Journal of Petroleum Technology最新文献

{"title":"The HSE Journey: A Look at SPE’s Accomplishments and the Way Forward","authors":"Roland Moreau","doi":"10.2118/0524-0016-jpt","DOIUrl":"https://doi.org/10.2118/0524-0016-jpt","url":null,"abstract":"\u0000 \u0000 Congratulations to SPE’s Journal of Petroleum Technology (JPT) on its 75th anniversary. This milestone presents a good opportunity to look back on SPE’s longstanding commitment to promoting a safe, healthy, environmentally friendly, sustainable, and secure workplace for everyone working in the oil and gas industry, both onshore and offshore. As I prepared to write this article, I reread a guest editorial I wrote for JPT after the 2012 SPE International HSE Conference and Exhibition focused on “The Growing Importance of HSES-SR in Our Industry.”\u0000 The good news is that SPE has remained active in promoting conferences and workshops as well as enhancing competencies across the spectrum of HSE subdisciplines. Challenges remain, however, in engaging functional leaders across our industry and achieving more consistency related to industrywide HSE culture, leadership, management systems, risk management, and sustainable development.\u0000 Another historical challenge facing our industry continues to be how to learn from the past and more effectively share lessons learned in HSE with the objective of pursuing continual improvement in all we do. A strength of SPE has been, and continues to be, the ability to convene and leverage the expertise of our global members and sister organizations in achieving this objective, as well as identifying and developing innovative, engaging, and sustainable approaches to turn this objective into a reality.\u0000 My goal in this article is to share with you some of the HSE accomplishments we’ve had over the past several years in this industry, as well as what the future might hold. Unfortunately, given the breadth of the HSE discipline, it is not possible to do adequate justice to the large number of proactive initiatives pursued by SPE over the past several years, so I’ve tried to highlight a handful of those items I felt were most impactful as a result of SPE engagement.\u0000 \u0000 \u0000 \u0000 SPE hosted its first international HSE conference in 1991 and has held numerous international and regional conferences ever since. As evidence of SPE’s recognition of the importance of HSE to oil and gas activities, the first technical directors were added to the SPE Board of Directors in 2001, with the role of HSE technical director established in 2002. The scope of the HSE role was expanded to include security and social risk management in 2007, and sustainable development was added in 2014.\u0000 From 2010 to 2014, I was privileged to serve as the fourth HSE technical director on the SPE Board of Directors. I want to thank my predecessors in that role for establishing a strong HSE foundation from which to build on, and I hope I was able to do the same for my successors. My exposure to the global HSE community within SPE allowed me to more fully recognize the extent to which HSE crosses all discipline boundaries, as well as the extent to which HSE affects other parts of the oil and gas industry and more broadly other industries. It is important that we con","PeriodicalId":16720,"journal":{"name":"Journal of Petroleum Technology","volume":"53 6","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-05-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141038795","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":"Solutions to Complex Well-Testing Challenges Aid Offshore Black Sea Gasfield Development","authors":"C. Carpenter","doi":"10.2118/0524-0078-jpt","DOIUrl":"https://doi.org/10.2118/0524-0078-jpt","url":null,"abstract":"\u0000 \u0000 This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 215123, “Frontiering Ultradeep Water Gas Field Development, Offshore Black Sea, Turkey: Solutions to Complex Well-Testing Challenges and Proving Production Potential,” by Coşan Ayan, SPE, Suat Aktepe, and Koscal Cig, Turkish Petroleum, et al. The paper has not been peer reviewed.\u0000 \u0000 \u0000 \u0000 Increasing demand for reliable energy resources has led to an increased exploration activity for untapped hydrocarbon resources in deep water. The recently discovered, fast-tracked Sakarya offshore natural gasfield development is a prime example. This paper describes dynamic reservoir characterization considerations, challenges, and engineering solutions to derisk field-development decisions, confirmed by a well-testing campaign in a complex setting with no tolerance for failure.\u0000 \u0000 \u0000 \u0000 The Sakarya field is approximately 170 km north of the Turkish coast in the Black Sea at 2117 m (Fig. 1). The natural gas field was discovered in August 2020 and is estimated to have potential natural gas reserves of 11 Tcf of lean gas, making it the largest gas reserve discovered in the Turkish Exclusive Economic Zone as well as the Black Sea.