Journal of Petroleum Technology最新文献

{"title":"High-Pressure Separation: New Technology in the Subsea Toolbox","authors":"J. Presley","doi":"10.2118/0224-0030-jpt","DOIUrl":"https://doi.org/10.2118/0224-0030-jpt","url":null,"abstract":"\u0000 \u0000 Subsea production systems have come far in the more than 60 years since the first deployment in the US Gulf of Mexico, helping many countries unlock their offshore hydrocarbon riches in the years that followed.\u0000 For Brazil, it was a combination of advances in subsea technologies and floating production, storage, and offloading vessel (FPSO) designs that supported the growth of its offshore oil and gas prowess.\u0000 From those first forays into the Sergipe-Alagoas basin in the northeast during the 1970s, the country’s offshore oil and gas footprint has grown significantly, with today’s production from the pre-salt Campos and Santos basins—located farther from shore and in much deeper water—launching state-run oil company Petrobras to a top spot among the ranks of global producers.\u0000 The ongoing development of its offshore fields will continue to boost the country’s oil and natural gas production in 2024. Since December 2022, five FPSOs have been brought online, with four installed in 2023 delivering record output. The fifth one—the FPSO Sepetiba—delivered a New Year’s Day surprise when it came online at Mero 2 oil field on 31 December 2023.\u0000 HISEP, a new subsea technology currently being readied for pilot testing, could potentially ensure continued future production of the Mero field and others by capturing CO2-rich dense gases directly from the wellstream and reinjecting it into the reservoir. The technology also frees up much-needed space and reduces weight on the FPSO’s topside by moving the separation process to the seafloor.\u0000 \u0000 \u0000 \u0000 Brazil’s challenging offshore pre-salt region—first explored by Petrobras in 2005—contains estimated reserves of 30 to 40 billion BOE and comes with an extensive list of development challenges.\u0000 Its Santos Basin, for example, lies in ultradeep water with hydrocarbon reservoirs located at extreme depths ranging from 5500 to 7600 m below sea level and under salt layers more than 2000 m thick.\u0000 But the challenges do not end there. Managing the basin’s high gas/oil ratio (GOR) and CO2 content leaves a significant operational footprint.\u0000 In OTC 29762, authors from Petrobras noted that developing the pre-salt reservoirs requires “large production facilities with complex gas processing plants that limit the oil processing and storage capacities.”\u0000 In the paper presented at the 2019 Offshore Technology Conference (OTC) Brasil, the authors said that the gas processing plants for some pre-salt fields with high production indexes, GOR, and CO2 content account for nearly 60% of the total FPSO topsides area.\u0000 The Santos Basin is home to the Mero oil field, the country’s third-largest pre-salt field and the first under a production-sharing contract awarded to the Petrobras-led Libra Consortium.\u0000 The field is considered one of the largest hydrocarbon discoveries in the past decade, covering about 320 km2 of the Libra block and with a net pay zone reaching 420 m filled with 29 °API oil and high productivity, according to Ana Luiza ","PeriodicalId":16720,"journal":{"name":"Journal of Petroleum Technology","volume":"67 5-6","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"139879874","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}

{"title":"Q&A With Dennis Denney, JPT Technology Focus Creator","authors":"C. Carpenter","doi":"10.2118/0224-0041-jpt","DOIUrl":"https://doi.org/10.2118/0224-0041-jpt","url":null,"abstract":"\u0000 \u0000 In 1997, JPT debuted a monthly feature that represented an unconventional approach in meeting SPE’s goal of disseminating technical information to its members. Soon titled “Technology Focus,” the feature brought together subject-matter experts (SMEs) in a range of important industry topics to review technical-paper abstracts gathered from the previous year of SPE meetings, as well as the Offshore Technology Conference. Its architect, engineer, and pilot was Technology Editor Dennis Denney, who would become a familiar presence to SPE members and staff alike over a 17-year career, although his industry roots extended to his college days.\u0000 Dennis helped recruit SMEs for review service; sent them hundreds of abstracts and full papers (monthly, that is; the cumulative count of papers he handled is likely a six-digit figure); answered their questions and concerns with prompt, supportive guidance; and then, once papers had been selected, synopsized them for publication in the magazine with the longtime help of Assistant Technology Editor Karen Bybee.