ALBERT

Description: We enter the new year together as an industry and as SPE members, but also as individuals who have traveled on varying roads and experienced personal detours. While this also can be said of years past, 2020 brought with it unanticipated upheavals within the oil and gas industry, global societies, and our personal and professional lives (and livelihoods). Outlooks for the coming year depend in large part on your own worldview: Are you generally an optimist or a pessimist? An optimist believes that problems are temporary and will get better. A pessimist is convinced that the problem is here to stay and can only get worse. Optimists go into new situations with high expectations, while pessimists hang onto low expectations to prepare for negative outcomes. Do you see the glass as half full or half empty? The objective truth is that the water in the glass is at the halfway mark. The rest is up to our interpretation of that truth. The truth itself doesn’t change, but how we interpret it can have a huge effect on our actions. In his column this month, SPE President Tom Blasingame, a self-described optimist, wrote, “It’s time to look at the horizon” and “open our sails.” The metaphor describes taking action after the worst of a storm has passed or is passing and to make adjustments to get back on course. None of us are continuously optimistic or pessimistic. Life happens and moves the needle in either direction, but opening our sails may help us recover our optimism when it falters. Tapping into our resources is critical to our worldview. Am I consistently a cheerleader with a rosy view, no matter what happens? Certainly not, but I tap into my resources and mightily try to move the needle back toward optimism. (Warning: Success in doing so may not be immediate.) Your personal resources vary, and this is a reminder that SPE is one of those resources. This list is intended to serve as an “SPE Guide to Optimism.” These offerings can help to move the needle for you. Best wishes for 2021 from the JPT editorial team.

Description: This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 202246, “Wheatstone: What We Have Learned in Early Production Life,” by John Pescod, SPE, Paul Connell, SPE, and Zhi Xia, Chevron, et al., prepared for the 2020 SPE Asia Pacific Oil and Gas Conference and Exhibition, originally scheduled to be held in Perth, Australia, 20–22 October. The paper has not been peer reviewed. Wheatstone and Iago gas fields, part of the larger Wheatstone project, commenced production in June 2017. The foundation subsea system includes nine Wheatstone and Iago development wells tied back to a central Wheatstone platform (WP) for processing. Hydrocarbons then flow through an export pipeline to an onshore processing facility that includes two liquefied-natural-gas (LNG) trains and a domestic gas facility. The complete paper highlights some of the key learnings in well and reservoir surveillance analysis and optimization (SA&O) developed using data from early production. Asset Overview Chevron Australia’s Wheatstone project is in the North West Shelf region offshore Australia (Fig. 1). Two gas fields, Wheatstone and Iago (along with a field operated by a different company), currently tie into the WP in the Northern Carnarvon Basin. These two gas fields are in water depths between 150 and 400 m. The platform processes gas and condensate through dehydration and compression facilities before export by a 220-km, 44-in., trunkline to two 4.45-million-tonnes/year LNG trains and a 200 tera-joule/day domestic gas plant. A Wheatstone/Iago subsea system consisting of two main corridors delivers production from north and south of the Wheatstone and Iago fields to the WP. Currently, the subsea system consists of nine subsea foundation development wells, three subsea production manifolds, two subsea 24-in. production flowlines, and two subsea 14-in. utility lines. The nine foundation development wells feed the subsea manifolds at rates of up to 250 MMscf/D. These wells have openhole gravel-pack completions for active sand control and permanent downhole gauges situated approximately 1000-m true vertical depth above the top porosity of multi-Darcy reservoir intervals for pressure and temperature monitoring. All wells deviate between 45 and 60° through the reservoir with stepout lengths of up to 2.5 km. The two subsea 24-in. production flowlines carry production fluids from the subsea manifolds to two separation trains on the WP. Each platform inlet production separator can handle up to 800 MMscf/D. The two 14-in. utility flowlines installed to the subsea manifolds allow routing of a single well to the platform multiuse header, which can direct flow into the multiuse separator (MUS) or other production separators at a rate of 250 MMscf/D.