\u0000 In October 2020, a second discovery was made in the lower sections of Tuna 1, which increased the potential recoverable reserve estimate to 14.3 Tcf of lean gas. The discovery was found at the deeper part of the well, where an additional 30 m of gas pay was encountered in the sandstone reservoir of the Late Miocene. Further, the drilling of the exploratory well Amasra 1, 40 km north of the Sakarya field, led to the discovery of 4.7 Tcf of gas in June 2021, and increased the potential recoverable cumulative natural gas reserves to 19 Tcf.\u0000 The first gas production from the Sakarya gas field began in 2023 into the Turkish grid from the completed wells of the first phase of the project. To accelerate the time to first gas production, it was deemed necessary to flow-test the reservoirs to acquire critical reservoir information, assess production potential and completions efficiency, and reduce the number of wells. This was achieved by drilling and testing several appraisal wells with multiple target intervals that will be used later as producers.\u0000 \u0000 \u0000 \u0000 Formation-failure studies and wireline formation testing data have shown that these weak reservoirs are prone to sand production. As a result, downhole sand-exclusion completions are necessary. Gas permeabilities are good, with core-measured air permeabilities in the range of 1–1000 md. The reservoir pressure varies from 4,200 to 5,800 psi, depending on depth. Reservoir temperatures are relatively low, in the range of 25–60°C.\u0000 Lower Completion Installation Sequences.\u0000 After drilling, the main section was completed with 9⅞-in. 62.8-lbm/ft production casing. The selected interval from openhole logs and formation test results was perforated and overbalanced by individual runs of a tubing-conveyed p","PeriodicalId":16720,"journal":{"name":"Journal of Petroleum Technology","volume":"213 4","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-05-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141049930","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":"Multifunctional-Team Approach Achieves Extended-Reach Record Offshore Abu Dhabi","authors":"C. Carpenter","doi":"10.2118/0524-0094-jpt","DOIUrl":"https://doi.org/10.2118/0524-0094-jpt","url":null,"abstract":"\u0000 \u0000 This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 216326, “Longest Extended-Reach-Drilling Well Worldwide Drilled in Middle East, Offshore Abu Dhabi, UAE,” by Marah Mohamad Alabed, Naser Salah Alsuwaidi, and Jamie Scott Duguid, SPE, ADNOC, et al. The paper has not been peer reviewed.\u0000 \u0000 \u0000 \u0000 The complete paper describes the engineering design and operational practices that supported the setting of a new extended-reach world record in a mature carbonate field offshore Abu Dhabi. This accomplishment reduces the carbon footprint of the development, allows acquisition of reservoir data earlier in the development plan, and accelerates production while reducing costs. This extended-reach development program is a strong example of what can be accomplished when a multifunctional team cultivates a strategic plan to expand technical and operational capabilities in a drilling campaign.\u0000 \u0000 \u0000 \u0000 The 1-md oil reservoir is a carbonate dominated by packstone and grainstone rock types in terms of storage capacity. Average porosity is 18%, and thickness is 130 ft. Permeability reduces in an southeast/northwest direction, dropping below 1 md. Calcite cementation development has occurred in the westernmost areas of the reservoir because of late oil in these low structural areas.\u0000 Initially, the target reservoir was drilled at 2-km well spacing with a five-spot waterflooding scheme from wellhead platform towers. Later, development was optimized by a line waterflooding scheme at 250-m well spacing by development from an environmental island. The target reservoir area was partitioned into four development areas (West A, West B, West C, and West D). The partition is based on drilling reachability from environmental islands and underlying geology.\u0000 The current optimized development began in the West A reservoir area through an artificially constructed island. The remaining reservoir areas required investment of two new islands. High risk is associated with these investment decisions because these reservoir areas degrade in terms of reservoir rock properties. Additionally, an increasing trend of water saturation exists with progress in the northwest direction within the transition zone.\u0000 The development plan in the West A area is based on drilling segments called AB and BC, first with over-20,000-ft laterals to achieve production buildup by target date. To test the West B area, Segment BC was extended, thus covering both West A and B areas. This option reduced drilling complexity and maximized the reservoir-production rate. Additionally, by adopting the island drilling option instead of appraising a limited area of West B, an extensive area of approximately 10 km could be appraised.