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Collaborating Authors
Wilson, Adam
In this month’s Field Development feature, SPE conference authors place an emphasis not only on original research and findings but also on validation and refinement of existing techniques that may not have received thorough attention in the literature. As operators strive to achieve the greatest returns possible from technically, environmentally, and economically challenging plays, they are driven to innovate new approaches and to fine-tune existing ones. In paper SPE 206267, the authors investigate the performance of a distributed quasi-Newton (DQN) derivative-free optimization (DFO) method, which, they write, had not yet been validated by realistic applications or compared with other DFO methods. They integrate DQN into a versatile field-development optimization platform designed for iterative work flows enabled through distributed parallel flow simulations. The method was field-tested on two realistic applications and identified the global optimum with the least number of simulations and the shortest run time on a synthetic problem with a known solution. The authors of paper SPE 207146 create and evaluate a development plan for an oil field discovered in a remote offshore environment in the Niger Delta. Because the oil in place was uncertain, a probabilistic approach was used to estimate the stock-tank oil originally in place using low, mid, and high cases. Keeping in mind governmental regulations to maintain the reservoir pressure above bubblepoint, the authors propose a development plan that is marginally base modeled and, despite the uncertainty of oil prices in the market, able to cover any unforeseen situations. Finally, the authors of paper SPE 208882, addressing the challenge posed by cumbersome integrated technical work flows for multiwell fracture modeling and reservoir simulation, use tools existing in the literature to quantify the effect of changing well spacing on well productivity for a given completion design using a simple, intuitive empirical equation. After describing and qualifying the use of their approach, they apply it to a case study from the Permian Basin. Recommended additional reading at OnePetro: www.onepetro.org. OTC 31151 - Autonomous Subsea Field Development—Value Proposition, Technology Needs, and Gaps for Future Advancement by Giorgio Arcangeletti, Saipem, et al. SPE 206533 - Field Development Optimization Using Machine-Learning Methods To Identify the Optimal Waterflooding Regime by Alexey Vasilievich Timonov, Consultant, et al. URTeC-2021-5301 - Unconventional Reservoir Development Performance Reviews—the Northern Midland Basin Case Study by Hongjie Xiong, University Lands, et al.
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- North America > United States > Texas > Permian Basin > Yates Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (21 more...)
Natural gas has two faces. On one side, it is an important part of the energy-transformation toolkit. On the other side, it is a potent greenhouse gas. Technology can bring the two sides together. The three papers selected for this Tech Focus feature describe technologies that can make natural gas safer to move and store. The first paper, OTC 30655, describes an effort to eliminate flaring during offloading from a floating liquefied natural gas facility (FLNG) and an LNG carrier. Managing the balance of fuel gas and boiled-off gas between the FLNG and the carrier is vital to maintaining equilibrium and eliminating flaring. The paper looks at carriers with spherical tanks and presents a process study to identify potential causes of flaring during offtake and corrections that could eliminate it without capital modifications. The second paper, OTC 30871, considers the benefits of barges over ship-type LNG carriers. Ship-type LNG carriers are designed to operate offshore over fields, which does not necessarily provide optimal opportunity for monetization. The paper argues that near-shore barges holding liquefaction facilities linked to the rest of the system elsewhere could be a more-viable gas-monetization concept. The third paper, SPE 204787, describes a characterization and monitoring approach for underground gas storage. The approach involves close integration of subsurface understanding with the optimization of surface facilities. It also addresses sustainable operations through an asset-integrity-management plan. To learn more about the advancement of technology in the natural gas space, check out the suggested additional reading and visit the OnePetro online library. Recommended additional reading at OnePetro: www.onepetro.org. IPTC 19783 - Hybrid System—An Emerging Solution to Sour Gas Treatment by Siddharth Parekh, Schlumberger SPE 202984 - Sour Gas Has a Sweeter Future—Bulk H2S Removal Using Polymeric Cellulose Triacetate-Based Membranes by Pinkesh Sanghani, Schlumberger, et al. SPE 208134 - Inventory Verification in Underground Gas Storage Rebuilt From Depleted Gas Reservoir: A Case Study From China by Lina Song, PetroChina, et al. SPE 207956 - Unconventional Waste and Flare Gas Recovery System in New Circular Economy by Mohamed Ahmed Soliman, Saudi Aramco, et al.
