improvement meetings, occurring among field and office personnel, for both the rig contractor and operator. Here, relevant performance data is shared regarding both successes and failures, with improvements needed for future wells are captured and implemented. In this instance, a four-tiered incentivized structure with KPIs measuring cycle time ft/day, connection times, tripping speeds and skid times were used. Over time, the performance contract structure benefits the operator/contractor relationship, with greater alignment on goals and responsibilities. A constant line of communication allows for frequent brainstorming and an eagerness to trial new methods, leading to a unique opportunity to demonstrate value with near-immediate results. Certain contractor technologies are at the operator's disposal as they benefit the well program, creating more openness to technologies not initially considered. Performance contracts allow for the continuous questioning of, "does this help us achieve our overall goal?" The constant focus on continuous improvement leads to performance benchmarks continually reviewed and fine-tuned with new data. There is no true "one size fits all" solution - despite everyone's best efforts, performance contracts don't all succeed at well release. Both the operator and contractor must continually be prepared to fail fast, identify improvement opportunities, make changes, and work together. However, all performance contracts ultimately play a part in innovative spirit while implementing fundamental changes in an evolving drilling industry and energy landscape. Over the course of deployment, this contract structure led to increased and more consistent performance compared to the unincentivized rigs. Overall, the rig experienced an 8.2% increase in average feet drilled per day compared to the operator's prior year benchmark
{"title":"Drilling Performance Contract: An Evolution in the Partnership Between Operator and Rig Contractor","authors":"Nishanth Samuel, Andrew H. W. Stone, Sarah Kern","doi":"10.2118/210271-ms","DOIUrl":"https://doi.org/10.2118/210271-ms","url":null,"abstract":"\u0000 Performance contracts are increasingly common in the drilling industry, especially in recent years. This incentivized contract structure, established as a partnership between operator and contractor, improves both well performance and operational execution while incorporating the rig contractor as an additional stakeholder in the operational performance of the well. Many performance contract styles exist, with one common goal: if targets are met, all parties involved benefit.\u0000 An increasingly common performance contract type is a tier-structure KPI (Key Performance Indicator) format. In this format, metrics in the form of KPIs are determined, and goal ranges are set in a tiered system. Prior research and data collection, requiring effort from multiple departments, is needed to determine achievable and stretch metrics. After the goals are agreed upon, field personnel, experienced rig leadership, and comprehensive technology support are determined, forming a foundation for success.\u0000 Establishing an effective communication structure is crucial for continuous improvement. This is achieved by regular performance improvement meetings, occurring among field and office personnel, for both the rig contractor and operator. Here, relevant performance data is shared regarding both successes and failures, with improvements needed for future wells are captured and implemented. In this instance, a four-tiered incentivized structure with KPIs measuring cycle time ft/day, connection times, tripping speeds and skid times were used.\u0000 Over time, the performance contract structure benefits the operator/contractor relationship, with greater alignment on goals and responsibilities. A constant line of communication allows for frequent brainstorming and an eagerness to trial new methods, leading to a unique opportunity to demonstrate value with near-immediate results. Certain contractor technologies are at the operator's disposal as they benefit the well program, creating more openness to technologies not initially considered. Performance contracts allow for the continuous questioning of, \"does this help us achieve our overall goal?\" The constant focus on continuous improvement leads to performance benchmarks continually reviewed and fine-tuned with new data. There is no true \"one size fits all\" solution - despite everyone's best efforts, performance contracts don't all succeed at well release. Both the operator and contractor must continually be prepared to fail fast, identify improvement opportunities, make changes, and work together. However, all performance contracts ultimately play a part in innovative spirit while implementing fundamental changes in an evolving drilling industry and energy landscape.\u0000 Over the course of deployment, this contract structure led to increased and more consistent performance compared to the unincentivized rigs. Overall, the rig experienced an 8.2% increase in average feet drilled per day compared to the operator's prior year benchmark","PeriodicalId":113697,"journal":{"name":"Day 2 Tue, October 04, 2022","volume":"55 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-09-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"131314510","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