\u0000 To implement this option, a stepout drilling plan was executed by drilling eight extended-reach maximum-reservoir-contact wells in increments to meet the goal of appraising the West B reservoir area. These first wells were extended in increment","PeriodicalId":16720,"journal":{"name":"Journal of Petroleum Technology","volume":"95 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-05-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141037840","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":"Well-Candidate-Recognition Solution Offers Time Savings, Production Enhancement","authors":"C. Carpenter","doi":"10.2118/0524-0082-jpt","DOIUrl":"https://doi.org/10.2118/0524-0082-jpt","url":null,"abstract":"\u0000 \u0000 This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 213329, “Data-Driven Well-Candidate-Recognition Solution: Case Study in a Digital Oil Field in Abu Dhabi,” by Erismar Rubio, SPE, Nagaraju Reddicharla, SPE, and Mayada Ali Sultan Ali, ADNOC, et al. The paper has not been peer reviewed.\u0000 \u0000 \u0000 \u0000 A well-candidate-recognition (WCR) data-analytics solution was developed to expedite the process of identifying unhealthy wells that may require rig or rigless interventions based on data integration, automation, and advanced data-driven models. The solution expedites the well-performance-review process to pinpoint candidates for stimulation, nitrogen lift, gas lift conversion, and water or gas shutoff, providing a flexible visualization platform to highlight hidden well-performance insight.\u0000 \u0000 \u0000 \u0000 Mature oil fields will face challenges in terms of increasing water cut, lack of pressure support, and the requirement of artificial lift. The critical concern is prioritization of remedial actions that are economically attractive with high returns and low risk. In the past, the asset was prioritizing the rig and rigless intervention candidates on a manual basis with no technical framework, mostly relying on engineers’ backgrounds and experience. Lack of understanding and failure to apply lessons learned from previous jobs were frequent outcomes because no single, comprehensive database or documentation existed that effectively captured well-intervention history. Every year, the operator requested a well-performance-review report for every reservoir containing hundreds of diagnostic plots that required massive manual updates, although the subject asset is a digital oil field fully instrumented with real-time data streaming. However, no tools were available to integrate periodic and nonperiodic required data.\u0000 The complete paper addresses these challenges of integrating huge amounts of data and model frameworks and developing a systematic workflow to identify opportunities for production enhancement. Data-driven models, combined with the integration of static and dynamic data, enable proactive surveillance routines that allow engineers to focus on problematic wells and opportunity generation in a timely manner.\u0000 \u0000 \u0000 \u0000 The WCR data-analytics solution was developed as part of the operator’s digital transformation strategy to streamline the process of improving diagnostics, identifying unhealthy wells, and reviewing value gain. The solution aims to help achieve the following objectives:\u0000 - Facilitate well-performance review to pinpoint candidates for rig and rigless intervention\u0000 - Provide a flexible visualization platform to highlight hidden well performance insight\u0000 - Integration of real-time data and official databases\u0000 - Create a collaborative environment for improved decision-making\u0000 - Improve rigless success factor for the most-expensive activities\u0000 - Optimize and prioritize the reservoir-monitoring plan (RMP)\u0000","PeriodicalId":16720,"journal":{"name":"Journal of Petroleum Technology","volume":"11 4","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-05-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141053771","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":"Comments: Grabbing the Brass Ring To Power the Demand for Data Centers and Generative AI","authors":"P. Boschee","doi":"10.2118/0524-0008-jpt","DOIUrl":"https://doi.org/10.2118/0524-0008-jpt","url":null,"abstract":"\u0000 \u0000 “There’s no way to get there without a breakthrough.”\u0000 These were the words of OpenAI’s CEO Sam Altman at a sideline meeting with Bloomberg at the World Economic Forum (WEF) in Davos, Switzerland, in January, referring to the energy required to power generative AI, data centers, cloud computing, and to support required equipment and infrastructure.\u0000 As industries swiftly transition into a fresh era of digital revolution, spearheaded by the fast adoption and advancement of generative AI technology, the demand for energy to power data centers and required infrastructure skyrockets.