Geothermal energy is a renewable energy that has vast potential due to its reliable energy supply. Its development has been related to specific geological locations with extremely high temperatures. However, depleted oil and gas reservoirs can produce geothermal energy from the subsurface. Repurposing this well can be a valuable tool to generate sustainable and steady energy for the state of Oklahoma due to its large number of wells used in the Oil and Gas industry. In fact, abandoned oil and gas wells are suitable candidates for conversion as these are environmental liabilities. The challenge is selecting which wells are good candidates for geothermal applications. This study aims to build an evaluation methodology to filter wells with a high potential for geothermal production. Three factors, temperature, proximity to the end user, and well integrity, are analyzed for evaluating possible candidates. Three datasets of temperature gradients were gathered from the Oklahoma Geological Survey, abandoned oil and gas wells from the Oklahoma Corporate Commission, and cities’ locations and populations from the US Census Bureau were combined. The objective is to evaluate the wells in Oklahoma to select promising candidates for repurposing for geothermal applications. Temperature prediction was made using Spatial Interpolation using Thiessen polygons, K-nearest Neighbors, and Kriging. K-nearest Neighbors exhibited the highest performance based on the evaluation metrics. Temperature prediction at an average true vertical depth of 6000 ft showed 26.7% or 4292 wells have more than 150 °F and can be converted for geothermal production. The shortest distance heuristic algorithm was used to calculate the shortest distance of each well to any city in Oklahoma. Before conversion, an evaluation of the well is required to assess the volumes and condition of the well; methods include statical analysis, logging, and evaluation techniques. These are discussed in this study. This study shows the high number of wells with the potential to be converted for geothermal applications converting a liability and environmental concern to a renewable energy-producing asset.
{"title":"A Robust Screening Tool to Repurpose Hydrocarbon Wells to Geothermal Wells in Oklahoma","authors":"Esteban R. Ugarte, S. Salehi","doi":"10.2118/213068-ms","DOIUrl":"https://doi.org/10.2118/213068-ms","url":null,"abstract":"\u0000 Geothermal energy is a renewable energy that has vast potential due to its reliable energy supply. Its development has been related to specific geological locations with extremely high temperatures. However, depleted oil and gas reservoirs can produce geothermal energy from the subsurface. Repurposing this well can be a valuable tool to generate sustainable and steady energy for the state of Oklahoma due to its large number of wells used in the Oil and Gas industry. In fact, abandoned oil and gas wells are suitable candidates for conversion as these are environmental liabilities. The challenge is selecting which wells are good candidates for geothermal applications. This study aims to build an evaluation methodology to filter wells with a high potential for geothermal production. Three factors, temperature, proximity to the end user, and well integrity, are analyzed for evaluating possible candidates. Three datasets of temperature gradients were gathered from the Oklahoma Geological Survey, abandoned oil and gas wells from the Oklahoma Corporate Commission, and cities’ locations and populations from the US Census Bureau were combined. The objective is to evaluate the wells in Oklahoma to select promising candidates for repurposing for geothermal applications. Temperature prediction was made using Spatial Interpolation using Thiessen polygons, K-nearest Neighbors, and Kriging. K-nearest Neighbors exhibited the highest performance based on the evaluation metrics. Temperature prediction at an average true vertical depth of 6000 ft showed 26.7% or 4292 wells have more than 150 °F and can be converted for geothermal production. The shortest distance heuristic algorithm was used to calculate the shortest distance of each well to any city in Oklahoma. Before conversion, an evaluation of the well is required to assess the volumes and condition of the well; methods include statical analysis, logging, and evaluation techniques. These are discussed in this study. This study shows the high number of wells with the potential to be converted for geothermal applications converting a liability and environmental concern to a renewable energy-producing asset.","PeriodicalId":360081,"journal":{"name":"Day 2 Tue, April 18, 2023","volume":"128 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-04-17","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"123712511","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}
Dahlia A. Al-Obaidi, David A. Wood, W. Al-Mudhafar, Andrew A. Wojtanowicz, A. Merzoug
Gas and downhole water sink assisted gravity drainage (GDWS-AGD) is a promising gas-based enhanced oil recovery (EOR) process applicable for reservoirs associated with infinite aquifers. However, it can be costly to implement because it typically involves the drilling of multiple vertical gas-injection wells. The drilling and well-completion costs can be substantially reduced by using additional completions for gas injection in the oil production wells through the annulus positioned at the top of the reservoir. Multi-completion-GDWS-AGD (MC-GDWS-AGD) can be configured to include separate completions for gas injection, oil, and water production in individual wells. This study simulates the MC-GDWS-AGD process applied to the synthetic reservoir (PUNQ-S3, based on a real North Sea Field) by placing multiple completions in two wells, which include a gas injection loop, and 2-horizontal wells with a diameter of 2⅜ inch, first one for producing oil located above the oil/water contact and the second one for water sink placed below the oil/water contact. Hydraulic packers are positioned to isolate the multiple completions and an electric submersible pump are positioned to produce the water zone. These results compare to a base case involving no MC-GDWS-AGD wells, which achieved 55.5% oil recovery and 70% water cut.