M. Sviridov, D. Kushnir, A. Mosin, Andrey Belousov, D. Nemushchenko, A. Zaputlyaeva
Logging-while-drilling (LWD) ultra-deep resistivity technology can explore the reservoir on a similar scale to seismic, so interpreted resistivity models can be combined with seismic sections to enable oil field operators to delineate pay zones better, improve reservoir understanding, and eventually achieve higher reservoir contact value by proactive geosteering. Currently, there is no industry-adopted processing software which supports different ultra-deep tools. This paper presents the first vendor-independent, gradient-based stochastic approach for ultra-deep data inversion while drilling. Industry literature review was performed to determine parameters of ultra-deep tools, investigate their responses, and add them to the list of supported devices. Inversion algorithm is based on stochastic Monte Carlo method with reversible jump Markov chains and can be launched automatically without prior assumptions about the reservoir structure. Finally, it provides an ensemble of unbiased 1D formation models explaining the measurements as well as uncertainty estimates of model parameters. Parallel running of several Markov chains on multiple CPUs with both gradient-based sampling and exchanging their states makes the algorithm computationally effective and helps to avoid sticking in local optima. The proposed approach enables gathering of ultra-deep tools from different vendors under a common interface, along with other resistivity tools, joint processing various resistivity data with the same inversion workflow, and representation of inversion deliverables in unified format. Due to the large formation volume being investigated, the ultra-deep readings become complex. To be interpreted, such responses require multi-layer models as well as special multi-parametric inversion software. Working in high-dimensional parameter space, stochastic Monte Carlo inversion algorithms might not be effective due to the limitation of sampling procedure that usually generates new samples through the random perturbation of the few model parameters and does not consider their relations with other model parameters. This may lead to a high rate of proposal rejections and a lot of unnecessary calculations. To overcome this issue and guarantee real-time results, the presented approach employs Metropolis-adjusted Langevin technique which evaluates the gradient of posterior probability density function and generates proposals with a higher posterior probability of being accepted. Additionally, a special fast semi analytical solver is utilized to compute the gradient simultaneously with tool responses, with almost no extra computational costs. Application of the developed software is shown on synthetic scenarios and case studies from Norwegian natural gas and oil fields. The presented approach is identified as the first vendor-independent gradient-based inversion algorithm operating with any measurements of ultra-deep and deep azimuthal resistivity tools available on the ma
{"title":"Reservoir Mapping with Vendor-Independent Gradient-Based Stochastic Inversion of LWD Ultra-Deep Azimuthal Resistivity Data","authors":"M. Sviridov, D. Kushnir, A. Mosin, Andrey Belousov, D. Nemushchenko, A. Zaputlyaeva","doi":"10.2118/210062-ms","DOIUrl":"https://doi.org/10.2118/210062-ms","url":null,"abstract":"\u0000 Logging-while-drilling (LWD) ultra-deep resistivity technology can explore the reservoir on a similar scale to seismic, so interpreted resistivity models can be combined with seismic sections to enable oil field operators to delineate pay zones better, improve reservoir understanding, and eventually achieve higher reservoir contact value by proactive geosteering. Currently, there is no industry-adopted processing software which supports different ultra-deep tools. This paper presents the first vendor-independent, gradient-based stochastic approach for ultra-deep data inversion while drilling.