- Asia > Middle East > Saudi Arabia (0.57)
- Asia > China (0.57)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > Asia Government > Middle East Government > Saudi Arabia Government (0.57)
The oil and gas industry has picked up on the benefits of digitization and artificial intelligence (AI) in its day-to-day activities, and the health, safety, and environment (HSE) sector is no exception. While AI brings clear benefits, the risks that come with those benefits remain unclear. While touting the advances of technology in HSE at SPE’s Virtual Annual Technical Conference and Exhibition (ATCE), Olav Skar, director of health, safety, security, and wells at the International Association of Oil and Gas Producers (IOGP), said, “I also see risks, and I remain concerned that we do not truly understand them.” Skar spoke at the ATCE on a panel that included Mohamed Kermoud, Schlumberger’s global vice president for HSE, and Philippe Herve, the vice president of energy solutions at Spark-Cognition. The panel was moderated by Josh Etkind, Shell’s Gulf of Mexico digital transformation manager. “A lot of power is in the technology,” Herve said. “The technology is beautiful. How we as humans are going to apply it, we need to think about it. We are thinking about all of the good things that the technology is bringing to humanity. Let’s keep it that way and remove all of the applications of artificial intelligence technology that may not be well perceived or beneficial to anybody.” An early target for digitization in oil and gas, driving has been the most dangerous HSE activity for employees. The IOGP claims that land-transportation-related incidents historically have been the largest cause of fatalities for its member companies. Since 2000, such incidents have accounted for 22% of all work-related fatalities reported by IOGP members. Schlumberger’s approach to driving safety was outlined in a paper presented at the 2020 SPE International Conference and Exhibition on Health, Safety, Environment, and Sustainability, a synopsis of which appeared in the August 2020 issue of JPT (http://go.spe.org/_01104-1542r). Schlumberger’s approach to improving driver safety includes an advanced driver-assistance system that alerts drivers of maximum speed limits, lane departures, and the proximity of pedestrians and other vehicles. The goal of the system is to effect good driver behavior. “If you analyze all the data, all the incidents, you find that behavior is always behind it,” Schlumberger’s Kermoud said. “People are trying to save time, to save the day. … The rules are generally perfect, but the behavior is something that we absolutely need to make sure that we impact one way or the other. And using technology will help us.”
- North America > United States (0.25)
- North America > Mexico (0.25)
Oil and gas are not the only things in the ground that can power our lives. Heat in the form of geothermal energy is rapidly taking its place alongside other sources of renewable energy, buoyed by the lessons learned from decades of drilling for oil. “Geothermal is this fantastic resource,” said Susan Hamm, director at the Geothermal Technologies Office in the US Department of Energy. “It’s an always-on renewable energy resource that harnesses the Earth’s natural heat. It improves domestic energy security and flexibility.” These benefits and challenges are the basis of the Geo Vision report (https://www.energy.gov/eere/ geothermal/geovision) created by the Energy Department. Hamm, along with Tim Latimer, the cofounder and chief executive officer of Fervo Energy, a company working on geothermal energy, and Aparna Raman, president of reservoir performance at Schlumberger, spoke during the Unconventional Resources Technology Conference. Hamm and Latimer laid out the benefits of geothermal sources of energy beyond its renewability. “It provides dispatchable baseload power,” Hamm said. “And this dispatchable nature is really key. You can turn it on, you can turn it off. You can turn it up, you can turn it down.” “It not only produces clean power,” Latimer added, “it does it around the clock, 24/7. It’s a fantastic complement to wind and solar resources to decarbonize the hardest parts of the electric grid.” Hamm mentioned that geothermal complements wind and solar by being widely available, pointing out that geothermal sources are available across the United States (Fig. 1). She also touted geothermal’s reliability, saying that, while solar can provide energy 20% of the time and wind 45% of the time, geothermal sources can provide energy more than 90% of the time. “In order to have a geothermal resource, you need to have three things,” Hamm said. “You need to have heat at depth, which we’ve already shown is everywhere, just in differing amounts. You need to have a fluid in the subsurface, and you need to have pathways for that fluid to move around to get the heat so you can get it back out.” An enhanced geothermal system (EGS) is a system wherein one or more of those aspects is created where it did not previously exist. “You either fracture the subsurface or you add water, or you do both in order to be able to recover that stranded heat.” Latimer, who began his career as a drilling engineer, turned toward geothermal sources after working in the Eagle Ford shale, where high temperatures were a problem to be solved. In solving the high-temperature problem, he said cues were taken often from the geothermal industry.
