Journal of Petroleum Technology最新文献

{"title":"Proposed Methods Accelerate Permanent CO2-Storage Process","authors":"C. Carpenter","doi":"10.2118/0724-0105-jpt","DOIUrl":"https://doi.org/10.2118/0724-0105-jpt","url":null,"abstract":"\u0000 \u0000 This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 215352,“ Accelerating the Permanent CO2 Storage Process: A Safer and Faster Route to Net Zero,” by Shubham Mishra, SPE, Boston Consulting Group. The paper has not been peer reviewed.\u0000 \u0000 \u0000 \u0000 The complete paper proposes two methods of accelerating the solidification (or mineralization) of CO2 in subsurface conditions, thus reducing the time required in the CO2 storage process. It also reviews industry and academic works devoted to the subject.\u0000 \u0000 \u0000 \u0000 Two main concerns with CO2 storage in subsurface reservoirs and CO2 sequestration are the large time cycle involved in its permanent storage and the associated environmental risks. Because other CO2 trapping mechanisms can be reversible, these concerns hinge heavily on the time required for solidification or mineralization of CO2 into a component such as calcite (CaCO3).\u0000 Using current technologies and practices, it is practically impossible to complete the soaking period—or, in simpler words, a CO2 storage project—in one lifetime. Thus, technological development of CO2 storage, which depends on field validations, becomes an extremely long, multigenerational process.\u0000 On the other hand, environmental safety is always a concern with underground CO2 storage. Three of four CO2 trapping mechanisms (structural, solubility-based, and residual) pose greater risk to the environment than does the fourth, which is mineralization or solidification.\u0000 Therefore, from the point of view of environmental safety, mineralization is the most permanent form of CO2 storage that minimizes the risk of CO2 existing in gaseous form in the reservoir and thus flowing upward to shallower zones or the surface.\u0000 \u0000 \u0000 \u0000 Several research projects devoted to finding a commercial solution for accelerating the mineralization process are ongoing, including the following:\u0000 - The CarbFix project in Iceland is based upon injection of CO2 dissolved in water streams into basalt rocks for accelerating mineral trapping. Through tracer surveys and mass calculations, the project has proposed that mineralization can be achieved in as little as 2 years for the size of the reservoir under consideration and the amount of CO2 injected.\u0000 - A Canadian startup (Carbon Engineering) is turning carbon emissions into pellets that could be used as a synthetic fuel source, while a Swiss company called Climeworks is pumping extracted carbon to farms for agricultural use.\u0000 - Another start-up is using calcium oxide, a waste product from the steel industry called steel slag, to react with CO2 and form CaCO3. This is used in controlled surface conditions in a cement-industry setup. This process, however, highlights how the reactions converting CO2 into solid can be sped up.\u0000 - University research projects are ongoing that focus on use of various catalysts for increasing the rate of the mineralization chemical reaction, resulting in the formation of CaCO3.\u0000 \u0000 \u0000 \u0000 Whil","PeriodicalId":16720,"journal":{"name":"Journal of Petroleum Technology","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2024-07-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141689422","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":"Integrated Technique Provides Effective Water Diagnostics in Tight Sand","authors":"C. Carpenter","doi":"10.2118/0724-0090-jpt","DOIUrl":"https://doi.org/10.2118/0724-0090-jpt","url":null,"abstract":"\u0000 \u0000 This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper URTeC 3864145, “Evaluating the Hydraulic Fracture Through Acoustic Reflection Imaging and Production Logging for Water Diagnostic Beyond the Wellbore: A Case Study From Chang 8 Tight Sand in the Ordos Basin, China,” by Guangsheng Liu, Dajian Li, and Gang Zheng, PetroChina, et al. The paper has not been peer reviewed.\u0000 \u0000 \u0000 \u0000 The Triassic Chang 8 tight sand reservoir in the Xifeng block of the Ordos Basin features low permeability, which means that hydraulic fracturing and subsequent waterflooding were performed during its development phase. Water breakthrough was encountered after a short period of oil production. A solution of borehole acoustic reflection imaging combined with production logging was proposed in a horizontal well suffering from high water cut. The objective was to determine which stages contributed most to water production, understand the cause, and, ultimately, create a water shutoff plan.