Journal of Petroleum Technology最新文献

{"title":"Data Science Has Exploded Across the Industry Over the Past 75 Years","authors":"Adam Wilson","doi":"10.2118/0424-0018-jpt","DOIUrl":"https://doi.org/10.2118/0424-0018-jpt","url":null,"abstract":"In 1957, the Journal of Petroleum Technology published an article titled “Application of Large Computers to Reservoir Engineering Problems.” That was the first reference in JPT to what became known as supercomputers.\u0000 The high-speed computers used in the 1957 article were capable of performing 60 million operations in about 3½ hours. They were proposed to analyze the thorny problem of multiphase flow. “It presently appears that the large computer will be required to investigate multiphase flow and to predict the flow behavior of oil and gas reservoirs considering two- and three-space dimensions.”\u0000 Now, 67 years later, supercomputer speeds are measured in trillions of operations per second, and investigating multiphase flow is just one of the many uses. This extreme growth in speed has given rise to artificial intelligence (AI) and machine learning (ML), which has found its way into almost every corner of the petroleum industry.\u0000 The Society of Petroleum Engineers and JPT has kept up with the digital advances in the industry, holding countless conferences, symposia, and other meetings centered on the digital aspects of the industry and recently creating the Data Science and Engineering Analytics (DSEA) technical discipline. In 2019, SPE launched the Data Science and Digital Engineering in Upstream Oil and Gas online publication.\u0000 Four leaders in the oil and gas digital space shared their views on the current state of data science in the industry and the future of the discipline.\u0000 Sushma Bhan, currently on the board of directors for Ikon Science, is SPE’s Technical Director for DSEA. Before joining Ikon, she worked for Shell for 32 years, eventually rising to the role of chief data officer for subsurface and wells.\u0000 “My journey in the oil and gas industry began in 1988, when I joined Shell’s Production Computing Assisted Operations team as a programmer analyst,” Bhan said. “During my time there, I gained valuable exposure to field production operations and developed a deep understanding of real‑time data.”\u0000 Jim Crompton, who claims he is mostly retired, is an associate professor of petroleum engineering at the Colorado School of Mines, a faculty fellow at the school’s Payne Institute for Public Policy, and director of Reflections Data Consulting.\u0000 “My academic career started out in exploration geophysics, so my first introduction to engineering analytics came from processing seismic data at Chevron Geophysical Company in Houston,” Crompton said. “I studied earthquake seismology in graduate school, but, when I graduated, I learned the oil and gas industry paid a lot more than the USGS did, so my career goals changed.”\u0000 Shahab D. Mohaghegh is a professor at West Virginia University and the president of Intelligent Solutions.\u0000 “Since I started working for the petroleum industry throughout the world using artificial intelligence in 2000, I was able to work with actual data (field measurements) that has been saved by all the companies,” Mohaghegh said. ","PeriodicalId":16720,"journal":{"name":"Journal of Petroleum Technology","volume":"162 2","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-04-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140760358","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":"Poromechanics Modeling Forecasts Production, Analyzes Productivity Decline","authors":"C. Carpenter","doi":"10.2118/0424-0100-jpt","DOIUrl":"https://doi.org/10.2118/0424-0100-jpt","url":null,"abstract":"\u0000 \u0000 This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 212200, “Accurate Production Forecasting and Productivity Decline Analysis Using Coupled Full-Field and Near-Wellbore Poromechanics Modeling,” by Yan Li, Bin Wang, and Jiehao Wang, Chevron, et al. The paper has not been peer reviewed.\u0000 \u0000 \u0000 \u0000 Productivity index (PI) decline is caused by different mechanisms in both the wellbore region and the far field. Damage in the wellbore region can be simulated by detailed wellbore modeling. A newly developed full-field and near-wellbore poromechanics coupling scheme is used in the complete paper to model PI degradation against time. Near-wellbore damage and field and well interactions are identified when applying the coupling scheme for a deepwater well. History matching, production forecasting, and safe drawdown limits are derived for operational decisions.