- North America > United States > Texas (0.25)
- North America > United States > California (0.15)
- Government > Regional Government > North America Government > United States Government (1.00)
- Energy > Renewable > Geothermal (1.00)
- Energy > Oil & Gas > Upstream (1.00)
The 2019 SPE Annual Technical Conference and Exhibition (ATCE) was held in Canada for the first time during 29 September–2 October. More than 6,000 petroleum professionals attended the event in Calgary, which offered a comprehensive review of technical topics related to industry productivity, digital transformation, safety, and sustainability.•• • Industry’s Difficult Task: Meet Global Demand While Lowering Emissions John Donnelly, JPT Editor The oil and gas industry must not only adapt to heightened public and government scrutiny on environmental issues but also be a leader in the world’s quest for a lower-carbon energy future, panelists agreed during the opening session at the conference. The panel session, titled “Positively Impacting the World through Responsible Energy Development,” featured participants from BP, Baker Hughes, Gazprom Neft, and ARC Energy Research•Institute. • Industry Strives To Leave Operations Alone Adam Wilson, Special Publications Editor Having rigs that run without people can increase safety and efficiency. The industry has known that for years, yet implementing these remote operations sometimes has been a challenge, and integrating these operations has been an even larger challenge. That was the topic at a panel dinner held by SPE’s Digital Energy Technical Section during the conference. “Remote has been embedded in the digital concept for over 10 or 15 years,” said Tony Edwards, chief executive officer of Stepchange Global and moderator of the panel. “The idea of taking data information from your operations center, bringing it to the back office, and actually being able to do something is core to the digital oilfield integrated operations concept for 10 or 15 years now.” • Bandwidth of Nanotechnology in the Oil Field Widens Judy Feder, Technology Editor On the final day of the conference, attendees filled a hall to listen to seven experts discuss the value to the oil and gas industry of particles that are less than 1 micron in length. Nanotechnology has great potential to reduce cost, increase production, and even improve the sustainability of E&P operations. The gap between potential and reality is closing, the number of applications is growing, and the industry is ready and willing to use nanotechnology if it can be shown to deliver better performance for less money, according to the panelists and moderators—Steven Bryant of the University of Calgary; Hugh Daigle of The University of Texas at Austin; Ramanan Krishnamoorti of the University of Houston; Oya Karazincir of Chevron; Reinhard Pongratz and Philipp Urban of OMV Exploration; and Hui Zhang of M-I Swaco. Nanotech in oil and gas has become a hammer with many nails. • Women in Energy Share Tips, Tricks, and Wisdom at Inaugural Meeting Judy Feder, Technology Editor The real challenge of attracting and retaining women in the upstream oil and gas industry has nothing to do with gender, said four industry leaders at the inaugural SPE Women in Engineering Committee Breakfast. The four—incoming SPE President Shauna Noonan, director of artificial lift engineering for Occidental Petroleum; Helen Chang, chief engineer for Alberta Energy Regulator; Lils Groenendaal, venture planning transition manager for Shell Exploration & Production; and panel moderator Melanie Popp, director of engineering for geoLOGIC Systems— came together to share their thoughts about personal and professional engagement, empowerment, and success with existing and new SPE members. In the course of the discussion, the panelists agreed that the real challenge of attracting and retaining all talent— not just women—is tied to the industry’s unintentional “brand” among people outside it. • Canadian Startups Shine in Calgary Contest Trent Jacobs, JPT Digital Editor They are among the smallest companies in a business dominated by big ones. Yet, despite their size, technology startups have become central to the upstream industry’s mandate to