\u0000 As this writer well knows, condensing a 10,000-word paper on, say, distributed quasi-Newton derivative-free optimization methods for field development optimization into a 1,500-word summary that captures the novelty and technical sophistication of its authors’ work can be a daunting task. Applying his own background as a petroleum engineer to methodically analyze and trim each chosen paper, Dennis did just that dozens of times a year, transforming these texts into svelte packages that included only one table or figure to deliver the highest possible quantity of quality to JPT readers.\u0000 When Dennis retired in 2013, I initially split his eyebrow-raising workload with fellow Technology Editor Adam Wilson (now JPT’s Special Publications Editor). It was immediately clear from the way that reviewers spoke about Dennis, and his contributions to the magazine and SPE itself, that he was held in the same high regard outside of the organization as he was within it, a testament to the reputation he had earned while working with so many members and SMEs.\u0000 It was entirely fitting that, for JPT’s 75th anniversary celebration, we caught up with Dennis to reflect on his achievements in the industry and with the groundbreaking Technology Focus feature he created.\u0000 Dennis lives with his wife Linda in Rockwall, Texas—not too far from SPE headquarters in Dallas, but not too close, either!—enjoying his retirement and his family.\u0000 (Note: For more on the development and history of the Technology Focus features, read the companion piece to this article, “Technology Focus Topics Reflect Industry Growth, Evolution Over 25+ Years.”)\u0000 \u0000 \u0000 \u0000 I worked several years as an engineering tech, testing gas wells, tracking well and reservoir pressures, and writing computer programs to analyze pressure data. The department manager encouraged me to finish my degree and become a petroleum engineer. So, after I received a scholarship from J. H","PeriodicalId":16720,"journal":{"name":"Journal of Petroleum Technology","volume":"2 2","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"139879916","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}

{"title":"President’s Column with Terry Palisch: The Value of Publishing Technical Papers for Your Career","authors":"Terry Palisch","doi":"10.2118/0224-0004-jpt","DOIUrl":"https://doi.org/10.2118/0224-0004-jpt","url":null,"abstract":"\u0000 \u0000 This transcript is an excerpt from the podcast episode.\u0000 \u0000 \u0000 \u0000 Hello, I’m Bryan Hibbard, senior editorial operations manager for SPE, I’m pleased to join 2024 President Terry Palisch as he continues his discussion about the ways we connect our members to technology by focusing on SPE papers, JPT, and other SPE publications. Terry, thank you for inviting me.\u0000 \u0000 \u0000 \u0000 Thank you for joining me, Bryan. I appreciate you taking the time to be the host. I thought you would make a good host for this topic.\u0000 In December, I talked about regional sections and how I think that they are the face of SPE, and similarly when I think of reading and writing SPE papers or reading the Journal of Petroleum Technology (JPT), and the SPE Journal, these too are some of the key aspects of being an SPE member. It’s also front and center to our mission statement connecting our members to technology, serving as one of the primary ways we do that, and it also plays a role in connecting our members to other members.\u0000 So, I thought it would be important to spend this episode talking about the importance of SPE papers, JPT, and continuing our focus on how members can get the most out of their SPE membership and in turn create their energy future.\u0000 \u0000 \u0000 \u0000 SPE papers mean a lot to me. I manage the journals, as well as the conference papers at SPE. I know they are very special to you as well. When you and I did the How to Write a Good Abstract webinar together a couple of months ago, we got to hear a lot about your opinions on how to write a great abstract. So why do you think SPE papers are so important?\u0000 \u0000 \u0000 \u0000 Let me just tell you a quick story to illustrate the importance of papers. When I was a member of the Dallas Section several years ago, Danny Bell (SPE Dallas Section Education Chair) said his committee thought that writing papers was very important, so they asked me to put on a seminar on how to write SPE papers. That is what led to the webinar that you were just talking about.\u0000 If you think about technical papers, engineers in all industries write technical papers, they do it to disseminate information and to memorialize their ideas and their discoveries. It is important to any profession that we write and document.\u0000 When it comes to SPE I think papers are critical; without them we don’t have conferences or symposia. They enrich the multisociety library, OnePetro. In the end, it’s the way we disseminate technology and information to our members. But it’s also important to authors because they do the heavy lifting, they are the ones who do the writing, and sometimes they do it in their off time. More information about this is available from our webinar, mentioned earlier.\u0000","PeriodicalId":16720,"journal":{"name":"Journal of Petroleum Technology","volume":"45 3","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"139890095","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}