\u0000 \u0000 \u0000 \u0000 Full-field and near-wellbore modeling involves coupling the simulation of a full-field reservoir model with one or more near-wellbore poromechanics models. In the coupled simulation, the full-field reservoir model dictates the changing flow or thermal boundary conditions for the embedded near-wellbore models. Meanwhile, near-wellbore phenomena affect well productivity in the full-field reservoir model, altering the flow and thermal boundary conditions on all near-wellbore models in the same field. While capturing the dynamic interactions between the full-field model and all embedded near-wellbore models is of vital importance, the traditional near-wellbore modeling work flow considers only one-way coupling. This work flow is labor-intensive and lacks the dynamic interplay between the reservoir and near-wellbore models.\u0000 A novel near-wellbore coupling framework is developed to automate data exchange and capture dynamic interactions between the full-field model and the near-wellbore model. In the full-field reservoir and geomechanics coupling applications, only a reservoir simulator solves reservoir flow and thermal equations and a geomechanics simulator solves solid mechanics equations. The reservoir and geomechanics simulators exchange 3D field data. Because solid mechanics equations are quasistatic, the geomechanics simulator does not take timesteps in full-field coupling. In near-wellbore coupling, however, both reservoir and geomechanics simulators solve reservoir flow and thermal equations. The near-wellbore geomechanics model also may solve solid mechanics or other equations coupled to flow or thermal equations in the near-wellbore model.\u0000 All physics are included in the near-wellbore model for the coupling. Both field properties (3D) and transient boundary conditions (2D) must be mapped onto the near-wellbore model. It is important to ensure that the full-field and near-wellbore models are consistent. A 3D data-mapping module is developed to map flow and rock properties and initial conditions from the full-field model to the near-wellbore mod","PeriodicalId":16720,"journal":{"name":"Journal of Petroleum Technology","volume":"237 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-04-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140759961","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: Navigating Tax Credits Challenges for the Hydrogen Spectrum","authors":"P. Boschee","doi":"10.2118/0424-0008-jpt","DOIUrl":"https://doi.org/10.2118/0424-0008-jpt","url":null,"abstract":"The rainbow of colors of potential hydrogen sources as alternative energy share two sticking points: the economic feasibility of the advancement of the technologies required for real-world applications and the ultimate cost of supply to its end users.\u0000 Pink hydrogen, produced through water electrolysis powered by nuclear energy, recently drew attention which underscored the decision-making to advance such projects.\u0000 Constellation Energy, the operator of the largest fleet of nuclear plants (21 reactors) in the US, announced its plans in October 2023 to build the world’s largest nuclear-powered clean hydrogen facility at its LaSalle Clean Energy Center in Illinois.\u0000 The nuclear powerhouse is a participant in the Midwest Alliance for Clean Hydrogen (MachH2) hub selected for funding of up to $1 billion by the US Department of Energy (DOE) under the Infrastructure Investment and Jobs Act.\u0000 Constellation intended to use a portion of the funding to build the facility estimated to cost $900 million. Annual pink hydrogen production was forecast to be about 33,450 tons.\u0000 Joe Dominguez, president and CEO of Constellation, said at that time, “In the months leading up to this selection, Constellation, organized labor partners, and business leaders have urged the administration to provide important guidance implementing Congress’ intention to allow hydrogen production using carbon-free power from existing nuclear stations to earn tax credits contained in the Inflation Reduction Act (IRA). Without those credits, projects like this one will not go forward. Today’s award is proof positive that DOE and the administration want existing nuclear energy to play a vital role in jumpstarting domestic hydrogen production, and we look forward to final Treasury Department guidance.”\u0000 In December, the preliminary guidelines were issued, and they included a speed bump that brought Constellation’s plan to a halt. The appeal of advancing pink hydrogen faded with the proposed stipulation of “additionality,” which would require the nuclear power to be generated by new plants. Additionality is not limited to pink hydrogen; it would apply to all forms of clean hydrogen.