adopt cost-saving and production-enhancing innovations. As more begin to agree with this idea, the infrastructure that supports the oil and gas startup ecosystem is strengthening. The latest evidence came during the SPE 2019 Annual Technology Conference and Exhibition (ATCE) where a dozen startups were invited to take part in the third annual Energy Startup Competition. The event falls under the broader program that is the ATCE Startup Village. • 2020 SPE President Promises to Focus on Strengthening Organization’s Engineering Core Trent Jacobs, JPT Digital Editor This year’s conference wrapped up with the ceremonial induction of the new 2020 SPE President, Shauna Noonan, who is the director of artificial lift engineering for Occidental Petroleum. Noonan’s ascendance to the organization’s top volunteer position comes after she served on the SPE’s board of directors and authored and coauthored more than 25 technical publications. An SPE member since her time as an engineering student at the University of Alberta, Noonan said it was “surreal” to be assuming the presidency in her home province. The annual conference was held in Calgary for the first time.
- North America > Canada > Alberta > Census Division No. 6 > Calgary Metropolitan Region > Calgary (0.85)
- North America > United States > Texas > Travis County > Austin (0.34)
- Information Technology > Communications > Collaboration (0.66)
- Information Technology > Knowledge Management (0.46)
2019 OTC review Digitalization and automation were key topics in the panel and technical sessions at this year’s Offshore Technology Conference (OTC) as the iconic event celebrated its 50th anniversary. More than 59,000 attendees participated in the conference, which was held 6–9 May in Houston. OTC launched its golden anniversary with a wide-ranging panel discussion on the current viability of the offshore sector and how digitalization will change it in the future. Total’s Energy Outlook 2040 proposes two distinct scenarios of the energy future: a momentum scenario, in which oil demand is dominated by transportation and petrochemicals, and a rupture scenario, which sees a massive shift in public policy and the growth of renewables. Either way, “our industry has a major role to play in climate change issues,” said Arnaud Breuillac, president of exploration and production for Total. The global energy mix is changing, he said, but the question is how rapidly, especially regarding use of electric vehicles and the growth of electrification in developing countries. Given the projected population rise and the fact that 1.5 billion people do not have access to energy now, increased use of natural gas and renewables is the “right approach to stabilize the energy system,” Breuillac said. The 21st century will likely be the “century of electricity,” he added. “It is clear that the pace of change does not lie entirely in our hands,” he said about the use of hydrocarbons in the future, but will be influenced by the public and policymakers as well. For now, Total is pursuing projects on the low end of the cost curve while trying to reduce its carbon footprint from production to customer delivery. Whether the industry should pursue a future of reduced hydrocarbon production and use appears to be a dilemma, said panel moderator Scott Tinker, director of the Bureau of Economic Geology at The University of Texas at Austin. If climate change is the worst problem, then reduced hydrocarbon use could be part of the solution; but if poverty is the globe’s biggest issue, then hydrocarbons are undoubtedly part of the solution. Although the industry “does produce a lot of CO2,” Tinker said, access to readily available and affordable energy also alleviates hunger and provides clothing, shelter, and clean water, and allows access to education, health care, and medical services, among other things. Offering more perspective, Tinker noted that although there is a lot of talk about the growth in wind and power for energy, their use is but a fraction of demand for oil, natural gas, and coal. Over the past several decades, carbon emissions in the US and Europe have been flat to slightly down, while emissions in Asia have grown sharply, he said.