\u0000 Research firm IDC estimated that global data center energy consumption reached 382 TWh in 2022, with a forecast surge to 803 TWh by 2027. To contextualize, 382 TWh is roughly equivalent to France's annual electricity consumption, while 803 TWh is comparable to Russia's usage (International Energy Agency, 2019 data). Currently, data centers consume approximately 1 to 2% of global electricity, is expected to rise to 8% by 2030, according to WEF.\u0000 Struggling to keep pace are the sources of energy required to fuel this transformation, and the transmission and distribution constraints of power grids.\u0000 In 2010, IDC observed a 50% gigaleap in global data production to 1.2 zettabytes (1.2 trillion GB), with projections of annual data production reaching 35 zettabytes by 2020, a milestone reached in 2018 instead. By 2020, 59 zettabytes of data were generated. IDC anticipates newly created data to soar to 175 zettabytes by 2025, notching a 146-fold increase over 15 years.\u0000 \u0000 \u0000 \u0000 The voracious energy consumption of data centers is sounding alarms about the need for additional sustainable and efficient power generation sources.\u0000 SPE-218905, presented last month at the 2024 SPE Western Regional Meeting, dove into the oil and gas industry’s role in assuring “digital decarbonization.” Noting the expanded use of AI, data centers, and cloud computing in our industry, the authors wrote, “The need for energy transition has triggered an unprecedented momentum for developing renewable energy sources. With its historical and current contributions to the energy and products market, all indications are that the petroleum Industry needs to continue its efforts in the production of hydrocarbons while also actively exploring ways to substantially reduce GHG emissions such as methane and carbon dioxide.”\u0000 Major companies are intensifying digital transformation efforts, reshaping petroleum industry processes. This includes reservoir characterization, drilling design, and economic calculations, which rely on high-performance computers—increasing energy consumption and emissions. Data analytics and AI aid in demand forecasting, inventory management, and predictive maintenance, reducing disruptions and environmental damage, thereby cutting carbon emissions. Automation, drones, robotics, and IoT sensors enhance operations, safety, and efficiency while minimizing environmental impact.\u0000 Data reign su","PeriodicalId":16720,"journal":{"name":"Journal of Petroleum Technology","volume":"336 3","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-05-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141028264","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":"Fewer Operators, Lower Volumes in View for the Prolific Permian","authors":"Blake Wright","doi":"10.2118/0524-0044-jpt","DOIUrl":"https://doi.org/10.2118/0524-0044-jpt","url":null,"abstract":"The $100-billion-plus wave of oil industry consolidation that swept through the Permian Basin of west Texas and southeast New Mexico in the second half of 2023 may have crested but is still showing momentum that will likely result in more deals over the remainder of this year. Need evidence? Look to February’s $50-billion combination of Diamondback Energy and rival Endeavor Energy Resources.\u0000 Endeavor began as a green-shoot sole-proprietorship in 1979 to drill its first well in Midland County, Texas. By 2016, the private company had transitioned into one of the region’s top horizontal well operators—completing over 1,100 gross operated horizontal wells and producing more than 400,000 gross operated barrels of oil equivalent per day at the time of the Diamondback deal.\u0000 The Diamondback/Endeavor marriage was the side salad in an otherwise grand buffet of deals that ran roughshod through the region over the past several months. Last October, ExxonMobil cut a deal to acquire Pioneer Natural Resources for around $60 billion. Chevron followed suit with its $53-billion deal to acquire rival Hess. Other smaller, but notable deals included Permian Resources’ $4.5-billion bid for Earthstone Energy, Canada’s Ovintiv’s $4.3-billion offering on a trio of regional deals, and Civitas Resources snapping up private-equity-led Tap Rock Resources and Hibernia Energy III for a combined $4.7 billion.\u0000 The lion’s share of the larger deals is characterized by players with more-predominant international footprints snapping up more-focused producers in an area of established crude oil production. When deals like this occur, not only are you taking two potential drilling programs and making them one, but you are also bringing these assets into a situation of heightened competition for budget dollars due to the acquiring company’s other financial requirements. This is expected to result in less drilling and, as a result, less production coming from the prolific Permian over the course of the next several months.\u0000 “We do have production growth from the Permian slowing to about 400,000 B/D in 2024 from 500,000 in 2023 and 600,000 in 2022,” said Andrew Dittmar, analyst with Enverus.