\u0000 Dominguez told Bloomberg News, “The uncertainty around the regulations has brought us pretty much to a full stop.” He warned that the rule would likely kill the production of pink hydrogen in the US. “There’s no business case [for constructing new reactors],” he told Bloomberg. The billions\u0000 of dollars and time required to build new plants introduce enormous challenges to this nascent technology already facing hurdles. He added, “I’m frankly frustrated this issue has come up. It’s crazy.”\u0000 Additionality is intended to prevent the use of existing generation capacity—be it renewable energy such as solar, wind, or nuclear—for hydrogen production. The concern is that using established capacity could reduce the supply of power available to the grid and shift reliance back to fossil fuel to make up for a resulting gap i","PeriodicalId":16720,"journal":{"name":"Journal of Petroleum Technology","volume":"61 2","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-04-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140760264","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":"Monitoring, Modeling Techniques Help Optimize Eagle Ford Completions","authors":"C. Carpenter","doi":"10.2118/0424-0078-jpt","DOIUrl":"https://doi.org/10.2118/0424-0078-jpt","url":null,"abstract":"\u0000 \u0000 This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 212367, “Sealed Wellbore Pressure Monitoring and Calibrated Fracture Modeling: The Next Step in Unconventional Completions Optimization,” by Karen Olson, SPE, Joshua Merritt, and Rair Barraez, SPE, Well Data Labs, et al. The paper has not been peer reviewed.\u0000 \u0000 \u0000 \u0000 Sealed wellbore pressure monitoring (SWPM) has been used across North and South America, with more than 16,000 stages monitored. A recent development is the added capability of a fracture model that can automatically history-match the volume to first response (VFR) determined from SWPM. The complete paper’s focus is a case study of the Department of Energy Eagle Ford refracturing project, where a range of completion designs were trialed while monitoring offset SWPM and fiber-optic strain.\u0000 \u0000 \u0000 \u0000 Background. The HFTS1 Phase 3 was conducted at the Zgabay unit in northwest DeWitt County, Texas. This unit was initially developed with horizontal multistage completions and has been producing since 2013.\u0000 The 10 original wells in the unit, and the four new drilled wells, are landed in the approximately 100-ft-thick Lower Eagle Ford Shale. Of the four new drills, Well 14H is a dedicated observation well instrumented with various diagnostics, including a permanent fiber-optic cable. Well 12H, another new drill, was monitored using a wireline-deployable fiber. Both of these wells featured downhole gauges, while Wells 11H and 13H featured surface gauges.\u0000 The focus of the refracturing strain diagnostics— SWPM and fiber—was to characterize new fracture growth and interaction with pre-existing fractures during the liner refracturing of parent Wells 5H and 3H.\u0000 Completion Designs. Multiple stage and cluster architectures were tested on the Zgabay Wells 3H and 5H. Four single-cluster stages were performed per well. Both a high (2,000-psi target) and low (500-psi target) perforation friction design was tested on seven-, 12-, and 22-cluster stages. Well 3H maintained a slightly tighter cluster spacing (10–15 ft) compared with the 12–20 ft spacing of Well 5H. The main method of measuring the effect of different designs is strain monitoring using SWPM and fiber optics.\u0000 \u0000 \u0000 \u0000 SWPM. SWPM uses an uncompleted wellbore to monitor fracture intersections from offset-well stimulations. The monitor well collecting the SWPM data cannot be connected to a formation through perforations or other types of access points. The wellbore should be filled with low-compressibility fluid, with pressure added to the monitor well. Fractures intersecting the sealed wellbore cause local deformation, which results in a small volume reduction in the closed system and generates a discernable and distinct pressure response.\u0000 The total slurry injected into the stage of the active well when the first fracture arrival is identified using SWPM is the VFR. VFRs are used as a proxy for cluster efficiency and to calculate fracture-growth ra","PeriodicalId":16720,"journal":{"name":"Journal of Petroleum Technology","volume":"4 2","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-04-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140786309","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":"Annular Injection Mixer Approach Improves Evaporation of Heavy Hydrocarbons","authors":"C. Carpenter","doi":"10.2118/0424-0067-jpt","DOIUrl":"https://doi.org/10.2118/0424-0067-jpt","url":null,"abstract":"\u0000 \u0000 This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 216883, “How To Evaporate Heavy Hydrocarbon in a Natural Gas Stream Within a Short Distance: The AIM Concept,” by Fariz Maktar and Christian Chauvet, Wood, and John Sabey, SPE, Prosep. The paper has not been peer reviewed.