\u0000 \u0000 \u0000 \u0000 The Ordos Basin, with an area of approximately 2.5×105 km2, is in North China. The Upper Triassic Yanchang formation is subdivided into the Chang 1 to 10 members, from top to bottom. It contains significant oil reserves in siltstone and sandstone reservoirs, especially in Chang 6 through Chang 8, that have been the major oil-producing resources in recent years.\u0000 In the Triassic Chang 8 tight sand reservoir, horizontal well drilling and multiple-stage hydraulic fracturing have become common practice. In the study block, the well of interest was hydraulically fractured by coiled tubing with sand-jet perforation and fracturing operations in one run with a retrievable packer in the bottomhole assembly of the coiled tubing.\u0000 In the study block, when some producing wells encountered water breakthrough, traditional water diagnostics using production logging was not enough; a survey to detect hydraulic fractures beyond the wellbore was needed.\u0000 \u0000 \u0000 \u0000 Borehole Acoustic Reflection Imaging.\u0000 The processing workflow for acoustic reflected waves mainly consists of two parts. The first is a filtering process to suppress the borehole mode and noise in order to preserve the reflected wave. The second is to migrate the reflected wave to the true position of a reflector. The conventional migration method used for acoustic reflection imaging normally requests previous information relating to reflector dip and produces 2D images, which show the reflector shape but have hard-to-extract precise quantitative information. A trial reflector-migration method covered in the literature was introduced in 2016 that does not require input of structure dip and is of high resolution. A 3D slowness-time-coherence method was developed in 2018, also covered in the literature, that could determine the true dip, azimuth, and distance of a reflector.\u0000","PeriodicalId":16720,"journal":{"name":"Journal of Petroleum Technology","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2024-07-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141712636","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":"What You Don’t Know About Chevron’s New 20K Anchor Project","authors":"Trent Jacobs","doi":"10.2118/0724-0032-jpt","DOIUrl":"https://doi.org/10.2118/0724-0032-jpt","url":null,"abstract":"\u0000 \u0000 After overcoming the impacts of the COVID-19 pandemic and closing significant technology and regulatory gaps, Chevron’s $5.7 billion Anchor project in the US Gulf of Mexico (GOM) is nearly ready to start producing oil.\u0000 When it finally does, it will mark the start of the “20K” era for the deepwater oil and gas industry. The term 20K refers to the project’s core technologies, designed to handle wellhead pressures of up to 20,000 psi—a first for the subsea market.\u0000 The advancement opens the door to previously inaccessible reservoirs by stretching the boundary of deepwater technology beyond the technical limit of 15,000 psi established in the past decade.\u0000 In particular, the drive to reach such extremes is a response to the demands posed by the Lower Tertiary Wilcox play which Chevron pioneered the development of in 2014 with its Jack/St. Malo project.\u0000 Output from the high-pressure, low-permeability, and ultradeep formation is expected to rise from last year’s 270,000 B/D to around 750,000 B/D by 2028. This would represent a shift from 13% to nearly 40% of the US GOM’s total of roughly 2 million B/D, according to Enverus Intelligence Research.\u0000 The success of just a handful of projects like Anchor is crucial for achieving these projections.\u0000 Located approximately 140 miles offshore Louisiana in about 5,000 ft of water, Chevron holds a 62.8% share in the project, with TotalEnergies owning the remaining interest.\u0000 The initial phase includes seven wells targeting reservoir depths between 30,000 and 34,000 ft. Chevron has drilled three so far.\u0000 Anchor’s semisubmersible floating production unit (FPU) arrived in the GOM last year after its hull was built in South Korea and topsides integrated along the Texas coast.\u0000 The FPU has nameplate capacity of 75,000 B/D but modifications made by Chevron post-delivery boosted the facility’s peak throughput to 86,000 B/D—an almost 15% increase.\u0000 At this year’s Offshore Technology Conference (OTC) in Houston, Chevron’s Anchor project team offered a behind-the-scenes look at their journey to the precipice of first oil.\u0000 Drawing from several papers they presented, here are some of Anchor’s biggest challenges and achievements.\u0000 \u0000 \u0000 \u0000 The nature of the Anchor project is such that it involves a number of industry firsts and records.