{"title":"Development of a Multi-Completion Gas and Downhole Water Sink-Assisted Gravity Drainage (MC-DWS-AGD) to Improve Oil Recovery and Reduce Water Cut in Reservoirs with Strong Water Aquifers","authors":"Dahlia A. Al-Obaidi, David A. Wood, W. Al-Mudhafar, Andrew A. Wojtanowicz, A. Merzoug","doi":"10.2118/213071-ms","DOIUrl":"https://doi.org/10.2118/213071-ms","url":null,"abstract":"\u0000 Gas and downhole water sink assisted gravity drainage (GDWS-AGD) is a promising gas-based enhanced oil recovery (EOR) process applicable for reservoirs associated with infinite aquifers. However, it can be costly to implement because it typically involves the drilling of multiple vertical gas-injection wells. The drilling and well-completion costs can be substantially reduced by using additional completions for gas injection in the oil production wells through the annulus positioned at the top of the reservoir. Multi-completion-GDWS-AGD (MC-GDWS-AGD) can be configured to include separate completions for gas injection, oil, and water production in individual wells. This study simulates the MC-GDWS-AGD process applied to the synthetic reservoir (PUNQ-S3, based on a real North Sea Field) by placing multiple completions in two wells, which include a gas injection loop, and 2-horizontal wells with a diameter of 2⅜ inch, first one for producing oil located above the oil/water contact and the second one for water sink placed below the oil/water contact. Hydraulic packers are positioned to isolate the multiple completions and an electric submersible pump are positioned to produce the water zone. These results compare to a base case involving no MC-GDWS-AGD wells, which achieved 55.5% oil recovery and 70% water cut.","PeriodicalId":360081,"journal":{"name":"Day 2 Tue, April 18, 2023","volume":"8 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-04-17","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"129205867","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}
There are many exciting and effective uses of digital technology in modern oil and gas operations. From drilling to completions, mid-stream to refining many advances have been made that are increasing compliance, safety, efficiency, and overall profit for many in our industry. One area that has been slower to change is onshore production operations. Many digital solution providers that have experience in the oil and gas industry have fallen short of this segment's needs. Multiple exploration and production (E&P) companies have attempted digital initiatives that have seen limited success. This may be due to not understanding the data needs, consumption requirements, and overall digital and organizational landscape of production operations. This paper attempts to illustrate five key ways that onshore upstream production operations differ from other aspects of oil and gas, and give considerations and guidance to digital solution providers and E&P companies so that the needed digital transformation can truly take hold within this sector. Devon Energy has made investments in the physical, technological, and human infrastructure necessary to improve its digital capabilities for production operations and all other facets of its business for many years. This paper draws on the observations and lessons from the author's experience working both alongside and within Devon's Production Technology organization.