\u0000 \u0000 \u0000 \u0000 Evaporating heavy hydrocarbons has long been a challenging task, especially in a limited area that requires rapid vaporization of liquified petroleum gas (LPG) fractions within a short distance. A static mixer that the authors call the annular injection mixer (AIM) has demonstrated superior performance in providing immediate and uniform vaporization of LPG fractions into natural gas. The complete paper focuses on the use of AIM in vaporizing heavy hydrocarbon (C4–C9) fractions into natural gas streams and the evaluation of evaporation performance through computational fluid dynamics (CFD).\u0000 \u0000 \u0000 \u0000 The efficacy of the AIM revolves around its capability to generate fine liquid droplets in the main gas stream. In the AIM, droplets generation takes place through a series of primary and secondary breakup processes. As the liquid phase is introduced into the AIM, the liquid phase travels along the conical wall as a thin liquid film. The difference in velocity between the liquid film and the carrier fluid, in this case natural gas, induces instability within the liquid film. Downstream of a sharp rim, called the “knife edge” by the authors, these instabilities grow further and eventually lead to the breakup of liquid film into liquid ligaments. These unstable ligaments experience further atomization and generate droplets. At higher carrier-fluid velocity, these droplets will deform and experience secondary atomization, generating much smaller droplets. This process continues until the droplets are sufficiently small and stable.\u0000 \u0000 \u0000 \u0000 The AIM is a static mixer with no moving parts (Fig. 1). It relies on the momentum of the carrier fluid to generate small liquid droplets and enhance their evaporation, resulting in 100% homogenization and full vaporization of the droplets within several pipe diameters downstream.\u0000 The AIM’s design consists of a convergent conical section and a divergent conical section. Between the sections, at the vena contracta, is the knife edge. LPG in the liquid phase is introduced into the AIM through annular rings consisting of multiple opening channels just upstream of the knife edge. Because of the high natural gas velocity in this area, the LPG is spread along the conical wall, forming a thin liquid film. Once the LPG liquid film reaches the knife edge, the liquid film transforms into liquid ligaments. These liquid ligaments are unstable and experience further breakup into liquid droplets. Additionally, these liquid droplets are subjected to droplet deformation and secondary droplets break up.\u0000 \u0000 \u0000 \u0000 Conventional 1D process simulators might be able to assess the evaporation capability of LPG into natural ","PeriodicalId":16720,"journal":{"name":"Journal of Petroleum Technology","volume":"643 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-04-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140776982","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":"An Acid Test for Spacing Decisions Complete 44 Wells With 129 Miles of Laterals on a 3×2-Mile Lease in the Midland Basin","authors":"Stephen Rassenfoss","doi":"10.2118/0424-0045-jpt","DOIUrl":"https://doi.org/10.2118/0424-0045-jpt","url":null,"abstract":"ConocoPhillips has an increasingly rare opportunity in the Permian—6 square miles of land over multiple layers of prime, undeveloped shale.\u0000 The scale of this Midland Basin project is huge—44 wells with laterals running the 3-mile length of the lease—as is the company’s patience.\u0000 Last fall, when a ConocoPhillips panel described the megaproject at the SPE Permian Basin Energy Conference in Midland, they said they were about 70% done with drilling. Fracturing would begin as drilling was ending and would take about 8 months to complete.\u0000 Only then would the wells in this geologic tank go into production, limiting any interactions with older wells inside the lease lines. However, outside that boundary there are older wells that could interact.\u0000 Brady Kolb, a staff geologist for ConocoPhillips who led off the panel discussion, explained, “All the zones communicate in some shape or form, so we take the whole tank and deliver it at the same time to maximize resource capture.”\u0000 The gains come from avoiding harmful interactions with older wells and the depleted zones they create, as well as the rock left undeveloped to create wide buffer zones around parents.