\u0000 At the top of that list is Transocean’s Deepwater Titan drillship which Chevron inked a 5-year $830 million contract for while it was still under construction in 2018. The rig began operations in the GOM in June 2023 as the second eighth-generation drillship ever built but holds claim to being the first ever rated for 20K operations.\u0000 Originally planned to be a 15K-rated vessel, the Deepwater Titan was upgraded on Chevron’s request to host two NOV-supplied 20,000-psi blowout preventers (BOPs). Combined with the lower marine riser package, the BOP stack weighs in at more than 1.1 million lbs.\u0000 Chevron points out in OTC 35148 that the BOPs were not needed to drill the wells—for that, 15,000","PeriodicalId":16720,"journal":{"name":"Journal of Petroleum Technology","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2024-07-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141692894","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: Pore Space Leasing: Insights From a Bakken Surface Owner’s Perspective","authors":"P. Boschee","doi":"10.2118/0724-0008-jpt","DOIUrl":"https://doi.org/10.2118/0724-0008-jpt","url":null,"abstract":"During a trip to western North Dakota last month to visit my family, I met with a long-time friend, Dick, who holds subsurface mineral rights and surface rights in the Bakken area. Over coffee, German sausage, and kuchen, our conversation naturally turned to the leasing of pore space.\u0000 Dick has lately been approached by landmen with what they describe as “great deals” for purchasing the underlying pore space associated with his surface rights. They hesitate to provide specific offers. Instead, he described the initial interactions as “like making a deal for a new car or tractor.” The landmen reply, “I’ll need to go back to the client [my boss or manager] with your questions.” Sound familiar?\u0000 Like most US states, pore space ownership correlates with surface ownership in North Dakota. In August 2022, the North Dakota Supreme Court clarified the rights of surface owners and the need for compensation for pore space use. It also created uncertainty for oil and gas operators who previously had more latitude in using pore space without compensation.\u0000 Dick knows his way around the dealmaking involved in oil and gas rights leasing, having been involved in many landmen inquiries in the days of the Bakken boom and subsequent wheeling and dealing. However, pore space leasing is relatively nascent and faces similar unknowns like the early days of Bakken pitches.\u0000 During his research, he came up against the same walls I have over the years while writing about pore space leasing for carbon sequestration. Becoming more apparent as deals gain momentum is the lack of specifics for comparable deals. As when purchasing a home, identifying “comps” for similar properties is a necessary part of the process.\u0000 But the amounts paid for pore space are closely held, generally not publicly available. It’s impossible to determine if a deal is good or bad. Is the compensation fair?\u0000 And individual surface owners and landowners rights associations (and/or their attorneys) are aware of the 45Q tax credit of $85/tonne of CO2 captured and stored available to the project developer/operator under the 2022 US Inflation Reduction Act. How should this be factored into the determination of fair compensation?\u0000 For example, the Ohio River Valley Institute (ORVI), a think tank focused on the Appalachian region, in March described a proposal by Tenaska Inc. to lease underground pore space across seven counties (approximately 80,000 acres) in Ohio, Pennsylvania, and West Virginia for the sequestering of 150 million tons of CO2. In a document proposing terms for the acquisition of nearly 1,400 acres of pore space in county parklands in Washington County, Pennsylvania, Tenaska offered about $4 million for the county’s 2.6-million-metric-ton share of the CO2 between 2027 and 2056, or about $1.50 per metric ton.\u0000 The ORVI called the deal “ridiculous and borderline insulting.” It supports this declaration by highlighting a comp available from August 2023. Mountaineer GigaSystem LLC offered the s","PeriodicalId":16720,"journal":{"name":"Journal of Petroleum Technology","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2024-07-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141701065","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":"A Grand Challenge: Digital Transformation for the Upstream Oil and Gas Industry","authors":"Thomas C. Halsey","doi":"10.2118/0724-0047-jpt","DOIUrl":"https://doi.org/10.2118/0724-0047-jpt","url":null,"abstract":"\u0000 \u0000 This is the fourth in a series of six articles on SPE’s Grand Challenges in Energy, formulated as the output of a 2023 workshop held by the SPE Research and Development Technical Section in Austin, Texas.