\u0000 Industry literature review was performed to determine parameters of ultra-deep tools, investigate their responses, and add them to the list of supported devices. Inversion algorithm is based on stochastic Monte Carlo method with reversible jump Markov chains and can be launched automatically without prior assumptions about the reservoir structure. Finally, it provides an ensemble of unbiased 1D formation models explaining the measurements as well as uncertainty estimates of model parameters. Parallel running of several Markov chains on multiple CPUs with both gradient-based sampling and exchanging their states makes the algorithm computationally effective and helps to avoid sticking in local optima.\u0000 The proposed approach enables gathering of ultra-deep tools from different vendors under a common interface, along with other resistivity tools, joint processing various resistivity data with the same inversion workflow, and representation of inversion deliverables in unified format.\u0000 Due to the large formation volume being investigated, the ultra-deep readings become complex. To be interpreted, such responses require multi-layer models as well as special multi-parametric inversion software. Working in high-dimensional parameter space, stochastic Monte Carlo inversion algorithms might not be effective due to the limitation of sampling procedure that usually generates new samples through the random perturbation of the few model parameters and does not consider their relations with other model parameters. This may lead to a high rate of proposal rejections and a lot of unnecessary calculations.\u0000 To overcome this issue and guarantee real-time results, the presented approach employs Metropolis-adjusted Langevin technique which evaluates the gradient of posterior probability density function and generates proposals with a higher posterior probability of being accepted. Additionally, a special fast semi analytical solver is utilized to compute the gradient simultaneously with tool responses, with almost no extra computational costs.\u0000 Application of the developed software is shown on synthetic scenarios and case studies from Norwegian natural gas and oil fields.\u0000 The presented approach is identified as the first vendor-independent gradient-based inversion algorithm operating with any measurements of ultra-deep and deep azimuthal resistivity tools available on the ma","PeriodicalId":113697,"journal":{"name":"Day 2 Tue, October 04, 2022","volume":"365 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-09-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"122833648","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}
Dan Fu, W. Zemlak, Tony Yeung, Caleb Barclay, Trevor Gorchynski
Recently, the North America Oil and Gas industry has seen a rapid increase in the adoption of new hydraulic fracturing technologies such as dual-fuel diesel engine, electric system powered by gas turbine or engine on-site and turbine direct drive technology, to reduce emissions and operating costs. The objective of this paper is to provide a detailed analysis of economic, environmental, and technical considerations when selecting the next generation hydraulic fracturing equipment platform. It is believed that any next-generation technology must meet the following key requirements: 1. Reduction of GHG and EPA regulated emissions; 2. Reduced equipment footprint; 3. Capable of meeting the most stringent noise standard; 4. Improved reliability; 5. Improved pad-to-pad mobility; 6. Reduced maintenance and personnel costs; 7. Competitive capital cost. For the selection process, a methodology was developed to evaluate the energy density of fuel, thermal efficiency of prime movers, mechanical power transfer efficiency, and equipment operating environment and configuration against the above objectives. The methodology also considered the technical and commercial feasibility of key components. Natural gas is selected as the mobile primary energy source due to its higher energy density and lower emission profile than conventional diesel, and more economical and widely available on-site. Among all available natural gas-powered engines evaluated, which included dual-fuel diesel engine, gas reciprocating engine, single large turbine and direct drive turbine, the direct drive turbine scored the highest. The direct drive pumping unit is equipped with a 5,000 HHP continuous duty power end driven by a 5,000 HHP dual shaft turbine through a single speed reduction gearbox. This combination provides the most efficient mechanical power transfer efficiency resulting in significant fuel cost savings and reduction in greenhouse gas emissions. Because of its high-power density, the direct drive turbine system can potentially reduce the number of on-site equipment by 43% and personnel by 31%. Comparing to other next generation hydraulic fracturing system, the direct drive turbine technology has the lowest capital cost per HHP.