\u0000 In addition, they are deploying innovative technology to reduce fuel costs and emissions, from grid power for two of its five drilling rigs to processing field gas to create the rich gas needed to run fracturing equipment. And they are using the flood of data gathered while drilling to continuously improve work on later wells.\u0000 On one level, it will certainly succeed. ConocoPhillips needed to begin drilling to hold on to a valuable lease with prime targets in the Wolfcamp and Spraberry formations.\u0000 “We had a pretty significant drilling obligation on the ranch and had to drill quite a few wells,” said Carl Warren, a senior reservoir engineer for ConocoPhillips, during the Permian conference panel discussion.\u0000 For ConocoPhillips this is a high-profile example of its approach to maximizing the value of its shale development with longer laterals and graduating all the wells to production at about the same time, also known as “co-development.”\u0000 “Co-development allows us to minimize the parent-child impacts while improving recovery, as well as capital efficiency. And we’ve demonstrated over the past 4 years, both in the Midland Basin as well as the Delaware Basin, improved performance there,” said Nick Olds, executive vice president Lower 48 for Conoco Phillips during an earnings call last November.\u0000 ConocoPhillips will complete 129 miles of laterals in a zone that covers 1,300 ft of rock (8,500 to 9,800-ft total vertical depth) within the 3×2-mile area to test what it has learned about placing wells and to maximize the return on investment.\u0000 Those with long memories are likely to remember past efforts at mass development, known as cube or tank developments. Those were examples of a good concept undermined by a blunder—those pioneers crammed far too many closely spaced horizontal wells into a formation.","PeriodicalId":16720,"journal":{"name":"Journal of Petroleum Technology","volume":"320 19","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-04-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140779792","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":"Chemical Additives Assist Oil-in-Water Emulsion Formation in SAGD","authors":"C. Carpenter","doi":"10.2118/0424-0086-jpt","DOIUrl":"https://doi.org/10.2118/0424-0086-jpt","url":null,"abstract":"\u0000 \u0000 This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 212779, “Oil-in-Water Emulsion Formation in SAGD With Chemical Additives,” by S. Ali Ghoreishi, University of Calgary, and Javier O. Sanchez and Julian D. Otiz-Arango, ConocoPhillips, et al. The paper has not been peer reviewed.\u0000 \u0000 \u0000 \u0000 The study detailed in the complete paper aims at understanding the effect of a surfactant that the authors refer to as a high-temperature emulsifying agent (HEA) as an additive in the steam-assisted gravity drainage (SAGD) process. The work provides insights into the role of surfactants in forming oil-in-water (O/W) emulsions in steam-based bitumen production. A novel high-pressure/high-temperature (HP/HT) visual cell enables the rapid assessment of recovery processes and a better understanding of the active emulsifying mechanism in such a system.\u0000 \u0000 \u0000 \u0000 The authors conducted a pore-network micromodel experiment to analyze the effect of emulsifiers on the SAGD process. Hot water, with and without a priority emulsifying agent, was injected into a bitumen-saturated micromodel at 82°C. The surfactant solution can remove the residual oil from the invaded zone and forms O/W emulsions as it spreads in uninvaded regions.\u0000 \u0000 \u0000 \u0000 The experimental setup includes a high-resolution imaging system, a lightbox, a precision syringe pump, a bitumen-transfer vessel, and an HP/HT cell (Fig. 1a). A borosilicate glass micromodel (Figs. 1b and 1c) was placed inside the vertical HP/HT cell, and the remaining space in the HP/HT cell was filled with a heat-resistant mineral oil. The heating jacket was mounted on the HP/HT cell, and a digital thermometer was connected to the heating jacket and placed between the heating jacket and the cell to monitor and control the temperature. The micromodel inlet was connected to the syringe pump.\u0000 The remainder of the experimental process is detailed in the complete paper.\u0000 \u0000 \u0000 \u0000 Effect of HEA on Emulsion Formation and Sweeping Patterns.\u0000 In all experiments, the hot aqueous phase was injected at the rate of 5 μL/min into the micromodel fully saturated with Athabasca bitumen. The HP/HT cell was kept at a constant temperature of 82°C. The hot water injection was used as the base system to be compared with the HEA-solution injection.