\u0000 Described in a JPT article last year, each of the challenges will be discussed separately in this series: geothermal energy; net-zero operations; improving recovery from tight/shale resources; digital transformation; carbon capture, utilization, and storage; and education and advocacy.\u0000 \u0000 \u0000 \u0000 The interval from the oil price decline of 2014–2015 through the global COVID-19 pandemic of 2020–2022 was a difficult period for the upstream oil and gas business. The industry has responded, as so many times before, by seeking to reduce structural costs with the minimum impact to required new investments, including those in nondiscretionary domains (security, including cybersecurity, and safety, health, and environmental performance) as well as those required to appropriately hedge against the emergence of new, more sustainable energy sources. Digital transformation is one of the key opportunities for the industry to systematically reduce costs across multiple business domains.\u0000 While there has been active discussion of the “digital oil field” for several decades, the economic shock of the past decade revived interest in the application of digital technologies across the enterprise to improve the cost structure of businesses.\u0000 Of course, at the same time, entirely new industries, such as social media, have emerged exploiting new digital technologies, including machine learning, web software and connectivity, and cloud storage and computing. These technologies have also transformed traditional industries such as retail and manufacturing. But taking the same path in the upstream industry has some special challenges and opportunities.\u0000 This review focuses on digital transformation opportunities that are, to a greater or lesser degree, unique to the special data and operating environment of the modern petroleum industry. There are many valuable opportunities, including business process automations, that can and should be adopted by upstream companies, but are not different in kind from such innovations in other industries.\u0000 \u0000 \u0000 \u0000 One challenge is the sheer mass and heterogeneity of upstream data. The upstream oil and gas industry is an old industry, with both business and technical records stretching back for many companies to the 19th century. These can be in paper form or a variety of digital forms reflecting the different methods of storing data since computers became a standard business and scientific tool in the 1950s. Conversion of this data to more modern formats suitable for cloud storage, for example, is not cost-free.\u0000 Thus, a key principle in digital transformation is that it must be value-driven. A frequently used phrase, “data is the new oil,” is, at least for the oil and gas business itself, deeply misleading. Most of the data held by any e","PeriodicalId":16720,"journal":{"name":"Journal of Petroleum Technology","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2024-07-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141699990","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":"Extended Laterals and Hydraulic Fracturing Redevelop Tight Fractured Carbonates","authors":"C. Carpenter","doi":"10.2118/0724-0093-jpt","DOIUrl":"https://doi.org/10.2118/0724-0093-jpt","url":null,"abstract":"\u0000 \u0000 This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 216292, “Redevelopment of Tight Fractured Carbonates Through Extended Laterals and Hydraulic Fracturing,” by Antonio Buono, Cameron Taylor, and Alyssa Dordan, SPE, ExxonMobil, et al. The paper has not been peer reviewed.\u0000 \u0000 \u0000 \u0000 In the complete paper, the authors compare development scenarios in a fractured carbonate play between historic vertical and short horizontal development and modern hydraulically fractured extended lateral development. Because of its long production history and recent redevelopment efforts, the Austin Chalk was chosen as a natural laboratory to test how recent artificial stimulation techniques can lead to additional production from a wider range of pore systems.\u0000 \u0000 \u0000 \u0000 In recent years, application of modern unconventional multistage hydraulic fracturing techniques, coupled with adding proppant to support induced fracture networks, mitigated the steep decline seen in historic production profiles. These improvements were exemplified in a recent Austin Chalk redevelopment where modern completions led to an increase in estimated ultimate recovery (EUR) by 250% on average.