{"title":"Technical, Economic and Environmental Considerations for Selecting Next Generation Hydraulic Fracturing Equipment Technology","authors":"Dan Fu, W. Zemlak, Tony Yeung, Caleb Barclay, Trevor Gorchynski","doi":"10.2118/210215-ms","DOIUrl":"https://doi.org/10.2118/210215-ms","url":null,"abstract":"\u0000 Recently, the North America Oil and Gas industry has seen a rapid increase in the adoption of new hydraulic fracturing technologies such as dual-fuel diesel engine, electric system powered by gas turbine or engine on-site and turbine direct drive technology, to reduce emissions and operating costs. The objective of this paper is to provide a detailed analysis of economic, environmental, and technical considerations when selecting the next generation hydraulic fracturing equipment platform.\u0000 It is believed that any next-generation technology must meet the following key requirements: 1. Reduction of GHG and EPA regulated emissions; 2. Reduced equipment footprint; 3. Capable of meeting the most stringent noise standard; 4. Improved reliability; 5. Improved pad-to-pad mobility; 6. Reduced maintenance and personnel costs; 7. Competitive capital cost. For the selection process, a methodology was developed to evaluate the energy density of fuel, thermal efficiency of prime movers, mechanical power transfer efficiency, and equipment operating environment and configuration against the above objectives. The methodology also considered the technical and commercial feasibility of key components.\u0000 Natural gas is selected as the mobile primary energy source due to its higher energy density and lower emission profile than conventional diesel, and more economical and widely available on-site. Among all available natural gas-powered engines evaluated, which included dual-fuel diesel engine, gas reciprocating engine, single large turbine and direct drive turbine, the direct drive turbine scored the highest. The direct drive pumping unit is equipped with a 5,000 HHP continuous duty power end driven by a 5,000 HHP dual shaft turbine through a single speed reduction gearbox. This combination provides the most efficient mechanical power transfer efficiency resulting in significant fuel cost savings and reduction in greenhouse gas emissions. Because of its high-power density, the direct drive turbine system can potentially reduce the number of on-site equipment by 43% and personnel by 31%. Comparing to other next generation hydraulic fracturing system, the direct drive turbine technology has the lowest capital cost per HHP.","PeriodicalId":113697,"journal":{"name":"Day 2 Tue, October 04, 2022","volume":"16 23","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-09-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"120873507","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}
Javier Canon, Theresa Broussard, A. Johnson, W. Singletary, Lolymar Colmenares-Diaz
This paper details experiences gained while developing a novel technology-driven approach to Risk Assessment methodologies, e.g., Process Hazard Analysis (PHA), Hazard Identification (HAZID) and Hazard Operability (HAZOP), in oil & gas. Emphasis has been placed on combining encoded human knowledge with Artificial Intelligence techniques, in a way which fosters safer designs and operations, while maintaining Subject Matter Experts (SMEs) at the center of decision making. Encoding of human knowledge (e.g., Subject Matter Expertise, Industry best practices) in digital applications has traditionally been associated with creating static pieces of information, such as lessons learned documentation and validation activities for hazard analysis. New digital technologies, however, make it possible to create truly dynamic knowledge representations, which capture key concepts and their relationships, creating a new type of "source of truth." As a result, corporate and external knowledge can be made more readily accessible to engineers and operations personnel participating in decision making. Digital corporate knowledge can also be supplemented with Artificial Intelligence (AI) techniques which can help uncover latent threats and better guide optimal decision making. This is particularly relevant in Workforce, Health & Safety (WH&S) and Process Safety contexts, where the impact of flawed or suboptimal decisions can lead to catastrophic consequences. Practical examples from an oil & gas major show how the risk assessment domain can be represented in a computational knowledge graph, in a format which is comprehensible not only to software developers, but more importantly, to oil & gas SMEs. A presentation of different AI techniques overlaid on top of this computational knowledge graph, can also offer a glimpse of the possibilities of marrying SME expertise with emerging digital technologies.