\u0000 Water droplets trapped in the pockets of bitumen phase were observed at the later stages of displacement in flooded areas near the two-phase interface. Water droplets were first formed at the top of the micromodel, close to the injection port, and were pushed down toward the production port as injection continued. O/W droplets, in a much lesser quantity, also were formed during the displacement process close to the production port.\u0000 An HEA solution with a concentration of 3,000 ppm was injected under the same conditions as the hot-water-injection scenario. The HEA solution also formed a chamber at the top of the micromodel with an advancing finger toward the production port. ","PeriodicalId":16720,"journal":{"name":"Journal of Petroleum Technology","volume":"53 42","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-04-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140796155","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 Update Geothermal Energy","authors":"Jeffrey R. Bailey, Taylor Mattie, Tim Lines, Daniel Merino-Garcia","doi":"10.2118/0424-0052-jpt","DOIUrl":"https://doi.org/10.2118/0424-0052-jpt","url":null,"abstract":"\u0000 \u0000 This is the first of 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; improving recovery from tight/shale resources; net-zero operations; carbon capture, storage, and utilization; digital transformation; and education and advocacy.\u0000 \u0000 \u0000 \u0000 SPE identified five technical “Grand Challenges” in 2023 which, if successfully developed, could advance the interests of the SPE community in a net-zero world and help ensure our longevity and contributions to a prosperous future (Halsey et al. 2023).\u0000 Access to the subsurface is a key skillset of the SPE community, including geology and geophysics, well construction and completion, reservoir engineering, production operations, and facilities. The challenges that geothermal faces to become a leading player in the net-zero world are well within the areas of expertise of the SPE community, ranging from rapid technology implementation and learning-by-doing to assure competitiveness, to establishing suitable funding mechanisms to secure access to capital.\u0000 The increasing presence of geothermal-related sessions in SPE workshops and conferences shows the interest to explore novel methods to harness geothermal energy for power supply, thermal-use applications, and energy storage, illustrated by the threefold increase in OnePetro references since 2020 (Fig. 1).\u0000 The Role of the Oil and Gas Industry Geothermal energy offers a path forward using business models that are well-suited to the oil and gas industry, which can apply its current technology and expertise to produce clean, reliable power and thermal energy at scale. Geothermal is also the only baseload renewable energy source that produces heat, presenting an avenue to mitigate the largest contribution humanity makes to carbon emissions: heating and cooling which account for 40% of all carbon emissions globally (Lund and Toth 2021).\u0000 Table 1 presents some of the current applications.\u0000 In 2023, the Energy Institute of The University of Texas at Austin released a comprehensive report, “The Future of Geothermal in Texas,” led by Project InnerSpace (Beard and Jones 2023). The report presented a challenge to leverage the technical capabilities and resources in the state.\u0000 It estimated that “should the industry drill 15,000 geothermal wells each year for four years, it would provide the energy equivalent of all oil and gas used for electricity and heat production in the State today, including industrial heat.” This initiative is part of a broader movement in Texas, the spiritual home of the US fossil fuel industry, where a new geothermal energy ecosystem is emerging with veterans of the oil and gas business playing pivotal roles.\u0000 Geothermal energy cannot only help to reduce the state’s emissions but also throu","PeriodicalId":16720,"journal":{"name":"Journal of Petroleum Technology","volume":"98 ","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-04-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"140797581","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":"28 4","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"139819863","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":"71 1","pages":""},"PeriodicalIF":0.0,"publicationDate":"2024-02-01","publicationTypes":"Journal Article","fieldsOfStudy":null,"isOpenAccess":false,"openAccessPdf":"","citationCount":null,"resultStr":null,"platform":"Semanticscholar","paperid":"139821671","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}