\u0000 In the targeted area of development, historic, short Austin Chalk laterals without modern completions exhibited a wide range of well performance. Some outlier wells achieved high recoveries from accessing an existing natural fracture network with the original completion, whereas others, after only a few months of economic production, were unable to achieve continuous flow without a propped stimulation.\u0000 The differences in performance partially can be explained by the fact that the reservoir quality of different intervals within the Austin Chalk is likely highly variable. This is exemplified in the B-2 Zone, which contains a well-developed vertical fracture network with variable lengths. Data suggest that the natural fractures are confined within the B-2 and it is geomechanically less-susceptible to wellbore collapse than zones with higher clay concentrations. The B-2 is likely a stiffer interval than the E Zone. This implies that differences exist in the properties of these units that are caused by changes in mineralogy and cementation. The authors aim to characterize reservoir quality and hydrocarbon distributions of the fractured relatively clean zones compared with the hydraulically stimulated reservoir in relatively “dirty” chalky zones, and evaluate geomechanical properties and production expectations from each zone.\u0000 Depositionally, these units can be characterized broadly as carbonate-rich with subordinate siliciclastic detritus composed of clay minerals and silt-sized quartz and plagioclase grains. These units all contain distinctive stylolite seams. The most-favorable hydrocarbon shows typically are in the lower members of the Austin Chalk. Production data show that natural-fracture-only production (heritage) generally has lower total EUR with highly","PeriodicalId":16720,"journal":{"name":"Journal of Petroleum Technology","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2024-07-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141689223","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":"2024 SPE Pioneers of Improved Oil Recovery","authors":"Jennifer Pallanich","doi":"10.2118/0724-0052-jpt","DOIUrl":"https://doi.org/10.2118/0724-0052-jpt","url":null,"abstract":"Reservoirs present plenty of complexity and mystery. Four oil recovery experts have helped remove some of those mysteries, taming the complex to boost production.\u0000 From developing preformed particle gels that improve conformance when fractures cause severe channeling to simulating enhanced oil recovery (EOR) processes in the reservoir to identifying the aqueous stability concept to demonstrating the distance polymer solutions can travel without degradation, the four 2024 recipients of the 2024 Improved Oil Recovery (IOR) Pioneer Award have made a “sustained and important contribution to increased oil recovery,” Randy Seright, New Mexico Tech, 2024 Pioneer selection committee chairman and 2008 honoree, told JPT.\u0000 Seright, four other previous recipients of the recognition, and 2024 SPE IOR Conference General Chairman Tom McCoy evaluated a field of 16 nominees for the lifetime achievement honor and selected four who have throughout their careers “made the most lasting and significant contributions to IOR,” Seright said. “It’s why we are where we are today with respect to IOR.”\u0000 The 2024 IOR Pioneer recipients who were honored during the biannual IOR conference in Tulsa in April are Baojun Bai, professor of petroleum engineering, who sits in the Lester Birbeck Endowed Chair at Missouri University of Science and Technology (Missouri S&T) in Rolla, Missouri; Mojdeh Delshad, research professor in the Hildebrand Department of Petroleum and Geosystems Engineering at The University of Texas at Austin (UT-Austin); Varadarajan Dwarakanath, team lead for chemical EOR at the Chevron Technology Center in Houston; and Stephane Jouenne, who previously led a TotalEnergies team dedicated to surface and subsurface research topics for polymer flooding and is currently CO2 capture project coordinator at TotalEnergies.\u0000 “It’s the most prestigious award given out in IOR,” Seright said.","PeriodicalId":16720,"journal":{"name":"Journal of Petroleum Technology","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2024-07-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141691059","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":"Adaptive Approach for Reservoir Modeling Reduces Project Time, Improves Collaboration","authors":"C. Carpenter","doi":"10.2118/0724-0071-jpt","DOIUrl":"https://doi.org/10.2118/0724-0071-jpt","url":null,"abstract":"\u0000 \u0000 This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 23935, “Breaking the Chain: Novel Use of Adaptive Model Approach for Reservoir Modeling Reduces Time Duration of Project and Improves Collaboration,” by Anthony R. Thompson, SPE, and Cesar E. Zerpa Bolivar, SPE, Saudi Aramco. The paper has not been peer reviewed. Copyright 2024 International Petroleum Technology Conference.