{"title":"A Knowledge-Based Artificial Intelligence Approach to Risk Management","authors":"Javier Canon, Theresa Broussard, A. Johnson, W. Singletary, Lolymar Colmenares-Diaz","doi":"10.2118/210303-ms","DOIUrl":"https://doi.org/10.2118/210303-ms","url":null,"abstract":"\u0000 This paper details experiences gained while developing a novel technology-driven approach to Risk Assessment methodologies, e.g., Process Hazard Analysis (PHA), Hazard Identification (HAZID) and Hazard Operability (HAZOP), in oil & gas. Emphasis has been placed on combining encoded human knowledge with Artificial Intelligence techniques, in a way which fosters safer designs and operations, while maintaining Subject Matter Experts (SMEs) at the center of decision making.\u0000 Encoding of human knowledge (e.g., Subject Matter Expertise, Industry best practices) in digital applications has traditionally been associated with creating static pieces of information, such as lessons learned documentation and validation activities for hazard analysis. New digital technologies, however, make it possible to create truly dynamic knowledge representations, which capture key concepts and their relationships, creating a new type of \"source of truth.\" As a result, corporate and external knowledge can be made more readily accessible to engineers and operations personnel participating in decision making.\u0000 Digital corporate knowledge can also be supplemented with Artificial Intelligence (AI) techniques which can help uncover latent threats and better guide optimal decision making. This is particularly relevant in Workforce, Health & Safety (WH&S) and Process Safety contexts, where the impact of flawed or suboptimal decisions can lead to catastrophic consequences.\u0000 Practical examples from an oil & gas major show how the risk assessment domain can be represented in a computational knowledge graph, in a format which is comprehensible not only to software developers, but more importantly, to oil & gas SMEs. A presentation of different AI techniques overlaid on top of this computational knowledge graph, can also offer a glimpse of the possibilities of marrying SME expertise with emerging digital technologies.","PeriodicalId":113697,"journal":{"name":"Day 2 Tue, October 04, 2022","volume":"221 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-09-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"116287652","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}
Abdulrahman A. Almulhim, AbdulMuqtadir Khan, Jon E. Hansen, Hashem Alobaid, D. Emelyanov
The design of fracture diversion in tight carbonates has been a challenging problem. Recently, a conceptual and theoretical workflow was presented using a β diversion design parameter that uses system volumetric calculations based on high-fidelity modeling and mathematical approximations of the etched system. A robust field validation of that approach and near-wellbore diversion modeling was conducted to extend the application. Extensive laboratory and yard-scale testing data were utilized to realize the diversion processes. Fracture and perforation modeling coupled with fracture diagnostics was used to define system volumetrics, defined as the volume where the fluid needs to be diverted away from. Multimodal particulate pills were used based on a careful review of the size distribution and physical properties. Bottomhole reactions and post-fracturing production for multiple wells and 100 particulate pills were studied to see the effect of the β factor on diversion and production performance. A multiphysics near-wellbore diversion model was used for the first time to simulate the pill effect. Representative wells were selected for the validation study; these included vertical and horizontal wells and varying perforation cluster design, stages, and acid treatments. A complex problem was solved with reaction modeling coupled with near-wellbore diversion for the first time based on given lithology and pumped volumes to match the treatment and diversion differential pressures. Final active fractures and stimulation efficiency were computed through etched geometry. The results showed a range of etched fracture length from 86 to 109 ft and width of 0.05 to 0.08 in. A similar approach was used for perforation system analysis. Diversion pills from 2 to 15 per well were investigated with a 5- to 12-bbl particulate diversion pill range. Finally, the β factor was calculated for each case based on the diversion material and system volumetric ratio. The parameter was plotted against the average diversion pressure achieved and showed an R2 of 0.87. Based on the comprehensive theoretical, numerical modeling, and field-coupled findings, a β factor of 0.8 to 1.0 is recommended for optimum diversion and production performance. For multiple cases, stimulation efficiency and production performance have been enhanced up to 200%. From the field results, it is evident that the design of near-wellbore diversion needs to be strategic. The unique diversion framework provides the basis for such a well- and reservoir-specific strategy. Proper and scientific use of diversion material and modeling can lead to advances in overall project management by optimizing the cost–efficiency–quality project triangle. Digital advancements with digitized cores, fluid systems, and advanced modeling have significant potential for the engineered development of tight carbonates.