{"title":"Effective Data Visualization and Analytics: Unique Considerations for Large Scale Production Operations","authors":"T. Stephenson","doi":"10.2118/213058-ms","DOIUrl":"https://doi.org/10.2118/213058-ms","url":null,"abstract":"\u0000 There are many exciting and effective uses of digital technology in modern oil and gas operations. From drilling to completions, mid-stream to refining many advances have been made that are increasing compliance, safety, efficiency, and overall profit for many in our industry. One area that has been slower to change is onshore production operations. Many digital solution providers that have experience in the oil and gas industry have fallen short of this segment's needs. Multiple exploration and production (E&P) companies have attempted digital initiatives that have seen limited success. This may be due to not understanding the data needs, consumption requirements, and overall digital and organizational landscape of production operations. This paper attempts to illustrate five key ways that onshore upstream production operations differ from other aspects of oil and gas, and give considerations and guidance to digital solution providers and E&P companies so that the needed digital transformation can truly take hold within this sector.\u0000 Devon Energy has made investments in the physical, technological, and human infrastructure necessary to improve its digital capabilities for production operations and all other facets of its business for many years. This paper draws on the observations and lessons from the author's experience working both alongside and within Devon's Production Technology organization.","PeriodicalId":360081,"journal":{"name":"Day 2 Tue, April 18, 2023","volume":"28 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-04-17","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"129638391","PeriodicalName":null,"FirstCategoryId":null,"ListUrlMain":null,"RegionNum":0,"RegionCategory":"","ArticlePicture":[],"TitleCN":null,"AbstractTextCN":null,"PMCID":"","EPubDate":null,"PubModel":null,"JCR":null,"JCRName":null,"Score":null,"Total":0}
To meet the increasing demand for oil and gas, surfactants have been used to increase hydrocarbon recovery. Use of surfactants reduces the Interfacial Tension (IFT) at fluid/fluid interface and wettability at rock/fluid interface and mobilizes trapped oil out of the pores. However, there are two main limitations of the surfactant flooding process—first, high reservoir temperature & salinity, and second, adsorption of surfactants on the rock surface. Surfactant adsorption alters wettability of reservoir rock from oil-wet to water-wet. However, it may not increase oil recovery, especially in conventional reservoirs with high Total Dissolved Solids (TDS) and temperature due to excess surfactant adsorption. This study tested two synthetic amphoteric surfactants, one nonionic biosurfactant, and a base case with produced brine to understand wettability, IFT, surfactant adsorption, and their effect on oil recovery in shaly sandstone formation. Produced brine has a TDS of 238,000 ppm. First, surfactant stability tests were performed on the three surfactants. Then, IFT measurements were performed between crude oil and surfactant solutions along with produced brine. Next, wettability alteration was studied by measuring contact angle on oil saturated rock samples before and after being exposed with surfactants and produced brine. Then, surfactant adsorption experiments were performed using UV-Vis spectrophotometer to calculate the amount of surfactant adsorbed on the rock sample. Next, surfactants and produced brine imbibition experiments were performed on plug samples at 145°F and 500 psi pressure, and oil recovery was quantified using 12MHz Nuclear Magnetic Resonance (NMR) spectrometer. Results showed that all three surfactants reduced IFT and altered wettability, but biosurfactant showed most reduction of IFT, much lower surfactant adsorption, and made the sample most water wet as compared to amphoteric surfactants. Imbibition experiments showed that biosurfactant have the highest oil recovery, while amphoteric surfactants have oil recovery even lower than produced brine. This study shows that surfactant adsorption effects oil recovery, which can lead to loss of surfactants from solution to the rock surface. This study suggests that biosurfactants with glycolipids can be effectively used in shaly sandstone at high TDS and temperature.
{"title":"Experimental Investigation of Amphoteric and Microbial Surfactants for Enhanced Oil Recovery in Shaly Sandstones","authors":"Rishabh Pandey, A. Tinni, C. Rai","doi":"10.2118/213102-ms","DOIUrl":"https://doi.org/10.2118/213102-ms","url":null,"abstract":"\u0000 To meet the increasing demand for oil and gas, surfactants have been used to increase hydrocarbon recovery. Use of surfactants reduces the Interfacial Tension (IFT) at fluid/fluid interface and wettability at rock/fluid interface and mobilizes trapped oil out of the pores. However, there are two main limitations of the surfactant flooding process—first, high reservoir temperature & salinity, and second, adsorption of surfactants on the rock surface. Surfactant adsorption alters wettability of reservoir rock from oil-wet to water-wet. However, it may not increase oil recovery, especially in conventional reservoirs with high Total Dissolved Solids (TDS) and temperature due to excess surfactant adsorption. This study tested two synthetic amphoteric surfactants, one nonionic biosurfactant, and a base case with produced brine to understand wettability, IFT, surfactant adsorption, and their effect on oil recovery in shaly sandstone formation. Produced brine has a TDS of 238,000 ppm. First, surfactant stability tests were performed on the three surfactants. Then, IFT measurements were performed between crude oil and surfactant solutions along with produced brine. Next, wettability alteration was studied by measuring contact angle on oil saturated rock samples before and after being exposed with surfactants and produced brine. Then, surfactant adsorption experiments were performed using UV-Vis spectrophotometer to calculate the amount of surfactant adsorbed on the rock sample. Next, surfactants and produced brine imbibition experiments were performed on plug samples at 145°F and 500 psi pressure, and oil recovery was quantified using 12MHz Nuclear Magnetic Resonance (NMR) spectrometer. Results showed that all three surfactants reduced IFT and altered wettability, but biosurfactant showed most reduction of IFT, much lower surfactant adsorption, and made the sample most water wet as compared to amphoteric surfactants. Imbibition experiments showed that biosurfactant have the highest oil recovery, while amphoteric surfactants have oil recovery even lower than produced brine. This study shows that surfactant adsorption effects oil recovery, which can lead to loss of surfactants from solution to the rock surface. This study suggests that biosurfactants with glycolipids can be effectively used in shaly sandstone at high TDS and temperature.","PeriodicalId":360081,"journal":{"name":"Day 2 Tue, April 18, 2023","volume":"46 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-04-17","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"114053595","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}