{"title":"Hydraulically Fractured Horizontal Wells: A Technology Poised To Deliver Another Energy-Related Breakthrough of Enormous Scale","authors":"Greg Leveille","doi":"10.2118/0224-0012-jpt","DOIUrl":"https://doi.org/10.2118/0224-0012-jpt","url":null,"abstract":"\u0000 \u0000 The development of efficient technologies for drilling and hydraulically fracturing horizontal wells has enabled the US to more than double hydrocarbon production since 2005 (Fig. 1), thereby providing unprecedented levels of energy security for America.\u0000 America’s doubling of hydrocarbon output has also held down the price of energy worldwide, and by doing so, accelerated global economic growth. And it has helped reduce the greenhouse gas (GHG) intensity of energy production by backing out “dirtier” forms of energy, such as coal.\u0000 Energy security—economic growth—reduced GHGs vented to the atmosphere: That’s a winning combination. One that America and many other countries have benefitted from immensely.\u0000 Given the enormous positive contributions, it is worth noting that 20 years ago, few if any in our industry foresaw the immense potential of this technology, seeing it as being only applicable for extracting gas from ultratight reservoirs like the Barnett Shale, if they were aware of the technology at all.\u0000 This oversight caused many companies to wait too long before deciding to pursue unconventional reservoirs and caused several of the “shale gas” pioneers to be late in recognizing that hydraulically fractured horizontal wells (HFHWs) could also be successfully applied in liquid-rich plays such as the Eagle Ford and Permian Basin. These are plays that today deliver far more value than that derived from the gas-prone reservoirs that comprised the initial suite of targets.\u0000 And while events have proven beyond a doubt that HFHWs are a powerful tool for economically extracting hydrocarbons from both gas-prone and liquids-rich unconventional reservoirs, it seems likely that many in our industry are overlooking a third significant application of this technology: The use of HFHWs to extract heat from the Earth’s crust that can be utilized to generate electricity.\u0000 \u0000 \u0000 \u0000 What makes this third application particularly compelling as an investment opportunity is that the primary physical challenge that needs to be overcome to achieve attractive rates of return is strikingly similar to that which the oil and gas industry had to surmount to make both gas and liquids-rich unconventional reservoirs economic.\u0000 The key to success in all of these cases boils down to an ability to create via hydraulic stimulation a sufficiently large amount of conductive, connected, fracture surface area. With this, one can reliably expect per-well production rates to be economic given the extremely slow rate at which hydrocarbons—and heat—move through unconventional reservoirs and the hot, dry, basement rocks that contain the bulk of the world’s geothermal resources.\u0000 That converting from vertical to horizontal well geometries was critical for unlocking the potential of unconventional hydrocarbon reservoirs is now obvious, with this switch having allowed petroleum engineers to increase per-well fracture surface areas by several orders of magnitude. This move increased per-wel","PeriodicalId":16720,"journal":{"name":"Journal of Petroleum Technology","volume":"10 2","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"139881175","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}

{"title":"Technology Focus Topics Reflect Industry Growth, Evolution Over 25+ Years","authors":"C. Carpenter","doi":"10.2118/0224-0036-jpt","DOIUrl":"https://doi.org/10.2118/0224-0036-jpt","url":null,"abstract":"No matter your field of expertise or geographical area of operations, JPT’s Technology Focus feature addresses your career and research paths. During the more than 25 years of its appearance in the magazine, the feature has presented synopses of important papers in summarized form. A review of the Technology Focus topical calendar through the years reflects milestones in industry developments and innovations, and the magazine’s ability to adapt to meet the needs of its readers. Indeed, the inception of the feature was a response to such a challenge.