\u0000 “It’s hard to draw a direct correlation to the consolidation of private E&Ps, but in my view that is playing a role. There has been over $100 billion in private sales in the Permian since 2021. Privates are far more likely to target double-digit production growth versus publics managing for flat production or low single-digit growth. Privates are especially likely to ramp up production immediately before going to market to garner a higher sales price, so the wave of privates gearing up to sell then transacting was a tailwind for Permian volumes,” Dittmar said.\u0000 He noted that moving forward, this will have a diminished effect since there are limited large private entities left to merge in the Permian region. The likelihood of public-public mergers, such as ExxonMobil acquiring Pioneer or APA purch","PeriodicalId":16720,"journal":{"name":"Journal of Petroleum Technology","volume":"28 4","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-05-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141055176","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":"Project Pursues Autonomous Waterflooding Operations Driven by AI","authors":"C. Carpenter","doi":"10.2118/0524-0085-jpt","DOIUrl":"https://doi.org/10.2118/0524-0085-jpt","url":null,"abstract":"\u0000 \u0000 This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 215236, “AI Innovations in Waterflood Management: The Path to Autonomous Operations,” by Sanjoy K. Khataniar, SPE, Shripad S. Biniwale, SPE, and Mohamed A. Elfeel, SPE, SLB, et al. The paper has not been peer reviewed.\u0000 \u0000 \u0000 \u0000 In the S Field described in the complete paper, a major control mechanism applied to optimize waterflooded reservoirs is controlling the water injection and pumping rates of producers. The reservoir surveillance team has been using a simple, spreadsheet-based analytical approach that proved limiting as the number of injection patterns increased. The complete paper presents various innovations in bringing real applications of artificial intelligence (AI) for waterflooding management. The AI-based solution combines cloud technologies, data processing, data analytics, machine-learning algorithms, robotics, sensor and monitoring systems, automation, edge gateways, and augmented and virtual reality.\u0000 \u0000 \u0000 \u0000 The authors devote a subsection of the complete paper to a description of a process they term “Design Thinking.” The main steps in the Design Thinking process are discover, define, ideate, experiment, build prototype, and test. The approach and purpose of each of these steps is detailed in the complete paper, with examples of most steps discussed in this synopsis.\u0000 Establishing a strategic foundation framework is critical for any business wishing to improve efficiency. A commonly used framework separates the business’s operational, tactical, and strategic aspects. In the complete paper, the authors present a conceptual realization of such a framework for waterflood-performance management. The attributes of this framework include time-horizon integration; user-friendliness; and a decision-focused, fit-for-purpose design.\u0000 \u0000 \u0000 \u0000 The opportunity for the authors to consider introducing AI into waterflooding operations arose in 2019 when a large operator in Ecuador began to consider leveraging digital technologies for all its field operations to generate better business value.\u0000 Waterflood optimization was defined as encompassing all activities that optimize injectivity, capacity, and quality from water sourcing to injection at the sand face. Requirements were grouped into seven categories, and a high-level implementation road map was created to increase the digital maturity of assets as quickly as possible. Further analysis highlighted the fact that the existing injection-pattern balancing methodology was not robust enough and that addressing it on a priority basis would have the greatest effect. The S Field was identified as a candidate for solution prototyping.\u0000 The S Field is one of several being developed and produced by waterflooding. The field has been in production since the early 1980s by natural depletion. Reservoir pressure has declined considerably to levels just above bubblepoint pressure. A redevelopment of the field is ","PeriodicalId":16720,"journal":{"name":"Journal of Petroleum Technology","volume":"13 3","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-05-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141053481","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":"Study Explores Challenges, Potential of Superlaterals in the Vaca Muerta","authors":"C. Carpenter","doi":"10.2118/0524-0097-jpt","DOIUrl":"https://doi.org/10.2118/0524-0097-jpt","url":null,"abstract":"\u0000 \u0000 This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper URTeC 3968851, “Breaking the 5-km Barrier: Superlaterals Delivery Challenges—Are They Feasible in Vaca Muerta?” by Julio Palacio, SPE, Walid Ben Ismail, and Richard Walker, K&M Technology Group, et al. The paper has not been peer reviewed.