Tim Marvel, Austin M. Johnson, Phillip Douget, Michael Mast, John N. Dyer, Jordan Kuehn, B. Wiesner
Primary barriers to fracturing the reservoir 24/7 have been identified as 1) the time between stages (this includes transition time and pressure tests), 2) downtime associated with gate valve maintenance and failures, 3) frac pump maintenance and 4) sand and water logistics. Following a prescribed roadmap, a system has been developed with new subsystems and processes to eliminate these identified barriers through novel products and automated workflows resulting in fracturing the reservoir more hours per day with the goal of reaching 24 hours a day, 7 days a week (please note the difference between being on a frac site 24/7, which occurs today, and fracturing the reservoir 24/7). The system eliminates the time between stages with rapid, automated transitions from one stage to the next enabling operators to continuously pump for the duration of the completion. Utilizing automated workflows, interlocks with wireline and frac systems, control systems, and RFID, the system eliminates NPT associated with stage-to-stage transitions. An addition to the system that enables the exchange of pumps during frac operations without stopping the frac has gone through initial field trials, with a second iteration soon to be deployed. Although the overall system does not directly solve logistic issues (i.e. sand and water shortages), the demonstrated consistency achieved using the system enables better planning of resources. A summary of the system’s accomplishments, some previously disclosed, some new, will be presented. The system has broken multiple pumping records across US basins including hours pumped continuously and stages completed. In addition, the system has over a dozen industry "firsts" that have advanced completion practices, reduced NPT, and eliminated transition time. The paper highlights new additions to the system including the automated lubricator, automated greasing algorithms, and the ability to exchange a pump truck while fracturing. Utilizing the plentiful data provided by the system, specific case histories are documented highlighting the gains in operational efficiency, consistency and safety resulting from the new system.
{"title":"Automated Completion Surface System: The Path to Fracturing 24/7","authors":"Tim Marvel, Austin M. Johnson, Phillip Douget, Michael Mast, John N. Dyer, Jordan Kuehn, B. Wiesner","doi":"10.2118/213101-ms","DOIUrl":"https://doi.org/10.2118/213101-ms","url":null,"abstract":"\u0000 Primary barriers to fracturing the reservoir 24/7 have been identified as 1) the time between stages (this includes transition time and pressure tests), 2) downtime associated with gate valve maintenance and failures, 3) frac pump maintenance and 4) sand and water logistics.\u0000 Following a prescribed roadmap, a system has been developed with new subsystems and processes to eliminate these identified barriers through novel products and automated workflows resulting in fracturing the reservoir more hours per day with the goal of reaching 24 hours a day, 7 days a week (please note the difference between being on a frac site 24/7, which occurs today, and fracturing the reservoir 24/7).\u0000 The system eliminates the time between stages with rapid, automated transitions from one stage to the next enabling operators to continuously pump for the duration of the completion. Utilizing automated workflows, interlocks with wireline and frac systems, control systems, and RFID, the system eliminates NPT associated with stage-to-stage transitions. An addition to the system that enables the exchange of pumps during frac operations without stopping the frac has gone through initial field trials, with a second iteration soon to be deployed. Although the overall system does not directly solve logistic issues (i.e. sand and water shortages), the demonstrated consistency achieved using the system enables better planning of resources.\u0000 A summary of the system’s accomplishments, some previously disclosed, some new, will be presented. The system has broken multiple pumping records across US basins including hours pumped continuously and stages completed. In addition, the system has over a dozen industry \"firsts\" that have advanced completion practices, reduced NPT, and eliminated transition time. The paper highlights new additions to the system including the automated lubricator, automated greasing algorithms, and the ability to exchange a pump truck while fracturing. Utilizing the plentiful data provided by the system, specific case histories are documented highlighting the gains in operational efficiency, consistency and safety resulting from the new system.","PeriodicalId":360081,"journal":{"name":"Day 2 Tue, April 18, 2023","volume":"10 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-04-17","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"122733723","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}
Current hydraulic fracturing strategies require a significant investment of resources, time, and capital to warrant well productivity. As a result, it has become the crux of asset development in unconventional formations. Given that this technique has been in full force for almost two decades, the optimization strategies couldn't be more varied than they are today. Part of the problem exists in completion teams discretizing and optimizing individual facets while ignoring their impact on the entire system. To the authors’ knowledge, this paper is the first to present a comprehensive energy analysis of the hydraulic fracturing process. During hydraulic fracturing, energy transfer originates from the horsepower equipment used to inject a unit volume of fluid, containing a certain volume fraction of proppant, into the wellhead. Surface energy consumption is defined as the horsepower deployment integrated over time. As this unit volume traverses down the wellbore and into the formation, it is assisted by gravitational potential energy, which supplements its energy budget but must overcome the friction from the pipe, perforations, and tortuous near-wellbore zone, which act as energy losses. Subtracting energy losses from the total energy input results in the effective energy delivered to formation. With the tools outlined here to calculate the effective energy and energy efficiency, teams can vet and optimize their completion strategies to maximize energy delivered to the formation and/or improve capital efficiency. These metrics are sensitive to most of the variables involved in well completions and provide an understanding of the influence every decision has on the complete hydraulic fracturing system.