\u0000 Each year, thousands of high-quality technical papers are presented at SPE conferences and the Offshore Technology Conference (OTC). These papers are the embodiment of SPE’s mission to collect, disseminate, and exchange technical knowledge about the world of upstream E&P.\u0000 In the late 1990s, JPT staff recognized a need to expand the intersection of SPE’s members with the crucial work outlined in the technical papers written by their colleagues. While SPE’s stable of peer-reviewed journals had always played a critical role in its mission, the rigorous review structure meant that these papers, published in full, might not see audiences for some time. Annual proceedings volumes collected the year’s research literature, but time constraints also limited the number of members who could explore these publications.\u0000 The solution was the Technology Focus feature, in which conference papers dedicated to a broad spectrum of industry topics were chosen by subject-matter experts and condensed by SPE staff to convey key findings and illustrative case studies. The Tech Focus concept meant that SPE readers could find the best research and industry innovation at their fingertips each month. These papers were not peer reviewed, but the members of the JPT Editorial Review Board charged with their selection were recognized experts who reviewed hundreds of abstracts in order to choose only a few papers for inclusion. Since the feature’s launch, hundreds of SPE members from a wide range of major operators, service companies, technology specialists, academic institutions, and research facilities have served as reviewers.\u0000 Tech Focus’ first decade-plus of publication, from 1997 through 2010, established and refined the pattern by which tech papers were selected, synopsized, and organized for presentation. Before 1997, JPT had run Technology Briefs that had the same idea, but these were irregular, applied only to tech papers with a length that would make publication in JPT impractical.\u0000 For the first couple of years of the Tech Focus, however, each issue of JPT contained between two and three topical groupings of synopsized papers. The initial topics were broad, familiar ones (EOR, Drilling Technology, Fracturing, Offshore Development, Stimulation, and Reservoir Management, for example) as JPT Technology Editor Dennis Denney, who was responsible for the development of the feature, tested the waters and built a review board ","PeriodicalId":16720,"journal":{"name":"Journal of Petroleum Technology","volume":"27 9","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"139684678","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}

{"title":"Dynamic Simulation Platform Aids Deep Transient Tests, Well-Control Safety","authors":"C. Carpenter","doi":"10.2118/0224-0066-jpt","DOIUrl":"https://doi.org/10.2118/0224-0066-jpt","url":null,"abstract":"\u0000 \u0000 This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 215454, “Enhancing Well-Control Safety With Dynamic Well-Control Cloud Solutions: Case Studies of Successful Deep Transient Tests in Southeast Asia,” by M. Ashraf Abu Talib, SPE, M. Shahril Ahmad Kassim, and Izral Izarruddin Marzuki, SPE, Petronas, et al. The paper has not been peer reviewed.\u0000 \u0000 \u0000 \u0000 The complete paper addresses challenges related to well control and highlights the successful implementation of deep transient tests (DTT) in an offshore well performed with the help of a dynamic well-control simulation platform. The paper aims to provide insights into the prejob simulation process, which ensured a safer operation from a well-control perspective. Additionally, a comparison between simulated and actual sensor measurements during the DTT operation is presented.\u0000 \u0000 \u0000 \u0000 DTT is a formation-testing (FT) method that allows pressure transient tests that reach deeper into the formation compared with conventional interval pressure transient tests (IPTT). DTT enables the testing of formations with higher permeability, greater thickness, and lower viscosity and real-time measurement of crucial parameters. During a DTT, formation fluid is pumped from the reservoir; upon stopping the pump, the formation pressure begins to recover as fluid further from the wellbore replaces the extracted fluid. By analyzing the resulting pressure transient, properties such as formation permeability, permeability anisotropy, and other characteristics can be determined. DTT allows for a better understanding of reservoir characteristics and rock heterogeneity. When properly designed and executed, DTT can reveal potential baffles and boundaries within the radius of investigation. A further advantage of DTT over drillstem tests (DST) is its minimal fluid flow, which allows for the attainment of objectives while contributing to the United Nations sustainable development goals.