\u0000 \u0000 \u0000 \u0000 The complete paper details how the reservoir modeling workflow can be accelerated, and uncertainty reduced, even for challenging greenfield prospects by constructing multiple small fit-for-purpose integrated adaptive models instead of one all-encompassing model. This workflow reduces the number of items on the critical path while simultaneously enabling static and dynamic data to be integrated before the static model is finalized. In addition, this approach enables new ideas to be evaluated more rapidly without affecting the critical path of the project.\u0000 \u0000 \u0000 \u0000 Adaptive models are constructed to evaluate a single parameter, although this does not preclude an adaptive model being used to answer more than one question simultaneously. Critical to the successful use of adaptive models is the fact that they can be constructed quickly. This enables the various inputs received to be assessed and quality-controlled within the static and dynamic models the moment the input or interpretation becomes available.\u0000 The construction of adaptive models normally is best achieved through the construction of a workflow in the static modeling package. Initially, the workflow may only consist of the construction of a grid in which to start to place wells. As data become available and are quality-controlled into the model, in most cases, this can be included into the workflow, enabling more constraints to be applied to the subsequent modeling framework.\u0000 When the adaptive model is being simulated dynamically, it is critical that the model runs quickly. The use of a sector model can be considered for greenfields because the history-matching parameters before production starts are limited to the vicinity of the well. Full-field models are only required when an event occurs across the whole of the reservoir.\u0000 \u0000 \u0000 \u0000 In contrast to the classical approach to reservoir modeling, which uses a chain-type approach, the use of adaptive models brings components together in the sequence of work completion. This means that the various components of the model can be competed when the resource or team member is available. Thus, until very near the end, the project is unlikely to be waiting on the input of one person.\u0000","PeriodicalId":16720,"journal":{"name":"Journal of Petroleum Technology","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2024-07-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141699533","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":"Connected FPSOs Thrive on Automation","authors":"Blake Wright","doi":"10.2118/0724-0040-jpt","DOIUrl":"https://doi.org/10.2118/0724-0040-jpt","url":null,"abstract":"Modern life is connected. Our computers, phones, and watches are all tapped into personal insights, from a daily planner to keep track of meetings and appointments to a health monitor tracking everything from heart rate to blood oxygen level in real time. This connectivity has bled over into many different facets of our lives, including work.\u0000 Business and industry maintain critical connections allowing for simplification of complex tasks and the monitoring of machines for safety and performance.\u0000 As the oil field has become more connected, increasing opportunities for automation have been introduced into both new and existing oilfield technologies with aims to achieve new levels of productivity and safety. Whether it is a robotic arm on the drill floor of a rig bringing pipe from the stand to the well or autonomous robots being used for inspections and other operation observations in hard-to-reach or remote places, if the connectivity is there it opens the door to a vast, new toolkit for contractors and operators alike.\u0000 In 2023, a group of contractors came together to help define the next steps in automation for floating production, storage, and offloading (FPSO) vessels. The FPSO Coalition—made up of SLB, Rockwell Automation, Sensia, and Cognite—is a collaboration designed to accelerate the evolution of FPSOs by developing and employing new digital capabilities aimed at improving the reliability, availability, safety, and efficiency of the assets, while lowering the carbon footprint of their offshore operations.\u0000 FPSOs have been invaluable tools for offshore development around the world for decades. Some older hardware does not have the benefit of being wired for connection or pieces of equipment being Internet of Things (IoT)-ready. As much as the coalition looks to solutions to integrate into new facilities, it also explores the limitations and potential for bringing older yet still viable components into the digital age.