{"title":"Validation of a Novel Beta Diversion Design Factor for Enhancing Stimulation Efficiency Through Field Cases and Near Wellbore Diversion Model","authors":"Abdulrahman A. Almulhim, AbdulMuqtadir Khan, Jon E. Hansen, Hashem Alobaid, D. Emelyanov","doi":"10.2118/210439-ms","DOIUrl":"https://doi.org/10.2118/210439-ms","url":null,"abstract":"\u0000 The design of fracture diversion in tight carbonates has been a challenging problem. Recently, a conceptual and theoretical workflow was presented using a β diversion design parameter that uses system volumetric calculations based on high-fidelity modeling and mathematical approximations of the etched system. A robust field validation of that approach and near-wellbore diversion modeling was conducted to extend the application.\u0000 Extensive laboratory and yard-scale testing data were utilized to realize the diversion processes. Fracture and perforation modeling coupled with fracture diagnostics was used to define system volumetrics, defined as the volume where the fluid needs to be diverted away from. Multimodal particulate pills were used based on a careful review of the size distribution and physical properties. Bottomhole reactions and post-fracturing production for multiple wells and 100 particulate pills were studied to see the effect of the β factor on diversion and production performance. A multiphysics near-wellbore diversion model was used for the first time to simulate the pill effect.\u0000 Representative wells were selected for the validation study; these included vertical and horizontal wells and varying perforation cluster design, stages, and acid treatments. A complex problem was solved with reaction modeling coupled with near-wellbore diversion for the first time based on given lithology and pumped volumes to match the treatment and diversion differential pressures. Final active fractures and stimulation efficiency were computed through etched geometry. The results showed a range of etched fracture length from 86 to 109 ft and width of 0.05 to 0.08 in. A similar approach was used for perforation system analysis. Diversion pills from 2 to 15 per well were investigated with a 5- to 12-bbl particulate diversion pill range. Finally, the β factor was calculated for each case based on the diversion material and system volumetric ratio. The parameter was plotted against the average diversion pressure achieved and showed an R2 of 0.87. Based on the comprehensive theoretical, numerical modeling, and field-coupled findings, a β factor of 0.8 to 1.0 is recommended for optimum diversion and production performance. For multiple cases, stimulation efficiency and production performance have been enhanced up to 200%.\u0000 From the field results, it is evident that the design of near-wellbore diversion needs to be strategic. The unique diversion framework provides the basis for such a well- and reservoir-specific strategy. Proper and scientific use of diversion material and modeling can lead to advances in overall project management by optimizing the cost–efficiency–quality project triangle. Digital advancements with digitized cores, fluid systems, and advanced modeling have significant potential for the engineered development of tight carbonates.","PeriodicalId":113697,"journal":{"name":"Day 2 Tue, October 04, 2022","volume":"108 5 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-09-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"126075206","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}
Miguel Gonzalez, Tim Thiel, Nathan St. Michel, J. Harrist, E. Buzi, H. Seren, S. Ayirala, Lyla Maskeen, A. Sofi
Polymer degradation during Enhanced Oil Recovery (EOR) can have large impact on recovery rates during polymer flooding. In the field, few practical solutions exist to perform quality control/assurance (QA/QC) on EOR polymer fluids at surface and no solutions exist for measurements downhole. Here, we present the development of a miniaturized sensor that can be used to detect the onset of polymer degradation by measuring the viscous properties of EOR polymer fluids. The device was tested on samples collected from a polymer flooding operation. We describe its integration into wellsite portable systems and into an untethered logging tool for cost-effective routine measurements downhole. The sensors are based on millimeter-sized piezoelectric tuning fork resonators. The viscosity and density of the fluids was measured from the energy dissipation and the resonant frequency obtained from their vibrational spectra. The devices were specially designed for use in high-salinity polymer fluids. They were tested and validated on samples collected from a single well polymer flood trial. A miniaturized electrical measurement platform was then designed for use at surface in the field and for use in a compact untethered logging tool for quick and inexpensive deployment downhole. The devices were initially calibrated in the laboratory and then tested on samples collected from the field. These two field-collected solutions were used to preflush the formation before injecting surfactant-polymer solution and as a polymer taper to drive the injected surfactant-polymer solution, respectively. The obtained viscosity values correlated very well with those obtained from standard laboratory measurements. Therefore, the changes in viscosity due to reduction in the molecular weight of the polymer, as measured with the miniature devices, can be used to assess whether degradation has taken place. A miniaturized electrical measurement platform was then tested in comparable polymer fluids for use in the field and obtained comparable results. The platforms described here provide a simple, cost-effective, and user-friendly platform for the detection of polymer degradation in the field, thus providing valuable information in real-time during costly polymer flooding operations.