\u0000 In DTT operations, the FT tool is connected to the drillpipe through a circulating sub and a slip joint. The circulating sub plays a critical role in DTT operations because it enables the continuous mixing of pumped formation fluid with circulated mud and facilitates its transportation to the surface (Fig. 1). Typically, a constant circulation rate ranging from 100 to 250 gal/min is maintained. During circulation, the annular preventer is closed and the mud/hydrocarbon mixture is directed through the choke line to the mud/gas separator (MGS) once it reaches the surface. No formation fluids are flared during DTT operations. Instead, the circulated oil is retained in the mud and only small amounts of gas are vented. By use of a slip joint, the FT remains anchored to the borehole wall.\u0000 A high-resolution pressure gauge is used to capture and interpret even minor pressure fluctuations during the pressure transient buildup.\u0000","PeriodicalId":16720,"journal":{"name":"Journal of Petroleum Technology","volume":"24 11","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"139685569","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}

{"title":"High-Pressure Separation: New Technology in the Subsea Toolbox","authors":"J. Presley","doi":"10.2118/0224-0030-jpt","DOIUrl":"https://doi.org/10.2118/0224-0030-jpt","url":null,"abstract":"\u0000 \u0000 Subsea production systems have come far in the more than 60 years since the first deployment in the US Gulf of Mexico, helping many countries unlock their offshore hydrocarbon riches in the years that followed.\u0000 For Brazil, it was a combination of advances in subsea technologies and floating production, storage, and offloading vessel (FPSO) designs that supported the growth of its offshore oil and gas prowess.\u0000 From those first forays into the Sergipe-Alagoas basin in the northeast during the 1970s, the country’s offshore oil and gas footprint has grown significantly, with today’s production from the pre-salt Campos and Santos basins—located farther from shore and in much deeper water—launching state-run oil company Petrobras to a top spot among the ranks of global producers.\u0000 The ongoing development of its offshore fields will continue to boost the country’s oil and natural gas production in 2024. Since December 2022, five FPSOs have been brought online, with four installed in 2023 delivering record output. The fifth one—the FPSO Sepetiba—delivered a New Year’s Day surprise when it came online at Mero 2 oil field on 31 December 2023.\u0000 HISEP, a new subsea technology currently being readied for pilot testing, could potentially ensure continued future production of the Mero field and others by capturing CO2-rich dense gases directly from the wellstream and reinjecting it into the reservoir. The technology also frees up much-needed space and reduces weight on the FPSO’s topside by moving the separation process to the seafloor.\u0000 \u0000 \u0000 \u0000 Brazil’s challenging offshore pre-salt region—first explored by Petrobras in 2005—contains estimated reserves of 30 to 40 billion BOE and comes with an extensive list of development challenges.\u0000 Its Santos Basin, for example, lies in ultradeep water with hydrocarbon reservoirs located at extreme depths ranging from 5500 to 7600 m below sea level and under salt layers more than 2000 m thick.\u0000 But the challenges do not end there. Managing the basin’s high gas/oil ratio (GOR) and CO2 content leaves a significant operational footprint.\u0000 In OTC 29762, authors from Petrobras noted that developing the pre-salt reservoirs requires “large production facilities with complex gas processing plants that limit the oil processing and storage capacities.”\u0000 In the paper presented at the 2019 Offshore Technology Conference (OTC) Brasil, the authors said that the gas processing plants for some pre-salt fields with high production indexes, GOR, and CO2 content account for nearly 60% of the total FPSO topsides area.\u0000 The Santos Basin is home to the Mero oil field, the country’s third-largest pre-salt field and the first under a production-sharing contract awarded to the Petrobras-led Libra Consortium.\u0000 The field is considered one of the largest hydrocarbon discoveries in the past decade, covering about 320 km2 of the Libra block and with a net pay zone reaching 420 m filled with 29 °API oil and high productivity, according to Ana Luiza ","PeriodicalId":16720,"journal":{"name":"Journal of Petroleum Technology","volume":"53 13","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"139820242","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}