{"title":"Delineating and Quantifying the Hydraulic Fracturing Energy System","authors":"Awais Navaiz, P. Stark, J. Doucette","doi":"10.2118/213076-ms","DOIUrl":"https://doi.org/10.2118/213076-ms","url":null,"abstract":"\u0000 Current hydraulic fracturing strategies require a significant investment of resources, time, and capital to warrant well productivity. As a result, it has become the crux of asset development in unconventional formations. Given that this technique has been in full force for almost two decades, the optimization strategies couldn't be more varied than they are today. Part of the problem exists in completion teams discretizing and optimizing individual facets while ignoring their impact on the entire system.\u0000 To the authors’ knowledge, this paper is the first to present a comprehensive energy analysis of the hydraulic fracturing process. During hydraulic fracturing, energy transfer originates from the horsepower equipment used to inject a unit volume of fluid, containing a certain volume fraction of proppant, into the wellhead. Surface energy consumption is defined as the horsepower deployment integrated over time. As this unit volume traverses down the wellbore and into the formation, it is assisted by gravitational potential energy, which supplements its energy budget but must overcome the friction from the pipe, perforations, and tortuous near-wellbore zone, which act as energy losses. Subtracting energy losses from the total energy input results in the effective energy delivered to formation.\u0000 With the tools outlined here to calculate the effective energy and energy efficiency, teams can vet and optimize their completion strategies to maximize energy delivered to the formation and/or improve capital efficiency. These metrics are sensitive to most of the variables involved in well completions and provide an understanding of the influence every decision has on the complete hydraulic fracturing system.","PeriodicalId":360081,"journal":{"name":"Day 2 Tue, April 18, 2023","volume":"17 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-04-17","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"130046256","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}
When operators develop shale gas reservoirs in the southern Sichuan basin in China, they encountered numerous occurrences of casing deformations (CD) and even failures. The high frequency and severity of CD have led to significant financial loss. Since then, a considerable amount of research has been conducted with some field trials. Some research findings have been implemented in fields. The purpose of this paper is to present what we know and the trial results. We observed that casing deformation/failure were mainly in shearing failure and collapse modes. In the early stage of the development, most of the failure was due to shearing deformation caused by pre-existing geological features such as faults and weak interfaces. With the depletion of the reservoir and pressure decrease, casing collapses during the hydraulic fracture with extended length have become more and more popular in the later development stage. Laboratory tests on casing material and cementing material have shad lights on possible solutions. Increasing the casing wall thickness and cement thickness seems a viable solution for casing collapse, but the application of these recommendations yielded little effectiveness in mitigating casing deformation. Current operators redesigned a cementing material with high-strength beads which would collapse when stresses are above the designed threshold, which would "absorb" the formation displacement and reduce the severity of casing deformation caused by the aforementioned mechanisms. This paper summarizes the main research results from implementing numerical modeling and simulation. Based on that, we designed a special cementing with hollow high-strength particles in the cement slurry. In the later stage of fracturing, when the stress is above a threshold, the particles would burst and allow the casing to nudge slightly so that the deformation severity would be much less and more graduate. We implemented the new technology on 14 wells, and so far eight wells have been successfully completed without losses of horizontal segments. This new technology certainly brings hope for future study and provides field cases for future simulation work and laboratory studies for improvement.