- Asia (0.67)
- North America > United States > Texas > Travis County > Austin (0.24)
- Health, Safety, Environment & Sustainability > Sustainability/Social Responsibility > Sustainable development (1.00)
- Health, Safety, Environment & Sustainability > Environment > Climate change (1.00)
- Facilities Design, Construction and Operation > Offshore Facilities and Subsea Systems (1.00)
- Data Science & Engineering Analytics > Information Management and Systems (1.00)
This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 191574, “Delivering Drilling Automation II: Novel Automation Platform and Wired Drillpipe Deployed on Arctic Drilling Operations,” by Riaz Israel, Doug McCrae, Nathan Sperry, Brad Gorham, Jacob Thompson, and Kyle Raese, BP, and Steven Pink and Andrew Coit, SPE, NOV, prepared for the 2018 SPE Annual Technical Conference and Exhibition, Dallas, 24–26 September. The paper has not been peer reviewed. This paper presents a case history of drilling automation system pilot deployment, including the use of wired drillpipe, on an Arctic drilling operation. Two major aspects of technology were introduced during this pilot, the first being a drilling automation software platform that allowed secure access to the rig’s drilling control system. The second component was a wired drillstring, which provides high-speed delivery of downhole data from a series of distributed downhole sensors. Introduction In an effort to enhance the safety of its operations, improve well construction efficiency, and leverage the potential opportunities presented by digitalization of drilling, the operator has initiated a Remote Operations and Intelligent Automation Project. The project involved the deployment of an automation operating system (AOS) on top of an existing drilling control system. The AOS provides the ability for secure, programmatic control of the rig’s major drilling hardware through the use of software. The software interface allows for custom configuration of several routine drilling activities for automated execution. The project also evaluated the latest version of the service company’s wired drillpipe (WDP). At the time of writing, the project has delivered eight wells, with various combinations of the technology implemented. The overall objectives of the project were to evaluate The readiness of the AOS for wider deployment The reliability of the latest version of WDP The maturity of the AOS drilling applications The effectiveness of this technology in reducing well costs For each well, key performance indicators (KPIs) were defined that aligned with the project-level KPIs and are dependent on the specific aspect of the technology being used on that well. Field Description The giant Prudhoe Bay field, on the North Slope of Alaska on the edge of the Arctic Circle, was discovered in 1968 with an initial estimate of 22 billion to 25 billion bbl of oil in place and has been in production since June 1977. Since the field began production, it has generated more than 12.5 billion bbl of oil, making it the most productive US oil field. The field has been a proving ground for advanced drilling techniques, including multilateral and coiled tubing, now used in oil fields around the globe. Production from Prudhoe Bay is supported by ongoing drilling activity. Technology Description An overview of the automation technology is presented in Fig. 1.
- North America > United States > Alaska > North Slope Basin > Prudhoe Bay Field (0.99)
- Asia > Middle East > UAE > Abu Dhabi > Arabian Gulf > Rub' al Khali Basin > Ghasha Concession > Umm Shaif and Nasr Block > Umm Shaif and Nasr Field > Umm Shaif Field > Arab Formation (0.99)
This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 191458, “Good Tests Cost Money, Bad Tests Cost More: A Critical Review of DFIT and Analysis Gone Wrong,” by R.V. Hawkes, SPE, Trican Well Service; R. Bachman, SPE, CGG; K. Nicholson, Perpetual Energy; D.D. Cramer, SPE, ConocoPhillips; and S.T. Chipperfield, SPE, Santos, prepared for the 2018 SPE International Hydraulic Fracturing Technology Conference and Exhibition, Muscat, Oman, 16–18 October. The paper has not been peer reviewed. Diagnostic fracture injection tests (DFITs) incur direct and indirect costs resulting from the tests themselves and the extended time required for the pressure falloff, which delays the completion of the well. The benefits, therefore, must outweigh the costs if the test is to be justified. These tests are performed regularly around the world because a DFIT is one of only a few processes that can help quantify both geomechanical properties and reservoir-performance drivers within the same test. Introduction Operators and service providers commonly experience problems with DFIT execution and analysis despite efforts to