{"title":"Multidisciplinary Approach Optimizes Characterization, Completion in Shale Play","authors":"C. Carpenter","doi":"10.2118/0224-0074-jpt","DOIUrl":"https://doi.org/10.2118/0224-0074-jpt","url":null,"abstract":"\u0000 \u0000 This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper URTeC 3871303, “Using a Multidisciplinary Approach to Reservoir and Completion Optimization Within the Woodford Shale Play of the Arkoma Basin,” by Stephen C. Zagurski, SPE, and Steve Asbill, SPE, Foundation Energy Management, and Christopher M. Smith, Advanced Hydrocarbon Stratigraphy, et al. The paper has not been peer reviewed.\u0000 \u0000 \u0000 \u0000 Subsurface complexities related to the formation of peripheral foreland basins can have significant effects on unconventional resource development. In the Arkoma Basin of southeast Oklahoma, the onset of thrusting and tectonic loading induced a complex series of dip/slip and strike/slip faults during basin formation. The operator used a series of technologies to increase understanding of the reservoir and its hazards and provide insight into economic implications for future development plans and strategies.\u0000 \u0000 \u0000 \u0000 The Woodford is primarily a Type II kerogen source rock. The formation typically is classified as either siliceous mudstone or cherty siltstone. Variable thermal maturity across the basin places the Woodford in both the wet-gas and dry-gas phase windows (moving west to east across the basin). Complex faulting regimes within the Arkoma add a layer of complexity to horizontal development of the Woodford.\u0000 The operator wanted to increase the understanding of the Woodford and the effects of faulting through the reservoir in a recent development unit in the liquids-rich fairway. The development unit consists of an existing parent well (Well X) and a pair of child wells (Well Y and Well Z).\u0000 The background of Unit XYZ begins with the completion of parent Well X 4–6 years before infill development. In this portion of the basin, Well X’s initial production rate and its cumulative production to date rank it in the top 25% of wells. The wellbore is subjected to a pair of faults and was drilled in the upper half of the Woodford. Placement of Well X is substantially further east than most parent wells because it is approximately 1,600 ft from the unit boundary. This limited infill development to two wells instead of three; the Arkoma typically has seen spacing of four, and sometimes five, wells per section. Wells Y and Z were planned and drilled east of Well X with 1,100–1,600 ft of well spacing. Well spacing in the unit was slightly hindered by surface location limitations and limited true vertical depth (TVD) between surface casing and landing point.\u0000 Structural complexity within the unit partially impaired infill development of the unit. Specifically, Well Y and its lateral length was shortened. In this portion of the Arkoma, fault-derived water production typically is the highest-weighted variable in a well’s operating expenditure. Thus, the ability to limit excess water production within Unit XYZ and the surrounding acreage is of paramount importance.\u0000","PeriodicalId":16720,"journal":{"name":"Journal of Petroleum Technology","volume":"46 ","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"139829725","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}

{"title":"BKV CEO: If You Have the Skills To Pay the Bills, CCS Is a ‘Tremendous Business’","authors":"Trent Jacobs","doi":"10.2118/0224-0018-jpt","DOIUrl":"https://doi.org/10.2118/0224-0018-jpt","url":null,"abstract":"Shale gas producer BKV Corp. has made the leap into the US carbon capture and storage (CCS) sector, becoming the latest upstream firm to challenge the idea that only industry giants can make significant moves in this emerging arena.\u0000 Founded in 2015 as a privately held subsidiary of Thailand’s coal and energy conglomerate Banpu, BKV and its fewer than 400 employees have quickly built the company into the 17th largest gas producer in the US. In addition to its upstream operations in the Barnett and Marcellus shales, BKV’s business model borrows from its Thai energy roots and includes ownership of two natural gas power plants in Texas.\u0000 But the firm is better known within upstream technical circles for its leadership in refracturing horizontal wells in the Barnett where it is the largest operator both in terms of acreage and flowing wells.\u0000 No stranger to diversification, BKV is now shifting its focus to CCS—a market anticipated to balloon almost fivefold from $3 billion to over $14 billion by the end of the decade. This growth is being propelled in the US by new legislation offering $85 in tax credits for each ton of CO2 sequestered, effectively turning the greenhouse gas into a valuable commodity.\u0000 The company’s inaugural CCS project, in collaboration with Dallas-based EnLink Midstream, launched this past November in Bridgeport, Texas. Called the Barnett Zero Project, BKV and its partner are targeting the sequestration of approximately 210,000 mtpa of CO2e. Hitting that target means potentially generating over $17.8 million in annual tax credits, a sum that offers a swift return on investment for those who can manage costs.