{"title":"Casing Deformation and Controlling Methods During Hydraulic Fracturing Shale Gas Reservoirs in China: What We Known and Tried","authors":"Lihong Han, Shang-yu Yang, Lei Dai, Jing Cao, Yisheng Mou, Xingru Wu","doi":"10.2118/213072-ms","DOIUrl":"https://doi.org/10.2118/213072-ms","url":null,"abstract":"\u0000 When operators develop shale gas reservoirs in the southern Sichuan basin in China, they encountered numerous occurrences of casing deformations (CD) and even failures. The high frequency and severity of CD have led to significant financial loss. Since then, a considerable amount of research has been conducted with some field trials. Some research findings have been implemented in fields. The purpose of this paper is to present what we know and the trial results.\u0000 We observed that casing deformation/failure were mainly in shearing failure and collapse modes. In the early stage of the development, most of the failure was due to shearing deformation caused by pre-existing geological features such as faults and weak interfaces. With the depletion of the reservoir and pressure decrease, casing collapses during the hydraulic fracture with extended length have become more and more popular in the later development stage. Laboratory tests on casing material and cementing material have shad lights on possible solutions. Increasing the casing wall thickness and cement thickness seems a viable solution for casing collapse, but the application of these recommendations yielded little effectiveness in mitigating casing deformation. Current operators redesigned a cementing material with high-strength beads which would collapse when stresses are above the designed threshold, which would \"absorb\" the formation displacement and reduce the severity of casing deformation caused by the aforementioned mechanisms.\u0000 This paper summarizes the main research results from implementing numerical modeling and simulation. Based on that, we designed a special cementing with hollow high-strength particles in the cement slurry. In the later stage of fracturing, when the stress is above a threshold, the particles would burst and allow the casing to nudge slightly so that the deformation severity would be much less and more graduate. We implemented the new technology on 14 wells, and so far eight wells have been successfully completed without losses of horizontal segments. This new technology certainly brings hope for future study and provides field cases for future simulation work and laboratory studies for improvement.","PeriodicalId":360081,"journal":{"name":"Day 2 Tue, April 18, 2023","volume":"1 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-04-17","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"124388626","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}
Geothermal energy has vast potential as a reliable energy source of the future. However, its development has mostly been tied to specific geological locations or igneous rocks. Even though most western US regions have high thermal gradients compared to other places, higher temperatures are easily achievable by increasing the total depth in sedimentary rocks. The oil and gas industry has successfully mastered drilling sedimentary basins cost-effectively. Comparing cost/ft from typical sedimentary basins to granite or igneous rocks shows a tremendous difference. In addition, recent hydraulic fracturing technology transfer from the oil and gas industry can be deployed for geothermal applications. A potential new path toward expanded geothermal energy production is to use known porous and permeable reservoir rocks in appropriate sedimentary basins, where those formations have a sufficient temperature, thickness, porosity, and permeability, existing at depths that drilling time makes well construction costs economical for geothermal applications. In this paper, we will examine the unique potentials that sedimentary basins in Oklahoma offer to the geothermal industry for different end-user purposes, such as electricity generation or direct heat applications. The state has high geothermal gradients in some regions in the Arkoma Anadarko Basins that could be used for medium-temperature resources. Case studies from Oklahoma show how the many oil and gas wells in the state can enable geothermal direct-use projects. A state-wide levelized cost of energy analysis using geothermal gradient data indicates that there are areas with the potential to produce geothermal power at 14 cents/kWh or less. Geothermal energy has the potential to play a crucial role in Oklahoma's energy supply by offering a clean and renewable source of power that can fulfill energy demands.
{"title":"Scalable Geothermal Energy Potential from Sedimentary Basins in Oklahoma","authors":"C. Vivas, S. Salehi, R. Nygaard, Danny Rehg","doi":"10.2118/213094-ms","DOIUrl":"https://doi.org/10.2118/213094-ms","url":null,"abstract":"\u0000 Geothermal energy has vast potential as a reliable energy source of the future. However, its development has mostly been tied to specific geological locations or igneous rocks. Even though most western US regions have high thermal gradients compared to other places, higher temperatures are easily achievable by increasing the total depth in sedimentary rocks. The oil and gas industry has successfully mastered drilling sedimentary basins cost-effectively. Comparing cost/ft from typical sedimentary basins to granite or igneous rocks shows a tremendous difference. In addition, recent hydraulic fracturing technology transfer from the oil and gas industry can be deployed for geothermal applications.\u0000 A potential new path toward expanded geothermal energy production is to use known porous and permeable reservoir rocks in appropriate sedimentary basins, where those formations have a sufficient temperature, thickness, porosity, and permeability, existing at depths that drilling time makes well construction costs economical for geothermal applications.\u0000 In this paper, we will examine the unique potentials that sedimentary basins in Oklahoma offer to the geothermal industry for different end-user purposes, such as electricity generation or direct heat applications. The state has high geothermal gradients in some regions in the Arkoma Anadarko Basins that could be used for medium-temperature resources. Case studies from Oklahoma show how the many oil and gas wells in the state can enable geothermal direct-use projects. A state-wide levelized cost of energy analysis using geothermal gradient data indicates that there are areas with the potential to produce geothermal power at 14 cents/kWh or less. Geothermal energy has the potential to play a crucial role in Oklahoma's energy supply by offering a clean and renewable source of power that can fulfill energy demands.","PeriodicalId":360081,"journal":{"name":"Day 2 Tue, April 18, 2023","volume":"14 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-04-17","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"115234303","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}