{"title":"A New Viscosity Sensing Platform for the Assessment of Polymer Degradation in EOR Polymer Fluids","authors":"Miguel Gonzalez, Tim Thiel, Nathan St. Michel, J. Harrist, E. Buzi, H. Seren, S. Ayirala, Lyla Maskeen, A. Sofi","doi":"10.2118/210014-ms","DOIUrl":"https://doi.org/10.2118/210014-ms","url":null,"abstract":"\u0000 Polymer degradation during Enhanced Oil Recovery (EOR) can have large impact on recovery rates during polymer flooding. In the field, few practical solutions exist to perform quality control/assurance (QA/QC) on EOR polymer fluids at surface and no solutions exist for measurements downhole. Here, we present the development of a miniaturized sensor that can be used to detect the onset of polymer degradation by measuring the viscous properties of EOR polymer fluids. The device was tested on samples collected from a polymer flooding operation. We describe its integration into wellsite portable systems and into an untethered logging tool for cost-effective routine measurements downhole. The sensors are based on millimeter-sized piezoelectric tuning fork resonators. The viscosity and density of the fluids was measured from the energy dissipation and the resonant frequency obtained from their vibrational spectra. The devices were specially designed for use in high-salinity polymer fluids. They were tested and validated on samples collected from a single well polymer flood trial. A miniaturized electrical measurement platform was then designed for use at surface in the field and for use in a compact untethered logging tool for quick and inexpensive deployment downhole. The devices were initially calibrated in the laboratory and then tested on samples collected from the field. These two field-collected solutions were used to preflush the formation before injecting surfactant-polymer solution and as a polymer taper to drive the injected surfactant-polymer solution, respectively. The obtained viscosity values correlated very well with those obtained from standard laboratory measurements. Therefore, the changes in viscosity due to reduction in the molecular weight of the polymer, as measured with the miniature devices, can be used to assess whether degradation has taken place. A miniaturized electrical measurement platform was then tested in comparable polymer fluids for use in the field and obtained comparable results.\u0000 The platforms described here provide a simple, cost-effective, and user-friendly platform for the detection of polymer degradation in the field, thus providing valuable information in real-time during costly polymer flooding operations.","PeriodicalId":113697,"journal":{"name":"Day 2 Tue, October 04, 2022","volume":"31 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-09-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"126368721","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}
Zhihua Wang, Yunfei Xu, Jinling Li, Hankun Wang, Jiajun Hong, Bo Zhou, H. Pu
When wax deposition behavior occurs, gas condensate well suffers from moderate to serve reduction of productivity, even wellbore region blockage. For the operation and maintenance of a gas condensate well production system, a new methodology is needed to understand the wax deposition pattern in the wellbore region and assess the wax prevention under wellbore conditions. This paper establishes a phase envelope relationship in phase-behavior of typical condensate gas flow. The experiments map the potential deposition location in the wellbore region and capture the chemical wax inhibition performance in terms of wax appearance temperature (WAT), wax crystal morphology, and wax inhibiting rate, etc. The fluid component in wells for determining the envelope relationship in phase-behavior was corrected based on the gas-oil ratio of the actual gas condensate well and the carbon number distribution of the produced condensate oil-gas. The cold finger apparatus and dynamic wax inhibition measurement apparatus were designed to test wax deposition characteristics and evaluate chemical wax inhibition performance. The main test unit comprises a fully-closed high-pressure autoclave and cold finger capable of a maximum temperature of 285 °F and a maximum pressure of 16000 psi. The condensate mixtures were sampled from the wellbore region by downhole fluid sampling method. Starting from chemical wax prevention in wellbore flow, the wax crystal-improved wax inhibitor, which was mainly composed of long-chain hydrocarbons and polymers with polar groups, was employed. The temperature difference, intake pressure, stirring rate, and amount of wax inhibitor were controlled in the experiments. The wax content, WAT, and wax crystal structural characteristics of condensate systems showed noticeable differences from well to well. Using the matched