\u0000 Under the venture, SLB was tapped to bring advanced digital solutions, subsurface domain expertise, and complex integration and project management capabilities to scale up efficiencies and lower the carbon footprint of operations across every stage of the FPSO life cycle. Rockwell would provide expertise in control and safety systems for FPSOs, as well as extensive experience in power systems.\u0000 “Keeping in mind that the typical operating life of an FPSO can be 20-25-30 years, a lot can change in terms of technology, process conditions, regulatory requirements, etc.,” said Greg Trostel, global industry development manager for floating production at Rockwell Automation.\u0000 “But ultimately, the main goal of automation is to ensure the reliable and safe operation of the vessel—no loss of containment, no personnel at risk, no environmental incidents.\u0000 “Ideally, automation systems can adapt and grow with the changing technology and changing requirements. We depend on the automation systems to keep all the individual process module","PeriodicalId":16720,"journal":{"name":"Journal of Petroleum Technology","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2024-07-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141696484","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":"Downhole Tractors Enable Coiled Tubing Perforation in Horizontal Live Gas Wells","authors":"C. Carpenter","doi":"10.2118/0624-0049-jpt","DOIUrl":"https://doi.org/10.2118/0624-0049-jpt","url":null,"abstract":"\u0000 \u0000 This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 218365, “Conveying Extended-Reach Solutions: First Coiled Tubing Perforation in Horizontal Live Gas Wells With Downhole Tractors,” by William R. Tapia, Julien Delaune, SPE, and Luis C. Villagrana, SLB, et al. The paper has not been peer reviewed.\u0000 \u0000 \u0000 \u0000 A comprehensive study was conducted on the strategic use of coiled tubing (CT) to convey over 1,200 ft of perforating guns in single runs in extended-reach wells, effectively overcoming the lockup effect in a 7-in. monobore completion using downhole tractor and real-time monitoring tools. This solution served as the key enabler for the project, reducing risks and maximizing operational efficiency. Compared with tubing-conveyed perforation (TCP), the CT approach exhibited superior efficacy. The strategic implementation of downhole tractors enhanced operational efficiency while remaining aligned with the project’s vision.\u0000 \u0000 \u0000 \u0000 Well surveys for the horizontal gas wells featured in this study are becoming more complex, with greater dogleg severity and longer horizontal sections with the purpose of increasing the reservoir contact in the producing drain. As a result, the friction between the CT string and the well completion causes helical buckling that does not allow the CT pipe to convey the long bottomhole assembly (BHA) deeper after the lockup depth. In this case, the lockup effect is particularly severe because the large inner diameter of more than 6 in. of the completion allows the helical buckling to manifest more dramatically.\u0000 A depth-reach simulation was run for all CT well-intervention candidates as part of a preassessment. Multiple depth-reach simulations were conducted to establish methods that allow conveyance of the guns to target depth in a single run to overcome the lockup effect.\u0000 In this project, the main objective was to convey long sections of 2⅞-in. outer-diameter (OD) guns in single runs and retrieve the spent guns under pressure. The perforation sequence usually requires TCP to bring the guns to cover the first pay zone with an average of 1,200 ft of interval. Then, the 2⅜-in. OD CT strings are used with the help of a live well-deployment system to run similar lengths of guns in the subsequent intervals. These perforations are performed along horizontal sections longer than 10,000 ft, representing a true vertical depth/measured depth ratio of greater than 2 completed with 7-in. liners.\u0000 \u0000 \u0000 \u0000 In the basic sequence, in the first zone, TCP was used to bring the guns to target depth in overbalanced conditions and then electrical wireline was used to set a temporary plug to allow the installation of the wellhead on surface and allow the rest of the interventions to be performed by CT.\u0000 A CT equipped with fiber-optic real-time downhole telemetry was used to perforate the upper zones. Additionally, the CT firing head was hydraulically activated, and the downhole pressure parameters a","PeriodicalId":16720,"journal":{"name":"Journal of Petroleum Technology","volume":null,"pages":null},"PeriodicalIF":0.0,"publicationDate":"2024-06-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"141278332","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}