Geothermal sites have unique features that require tailored approaches when it comes to production and recovery forecasts. This article explores the latest technologies, and the current challenges that simulation methods face for these types of systems Objectives are to establish this work as a robust literature reference for researchers searching for a guide to assist their future investigations. At the end of their cycles, low permeability hydrothermal sites, low fracture reservoirs, or over-exploited wells are ideal candidates to become enhanced geothermal systems, but to get to this point; optimization processes need to be performed on these sites. Building from earlier models that measure both wellhead temperature and pressure and considering the important challenges to current geothermal systems modeling, we advance a framework that embraces more novel computational techniques that strive towards capturing 3D fluid flow dynamics, as well as potential interactions between aqueous fluids, gases, and porosity and permeability changes brought by the dissolution and transformation of minerals inside the well. The development of more novel models has improved the capabilities for working with increasingly larger quantities of data while also delivering accurate estimations when some data is missing or incomplete. Additionally, the advent of artificial intelligence techniques has aided engineers in modeling quasi-three-dimensional mass transport and fluid flow dynamics, as well as chemical and physical interactions within low-porosity reservoirs. Our review highlights the appearance of two important mathematical models that rely on nonlinear partial differential equations that cover fluid pressure, enthalpy, and boundary conditions. With that said, capturing those interactions in 3D models that are robust and efficient remains a steep challenge for researchers. Through this work, we ultimately offer a roadmap to developing models to combat these limitations. Geothermal systems have been understudied as some consider these wells afterthoughts within oil and gas operations, but more novel methods can significantly improve reservoir simulation for these sites. This work provides a window into the newest advances and techniques while also providing a framework for their use to engineers looking to optimize them.
{"title":"Challenges and Recent Advances in Modeling and Simulation of Geothermal Systems","authors":"M. Yurukcu, J. Saldana, C. Temizel, S. Arbabi","doi":"10.2118/213092-ms","DOIUrl":"https://doi.org/10.2118/213092-ms","url":null,"abstract":"\u0000 Geothermal sites have unique features that require tailored approaches when it comes to production and recovery forecasts. This article explores the latest technologies, and the current challenges that simulation methods face for these types of systems Objectives are to establish this work as a robust literature reference for researchers searching for a guide to assist their future investigations.\u0000 At the end of their cycles, low permeability hydrothermal sites, low fracture reservoirs, or over-exploited wells are ideal candidates to become enhanced geothermal systems, but to get to this point; optimization processes need to be performed on these sites. Building from earlier models that measure both wellhead temperature and pressure and considering the important challenges to current geothermal systems modeling, we advance a framework that embraces more novel computational techniques that strive towards capturing 3D fluid flow dynamics, as well as potential interactions between aqueous fluids, gases, and porosity and permeability changes brought by the dissolution and transformation of minerals inside the well.\u0000 The development of more novel models has improved the capabilities for working with increasingly larger quantities of data while also delivering accurate estimations when some data is missing or incomplete. Additionally, the advent of artificial intelligence techniques has aided engineers in modeling quasi-three-dimensional mass transport and fluid flow dynamics, as well as chemical and physical interactions within low-porosity reservoirs. Our review highlights the appearance of two important mathematical models that rely on nonlinear partial differential equations that cover fluid pressure, enthalpy, and boundary conditions. With that said, capturing those interactions in 3D models that are robust and efficient remains a steep challenge for researchers. Through this work, we ultimately offer a roadmap to developing models to combat these limitations.\u0000 Geothermal systems have been understudied as some consider these wells afterthoughts within oil and gas operations, but more novel methods can significantly improve reservoir simulation for these sites. This work provides a window into the newest advances and techniques while also providing a framework for their use to engineers looking to optimize them.","PeriodicalId":360081,"journal":{"name":"Day 2 Tue, April 18, 2023","volume":"11 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-04-17","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"125658585","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}
Camila Ortiz, G. Taitt, Angel Balzan, Tony Viator, Ramiro Fux Campa