reduce errors and inconsistencies. Before any field execution or analysis, the objectives of a DFIT must be considered. Historically, DFITs were performed predominantly for the purpose of designing better full-scale hydraulic-fracture treatments with early-time measurements of initial shut-in pressure, leakoff coefficient, and fracture closure having priority over reservoir parameters such as permeability and pore pressure. Increasingly, practitioners are using DFITs to measure reservoir parameters such as initial pressure and permeability. While, in many cases, these parameters may be obtained from a single successful test, other situations have time constraints or rock and reservoir properties that constrain operations to a point where priorities must be set. While leakoff and closure values are determined early in the DFIT shut-in period, reservoir pressure and permeability are derived from late-time measurements that may require longer falloff times. The complete paper presents cases encountered in which test procedures/operations or incorrect analysis misled engineers. Cases presented are Several Canadian Duvernay shale wells illustrating the importance of multiple tests and the use of gradients to understand fracture orientation and possible complexity. A well where the initial DFIT had an injection rate that was too low combined with operational issues. A second test on the same interval yielded better results. A Canadian Montney well where rock/fluid interactions led to a false radial-flow signature. Two subnormally pressured Canadian oil wells where surface falloff pressure dropped to a vacuum (i.e., falling liquid level), causing late-time effects that were not reservoir related. The authors present a work flow to determine reservoir pressure in this situation. An Australian naturally fractured gas well showing the importance of sufficient falloff time. A proper DFIT may be critical for assessing the geomechanical and reservoir properties of unconventional reservoirs. However, simple guidelines such as wellbore conditioning, the understanding of pressure anomalies resulting from wells going on vacuum, and the importance of flow-regime identification are often overlooked, leading to poor results. Having access to numerous high-quality data sets from various international oil and gas operators provides insight to establishing some useful guidelines that are applicable anywhere in the world.
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Reservoir geomechanics (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Pressure transient analysis (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE-191437-18IHFT-MS, “ACA Practical Considerations: When Is It Accurate and How Should It Be Used To Improve Reservoir Stimulation,” by O.A. Ishteiwy, SPE, M. Jaboob, and G. Turk, BP; S. Dwi-Kurniadi, SPE, Schlumberger; A. Al-Shueili, SPE, A. Al-Manji, and P. Smith, BP, prepared for the 2018 SPE International Hydraulic Fracturing Technology Conference and Exhibition, Muscat, Oman, 16–18 October. The paper has not been peer reviewed. The use of diagnostic fracture injection tests (DFITs) for prefracture investigation has become routine in the oil field, particularly for understanding reservoir properties and subsequently optimizing hydraulic-fracture design. A key component of an effective DFIT is an after-closure analysis (ACA) to assess the transmissibility of the formation and allow for effective design. This paper describes a DFIT-analysis program and the suitability of the results from ACAs for use in hydraulic-fracture design. Introduction The Khazzan field is being developed currently and includes multiple gas-bearing formations. The primary development reservoir is the Barik sandstone, which is characterized by permeabilities on the order of 0.1 to 1 md. An additional reservoir under development is the Amin formation, which lies deeper than the Barik and is perhaps more unconventional in nature, with estimated permeabilities an order of magnitude lower than the Barik formation. Both reservoirs require hydraulic fracturing to produce at economically attractive rates and, as such, carry the same sort of challenges to reservoir understanding inherent to all unconventional plays. This was recognized in advance of the appraisal program, and an approach was taken to address these challenges in a more-holistic fashion, encompassing a full suite of data gathering, including surveillance and well testing. One of the key tools used was DFIT along with associated ACA of the decline to determine reservoir properties. During the appraisal phase, significant rigor was aimed at ensuring high-quality data would be recorded and that an appropriate amount of time would be allocated to monitoring pressure declines to enable