\u0000 \u0000 \u0000 \u0000 Driven by increased production rewards, multiple operators in the United States have been improving their unconventional wells by increasing lateral length. Several “superlaterals” with lengths greater than 23,000 ft have been drilled successfully in several US basins. The complete paper describes the technical challenges faced in drilling and running casing in superlaterals and the difficulties in implementing them in the Vaca Muerta unconventional play.\u0000 \u0000 \u0000 \u0000 In 2012–2015, many operators began to drill longer laterals. Because production did not appear to decline with increasing lateral length, one operator drilled 11 superlaterals in 2017 in the Utica shale, reporting critical cost reductions and a greater recovery per foot. This operator used the term “superlateral” to describe a lateral length of 15,000 ft or greater. At the time of writing, several wells have exceeded a lateral length of 23,000 ft and can be categorized as extreme-reach wells. Typically, any well in the extended-reach region requires a large focus on operational practices and may require important design changes and special technologies or techniques to achieve its goals.\u0000 \u0000 \u0000 \u0000 The Vaca Muerta/Quintuco system is a late Jurassic to early Cretaceous play with a depth of more than 8,200 ft true vertical depth (TVD). Pore pressure in Quintuco can vary between 14.2 and 18.8 lbm/gal. Fractures connecting different zones and depths lead to discontinuity and important uncertainties in both pore pressure and fracture gradient. Historically, Quintuco was isolated by running casing before entering the Vaca Muerta. However, several operators drill Quintuco and Vaca Muerta in the same section to reduce the well cost. Using this approach, Quintuco pressure uncertainties effectively limit the maximum lateral length. To reduce this uncertainty effect, managed pressure drilling (MPD) has been used successfully in current laterals.\u0000 Bedding-plane instability limited early development of unconventional horizontal wells. Its effect is not commonly perceived while drilling but can affect bit trips and casing runs catastrophically. Higher mud weight (MW) has helped mitigate, but not eliminate, bedding-plane instability in unconventional plays around the world. However, higher MW can constrain more than the MW window requirements in the Quintuco/Vaca Muerta system.\u0000 As the lateral progresses in length, the annular pressure increases proportionally. Given that the TVD remains almost constant in horizontal wells, the equivalent circulating density (ECD) change will increase proportionally to the lateral length. Because of this ECD behavior in horizontal wells","PeriodicalId":16720,"journal":{"name":"Journal of Petroleum Technology","volume":"111 3","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-05-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141052668","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":"Uncertainty Study Aids Development-Plan Optimization in Deepwater Gulf of Mexico","authors":"C. Carpenter","doi":"10.2118/0524-0071-jpt","DOIUrl":"https://doi.org/10.2118/0524-0071-jpt","url":null,"abstract":"\u0000 \u0000 This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 32622, “Development-Plan Optimization and Uncertainty Study in a Major Deepwater Field in the US Gulf of Mexico,” by Mohsen Rezaveisi, SPE, Jennifer L. Campbell, and Paula L. Wigley, Woodside Energy Group, et al. The paper has not been peer reviewed. Copyright 2023 Offshore Technology Conference.\u0000 \u0000 \u0000 \u0000 This paper describes development-plan optimization and a probabilistic uncertainty study using Latin hypercube experimental design constrained to production performance in Lower Miocene (LM) reservoirs of the deepwater Gulf of Mexico Shenzi Field. The purpose of the development-plan optimization was to identify, rank, and characterize future development opportunities (i.e., infills and injectors) in the LM reservoirs to arrest field decline. The study uses history-matched dynamic simulation models.\u0000 \u0000 \u0000 \u0000 The Shenzi discovery is approximately 122 miles off the coast of Louisiana in a water column approximately 4,400 ft deep (Fig. 1). This part of the field is a partially filled three-way closure against a salt-cored anticline. The discovery includes four main sand units (A, B, C, and D) that exhibit various degrees of hydraulic connectivity based on pressure data and production history. The area of interest in the current study is the Eastern part of the field.\u0000 \u0000 \u0000 \u0000 The geomodel covering the area of interest was built from two seismically interpreted horizons and approximately 180 faults. The model is subdivided into 13 zones using well-based true stratigraphic thickness maps. The average cell height is 2–3.5 ft thick with heterolithics driving the lower end of the range. Sequential indicator simulation was used to populate facies using well-based net sand trend maps by zone. In zones with evidence of channelization, a second nested facies model was used to build channels into the model.