Attaining peak efficiency in zipper fracturing operations is an important objective for oil and gas companies. More-complex operations result in greater efficiency but also demand the use of digitalization to maximize safety and performance. A digital technology using industrial Internet of things (IIoT) edge computing and cloud analytics for the automation and control of frac valves is presented. It enables operators to deliver more fracturing stages with less nonproductive time (NPT) while enhancing visibility, safety, and integrity. The digital solution integrates supervisory applications, control systems with programmable logic controllers (PLCs), networking devices, instrumentation, digitally enabled skids, and cloud solutions. The system uses an edge application that provides the ability to monitor valve status, control valve actuation, and automate valve greasing, using customizable software workflows and safety controls and alerts following standards managing wellsite safety. It eliminates valve operational errors using enforced workflows and interlocks based on operational awareness and instrumentation. The unintentional cutting of wireline (WL) has effectively been eliminated through the use of a proprietary detection algorithm that uses input from nonintrusive and intrinsically safe sensors in real time. Pumping detection algorithms eliminate human error and prevent the overpressurization of valves using interlocks embedded in the software. Using digitally enabled controls that streamline frac tree and manifold valve operations, operators can reduce safety risks by reducing the headcount on location and eliminating red-zone activities; operational integrity is secured by enforcing the digital handshake and providing isolation valve interlocks between the well stimulation and well control equipment to prevent overpressurizing or washing out the frac valves. By integrating complex new workflows and flow control technology with digital controls, transition times are shortened, enabling maximum pumping time per day. The operational integrity provided by the embedded safety interlocks empowers operators to operate efficiently and without worrying about safety. The system uses a design language system-type web application, which has proven to be effective, consistent, and intuitive. Using ruggedized tablets and operating 100% remotely, the field technicians have found the system to be easy to understand and operate. The edge application has completed more than 10,872 stages in more than 258 wells, and data has been collected that verifies that the cost of ownership has been reduced by double digits. The number of completed fracturing stages in a day has increased by 50%, the transition (non pumping) time has been reduced by 41%, and valves are being greased outside of the critical path. The presence of personnel in the red zone has been eliminated, and only one service technician is required to operate the valves and perform maintenance
{"title":"Introducing Digitalization and Automation for Improvements in Fracturing Operational Efficiency and Safety","authors":"Camila Ortiz, G. Taitt, Angel Balzan, Tony Viator, Ramiro Fux Campa","doi":"10.2118/213098-ms","DOIUrl":"https://doi.org/10.2118/213098-ms","url":null,"abstract":"\u0000 Attaining peak efficiency in zipper fracturing operations is an important objective for oil and gas companies. More-complex operations result in greater efficiency but also demand the use of digitalization to maximize safety and performance. A digital technology using industrial Internet of things (IIoT) edge computing and cloud analytics for the automation and control of frac valves is presented. It enables operators to deliver more fracturing stages with less nonproductive time (NPT) while enhancing visibility, safety, and integrity.\u0000 The digital solution integrates supervisory applications, control systems with programmable logic controllers (PLCs), networking devices, instrumentation, digitally enabled skids, and cloud solutions. The system uses an edge application that provides the ability to monitor valve status, control valve actuation, and automate valve greasing, using customizable software workflows and safety controls and alerts following standards managing wellsite safety. It eliminates valve operational errors using enforced workflows and interlocks based on operational awareness and instrumentation. The unintentional cutting of wireline (WL) has effectively been eliminated through the use of a proprietary detection algorithm that uses input from nonintrusive and intrinsically safe sensors in real time. Pumping detection algorithms eliminate human error and prevent the overpressurization of valves using interlocks embedded in the software.\u0000 Using digitally enabled controls that streamline frac tree and manifold valve operations, operators can reduce safety risks by reducing the headcount on location and eliminating red-zone activities; operational integrity is secured by enforcing the digital handshake and providing isolation valve interlocks between the well stimulation and well control equipment to prevent overpressurizing or washing out the frac valves. By integrating complex new workflows and flow control technology with digital controls, transition times are shortened, enabling maximum pumping time per day. The operational integrity provided by the embedded safety interlocks empowers operators to operate efficiently and without worrying about safety.\u0000 The system uses a design language system-type web application, which has proven to be effective, consistent, and intuitive. Using ruggedized tablets and operating 100% remotely, the field technicians have found the system to be easy to understand and operate. The edge application has completed more than 10,872 stages in more than 258 wells, and data has been collected that verifies that the cost of ownership has been reduced by double digits. The number of completed fracturing stages in a day has increased by 50%, the transition (non pumping) time has been reduced by 41%, and valves are being greased outside of the critical path. The presence of personnel in the red zone has been eliminated, and only one service technician is required to operate the valves and perform maintenance","PeriodicalId":360081,"journal":{"name":"Day 2 Tue, April 18, 2023","volume":"154 1","pages":"0"},"PeriodicalIF":0.0,"publicationDate":"2023-04-17","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"114041706","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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