\u0000 BKV has also established a new business unit called dCarbon Ventures which is leading a separate CCS joint venture in the Barnett play called Cotton Cove. The $17.6-million project, $9 million of which will be put up by BKV, is expected to begin injecting up to 45,000 mtpa by the end of next year. Beyond that, BKV and its subsidiaries have secured rights for a large-scale project spanning 21,000 acres in neighboring Louisiana which would source its emissions from the industrial and petrochemical plants around the New Orleans area.\u0000 Steering these ambitious projects is BKV’s CEO, Chris Kalnin, alongside Lauren Read, vice president of the gas company’s dCarbon Ventures. Under their leadership, BKV hopes to achieve net-zero Scope 1 and 2 emissions by next year—decades ahead of most industry reduction targets. The company is not stopping there and is ambitioning to do what most US-based operators have so far refrained from, which is to offset its Scope 3 emissions sometime next decade.\u0000 In the following Q&A, Kalnin and Read discuss the motivations behind the Barnett Zero Project, its significance in the context of independent producers, and what it signals about BKV’s broader strategy.","PeriodicalId":16720,"journal":{"name":"Journal of Petroleum Technology","volume":"99 ","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"139830403","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}

{"title":"Reservoir Modeling Predicts Effect of Cold-Water Injection on Geothermal PTA","authors":"C. Carpenter","doi":"10.2118/0224-0069-jpt","DOIUrl":"https://doi.org/10.2118/0224-0069-jpt","url":null,"abstract":"\u0000 \u0000 This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 212615, “Reservoir Modeling To Predict the Effect of Cold-Water Injection in Geothermal Pressure Transient Analysis,” by Purnayan Mitra, SPE, University of Petroleum and Energy Studies, and Nihal Mounir Darraj, SPE, Imperial College London. The paper has not been peer reviewed.\u0000 \u0000 \u0000 \u0000 Geothermal reservoirs are one of the cleanest renewable sources of energy poised to address the global energy challenge. A major issue in the exploitation of geothermal reservoirs, however, is to find best-fit analytical methods for pressure transient analysis (PTA). This is because the assumptions made to predict PTA in hydrocarbon reservoirs are not satisfied by geothermal reservoirs. In the complete paper, the effect of cold-water injection on PTA of geothermal reservoirs is studied by varying the temperature of the injected cold water from room temperature to reservoir temperature.\u0000 \u0000 \u0000 \u0000 A major method of extracting heat energy from the Earth is the injection of water. Cold water is injected deep into geothermal reservoirs at a depth of 2–4.5 km. In this environment, cold water is essentially heated by the hot granite rock. Hydraulic fracturing is used to produce a large crack within the geothermal reservoir. Two boreholes intercept the crack. These boreholes are used for passing the cold fluid stream and the hot stream, respectively. In many scenarios, the gradient within the geothermal reservoir is so strong that a dry stream is produced. The greater the temperature difference between the injected fluid and the interior of the Earth, the greater the heat transfer. Therefore, it is always desirable to inject cold water inside geothermal reservoirs to maximize heat transfer and extract more heat. The steam coming out from the reservoir after heat transfer is used to run turbines to generate electricity. The steam also is used for a variety of other purposes. However, instances exist in which the temperature gradient is not as high, and it is difficult to produce a sufficiently heated dry stream. In such cases, an organic Rankine cycle is used for heating the steam on the surface. In such a case, the hot water or steam mixture is passed through a heat exchanger for heating the fluid to a desired temperature.\u0000 When cold water is injected into the reservoir, a need exists to analyze the pressure transience throughout the reservoir. Different formations affect PTA in different ways. PTA across the geothermal reservoir currently is performed using the empirical correlations available for hydrocarbon reservoirs. Although the method is not 100% effective because of differences in reservoir parameters, PTA provides an idea about reservoir conditions. To reduce imperfection, it is often preferred to use reservoir parameters rather than injectate properties. In the complete paper, the authors study the effect of injected water on geothermal reservoirs while varying temper","PeriodicalId":16720,"journal":{"name":"Journal of Petroleum Technology","volume":"99 2","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"139827079","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}