valid interpretations. This resulted in the ability to draw a good correlation between data gathered from the ACA operations and data collected from post-fracturing well-test data. Methods and Process Stimulation and Testing Sequence. The approach taken to stimulate and test the wells in Khazzan was to use a dedicated well-test unit. The overall sequence was as follows: Rig up well-test package Displace kill fluid and clean out with coiled tubing Perforate the target interval Rig up a tree-saver Perform DFIT and monitor pressure decline Perform main fracturing Establish post-main-fracturing-treatment pressure-decline period for fracture closure Rig down the tree-saver Clean out underdisplaced proppant with coiled tubing Flow the well back for cleanup and testing Perform a drift run with slickline to confirm hold-up depth Rig down equipment and handover well to operations
- Asia > Middle East > Oman > Muscat Governorate > Muscat (0.25)
- Asia > Middle East > Oman > Central Oman (0.25)
- Asia > Middle East > Oman > Ad Dhahirah Governorate (0.25)
- Asia > Middle East > Oman > Central Oman > Barik Formation (0.99)
- Asia > Middle East > Oman > Ad Dhahirah Governorate > Arabian Basin > Rub' al-Khali Basin > Block 61 EPSA > Block 61 > Khazzan-Makarem Field > Khazzan Field > Miqrat Formation (0.99)
- Asia > Middle East > Oman > Ad Dhahirah Governorate > Arabian Basin > Rub' al-Khali Basin > Block 61 EPSA > Block 61 > Khazzan-Makarem Field > Khazzan Field > Buah Formation (0.99)
- (6 more...)
This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 192053, “Maximizing Value of an Appraisal DST: Recording a 10,000-Hour Buildup in an Abandoned Well Using Wireless Downhole Gauges,” by Stuart Walters, SPE, Gavin Ward, and Mike Cullingford, SPE, Chevron, prepared for the 2018 SPE Asia Pacific Oil and Gas Conference and Exhibition, Brisbane, Australia, 23–25 October. The paper has not been peer reviewed. This paper describes the acquisition and interpretation of long-term pressure-buildup data in a plugged and abandoned deepwater appraisal well. To accomplish the test objectives at an acceptable cost, a novel combination of well testing, wireless-gauge technology, and material-balance techniques was used to allow the collection and interpretation of reservoir-pressure data over a planned period of 6 to 15 months following the well test. The final buildup duration was 428 days (14 months). Introduction Three interpretation methods of increasing complexity were used to provide insights into the reservoir. First, material balance was used to produce an estimate of the minimum connected reservoir volume. The advantage of material balance is that it requires very few input assumptions and produces a high-confidence result. Second, analytical models in commercial pressure-transient-analysis software were used to investigate near-wellbore properties and distances to boundaries. Finally, finite-difference-simulation models were used to investigate reservoir properties and heterogeneity throughout the entire tested volume. With increasing model complexity came additional insights into the reservoir properties and architecture but reduced solution uniqueness. A key complication for the interpretation of the recorded pressure data was the potential for gauge drift. This was incorporated into the uncertainty range used in all three interpretation methods. Well-Test Design Analysis of conventional well-test designs (with varying flow rates and buildup periods) showed that the cost of resolving the key uncertainties exceeded the value of information significantly. To justify the appraisal, a way was needed to extend either the flow period or the buildup period without a rig on station and with the well left in a permanently abandoned state. To meet this objective, the potential of wireless-gauge technology to extend the buildup length was evaluated. Two competing wireless technologies were available, acoustic and electromagnetic transmission, both occurring up the tubing/casing. The key differentiator was that acoustic transmission required that cables be run through any cement plugs, which violated the barrier standards for abandoned wells. Accordingly, electromagnetic transmission was selected for the final system. The post-abandonment well concept is shown in Fig. 1. Of note is that the wellhead was not recovered and the top of the 20- and 36-in. casings have not been severed. One critical design feature was the use of redundant gauges (four), repeaters (four), and subsea modems (four) to ensure no single point of failure existed within the wireless system. This also resulted in a narrowing of the gauge-drift and accuracy-uncertainty range as the response of individual gauges was thought to be independently and identically distributed.