\u0000 Shenzi East reservoir properties are good because of the high-quality sand deposited in the field. Lower reservoirs (C and D) have slightly more depositional complexity because of the varying paleotopography and a lower average net-to-gross (NTG) of approximately 53%. Upper reservoirs (A and B) had a larger sediment supply and were more continuously deposited, which resulted in a larger average NTG of approximately 67%.\u0000 \u0000 \u0000 \u0000 The Shenzi East reservoir has been on production since March 2009, providing abundant production data for history matching. Of seven producers, six are still active, and the reservoir also features three water injectors. Producers and injectors are identified with letters P and I, respectively, followed by well numbers. Well P7 was drilled after 6 months of production from other producers; formation pressure data showing reservoir depletion are available for history matching. The water injectors were drilled in 2012–2013, but only two have formation pressure testing data available. Well P1 was completed in all sands; Wells P2, P3, and P6 w","PeriodicalId":16720,"journal":{"name":"Journal of Petroleum Technology","volume":"545 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-05-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141028182","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":"API Proppant Test Not Looking So Strong","authors":"Stephen Rassenfoss","doi":"10.2118/0524-0036-jpt","DOIUrl":"https://doi.org/10.2118/0524-0036-jpt","url":null,"abstract":"\u0000 \u0000 The short answer for how to judge proppant strength sounds simple—just ask for the K-value.\u0000 The K refers to the weight in thousands that a sand sample can withstand in a crush test defined by API STD 19C covering “testing sand used in hydraulic fracturing operations.” For example, a sample that passes an 8,000-lb crush test but fails at 9,000 lb is an 8-K sand.\u0000 The goal of the standard is to measure how much weight a sand sample can withstand when used to prop open fractures to allow oil and gas to keep flowing. But a recent paper argues that measuring sand strength by the number of fines—small grains created by crushing—is an erratic indicator.\u0000 The SPE paper delivered at the 2024 SPE Hydraulic Fracturing Technology Conference described a blind test where a Permian sand supplier, Atlas Energy Services, sent out 120 samples of variously sized sand grains to four testing labs. The results for identical samples varied widely, even within the testing labs (SPE 217767).\u0000 “We are seeing 2K to 3K variation internally at independent labs on split samples, and at least 3K variation between labs,” said Ian Renkes, the paper’s lead author who is regional continuous improvement manager for Atlas in the Permian, adding, “This makes it very difficult if not impossible to differentiate between sand providers.”\u0000 For Atlas and other sand mines competing for business by focusing on delivering quality sand, this is frustrating because the inconsistent testing undermines those efforts.\u0000 There was an interesting detail near the end of the paper suggesting a large operator also has concerns. The list of references began by crediting “Todd Cage of ConocoPhillips who performed the initial work that provided the basis of this paper.”\u0000 Cage, ConocoPhillips’ commercialization manger in Midland, did not comment, but his role in devising the test suggests more than a passing interest in sand testing.\u0000 \u0000 \u0000 \u0000 For the test, Atlas created large samples in three mesh-size ranges—30/50, 40/70, and 100-mesh (40/140), using sand mined and processed in Kermit, Texas.\u0000 Each of them was measured 30 times using the API 19C methodology. They then split them up into smaller packages. Each of the four testing companies ultimately tested 30 packages.\u0000 To conceal the fact this was a test, they sent out two to seven samples at a time to labs over a 6-month period. The paper said, “Care was taken when sending the samples out to label them, so the laboratories were not aware the samples in each batch were identical splits.” This method is referred to as “round-robin” testing.\u0000 Charts tracking the results show large variations in the test results. The critical number in the crush test is the percentage of the sample made up of fines after crushing. API rules define fines as grains smaller than the smallest grains in the original sample.\u0000 For example, when 40/70-mesh grains were tested using 8,000 lbs of force by the company identified as Lab 2, it reported measuring about 50% more fines t","PeriodicalId":16720,"journal":{"name":"Journal of Petroleum Technology","volume":"13 17","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-05-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141024007","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}