component by the simulation, the wellbore temperature and pressure profiles are reliably predicted, and the envelope relationship in phase behavior of condensate gas flow is reasonably determined. Thermal and molecular diffusion are still the main mechanisms for driving wax deposition behavior in wellbore regions. The critical conditions for wax precipitation, wax deposition characteristics, and potential impact of wax deposition pattern are formulated. With the combined wellbore temperature and pressure profiles, the universal relationship schema for identifying deposition location is derived. The wax deposition location obtained from the schema agrees well with what was detected in actual production. Chemical wax prevention is an effective way to inhibit wax deposition. A maximum WAT reduction of 80% and a wax inhibiting rate of 90% could be achieved with the wax crystal improved wax inhibitor at a concentration of 0.25 wt.%. Understanding the wax deposition pattern in the wellbore region is significant for flow assurance and well operation. It provides evidence for wax prevention in wellbore flow and promotes deep condensate
{"title":"Wax Deposition Pattern in Wellbore Region of Deep Condensate Gas Reservoir and Its Prevention: A Combined Experimental and Simulation Study","authors":"Zhihua Wang, Yunfei Xu, Jinling Li, Hankun Wang, Jiajun Hong, Bo Zhou, H. Pu","doi":"10.2118/210338-ms","DOIUrl":"https://doi.org/10.2118/210338-ms","url":null,"abstract":"\u0000 When wax deposition behavior occurs, gas condensate well suffers from moderate to serve reduction of productivity, even wellbore region blockage. For the operation and maintenance of a gas condensate well production system, a new methodology is needed to understand the wax deposition pattern in the wellbore region and assess the wax prevention under wellbore conditions. This paper establishes a phase envelope relationship in phase-behavior of typical condensate gas flow. The experiments map the potential deposition location in the wellbore region and capture the chemical wax inhibition performance in terms of wax appearance temperature (WAT), wax crystal morphology, and wax inhibiting rate, etc. The fluid component in wells for determining the envelope relationship in phase-behavior was corrected based on the gas-oil ratio of the actual gas condensate well and the carbon number distribution of the produced condensate oil-gas. The cold finger apparatus and dynamic wax inhibition measurement apparatus were designed to test wax deposition characteristics and evaluate chemical wax inhibition performance. The main test unit comprises a fully-closed high-pressure autoclave and cold finger capable of a maximum temperature of 285 °F and a maximum pressure of 16000 psi. The condensate mixtures were sampled from the wellbore region by downhole fluid sampling method. Starting from chemical wax prevention in wellbore flow, the wax crystal-improved wax inhibitor, which was mainly composed of long-chain hydrocarbons and polymers with polar groups, was employed. The temperature difference, intake pressure, stirring rate, and amount of wax inhibitor were controlled in the experiments. The wax content, WAT, and wax crystal structural characteristics of condensate systems showed noticeable differences from well to well. Using the matched component by the simulation, the wellbore temperature and pressure profiles are reliably predicted, and the envelope relationship in phase behavior of condensate gas flow is reasonably determined. Thermal and molecular diffusion are still the main mechanisms for driving wax deposition behavior in wellbore regions. The critical conditions for wax precipitation, wax deposition characteristics, and potential impact of wax deposition pattern are formulated. With the combined wellbore temperature and pressure profiles, the universal relationship schema for identifying deposition location is derived. The wax deposition location obtained from the schema agrees well with what was detected in actual production. Chemical wax prevention is an effective way to inhibit wax deposition. A maximum WAT reduction of 80% and a wax inhibiting rate of 90% could be achieved with the wax crystal improved wax inhibitor at a concentration of 0.25 wt.%. Understanding the wax deposition pattern in the wellbore region is significant for flow assurance and well operation. It provides evidence for wax prevention in wellbore flow and promotes deep condensate ","PeriodicalId":113697,"journal":{"name":"Day 2 Tue, October 04, 2022","volume":"12 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2022-09-26","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"116792605","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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