Description: The carbon-free future should not be confused with a utopian future. A zero-carbon world will include the difficult realities experienced in Texas in February 2021. As shown in a graph of US EIA data, during the recent extreme cold event in Texas, wind and solar could not hold flat compared with their baseline the week before (4–8 February). Coal and nuclear remained mostly steady, while natural-gas producers ramped up supplies delivered to power plants by a factor of 4, helping people who were struggling to heat their homes. Natural gas may not receive well-deserved recognition from some quarters, and blackouts and loss of life still occurred, but our industry stepped up when people needed us most. Texas generates 25% of the wind power in the US and has more solar potential than 18 northern states combined, yet wind and solar simply failed when called upon. As the world attempts to go carbon-free, this reviewer hopes that more consumers will see the difference between results and public-relations promises. It will take a legitimate technological step-change before an unsubsidized renewable energy source is capable of replacing reliable fossil fuels. Imagine if Sir Isaac Newton, with all his brilliance, had tried to be the first man to land on the moon. In 1720, the cumulative knowledge did not exist to allow that to happen, and, if he had tried, he could have spent the entire British treasury and still failed. By standing upon the shoulders of giants like Newton, others were able to reach the moon 250 years later. Step-change technological breakthroughs happen when their time has come, not when mandated by political pressure. Until you hear that commercial fusion reactors are online or that low-cost, grid-scale electricity storage made from commonplace materials can handle a 10-day cold snap or heat wave, there is no need to hang up your pipe wrenches. Fossil fuels will remain the most energy-dense, cost-effective, reliable energy source until an extraordinary breakthrough creates a better alternative. The three papers selected for this feature demonstrate the continued critical role of gas production, and innovation therein, in the necessary daily role of supplying the world’s energy needs. One discusses means of exploiting stranded offshore gas reservoirs; the second details an Eagle Ford cyclic-gas-injection enhanced-oil-recovery effort; and the third focuses on the fracturing interference of multi-well pads in shale gas reservoirs. Reference Wilson, Scott. 2021. “EIA Texas Power Generation Data, February 2021.” Recommended additional reading at OnePetro: www.onepetro.org. SPE 200468 Hydraulic-Fracturing Test Site Phase-2 Enhanced-Oil-Recovery Pilot: Huff ’n’ Puff Pilot in the Permian Midland Basin by Shadi Salahshoor, Gas Technology Institute, et al. SPE 202448 Unconventional Gas Development in Queensland, Australia: How Well Does It Align With the Golden Rules of Gas? by Katherine Witt, The University of Queensland, et al. SPE 203208 Underbalanced Well Intervention to Re-Enter a Dead Well Changed the Future Dynamics of the Largest Gas Field in Pakistan—A Successful Pilot Project by Qasim Ashraf, Weatherford, et al.

Description: In some respects, the prospect of returning to some degree of normality is evident on the horizon. However, climate and the future of energy show little sign of a return to prepandemic normalcy. The future of our energy system is being transformed, and oil and gas are crucial for energy stability as well as the transformation. One of the miracles over the past year has been the accumulated knowledge around the human genome and application of this science to the rapid development of efficacious vaccines. As within oil and gas, humans can rise to the challenge to solve complex problems when identified. This is playing out as we see societal drivers around climate change and net-zero carbon emissions. Over the past year, SPE produced 11 events focused on the energy transition and continued the development of the Gaia Sustainability Program initiated by the SPE Health, Safety, Environment, and Sustainability (HSES) discipline. It is now a thriving community of SPE members across all disciplines committed to enabling and empowering all members and other interested parties who wish to engage in the alignment of the future of energy with sustainable development. An on-demand library of Gaia Talks and other resources has been built using the strategic programming framework (www.spe.org/en/gaia). Advances in our understanding and application of technology, and the development of those who can use it to better the world, are highlighted in the selections made for this month’s Technology Focus—genome sequencing of invasive species, technology to identify fatigue, and development of human capital for the industry in Kazakhstan. We must not forget the key element in any strategic improvement of performance: the human being. This starts with developing human capital at the university level. The industry is also working on progressing our understanding and application of human factors and human performance. As mentioned in the October 2020 JPT, the oil and gas industry has formed the Human Performance Oil and Gas (HPOG) alliance modeled after the very successful Dropped Objects Prevention Scheme program. The return to a more-normal life also means that our traditional conference model can reengage membership. Face-to-face meetings accelerate networking and the transfer of knowledge, which is core to the SPE mission. Events focusing on HSES this year include a planned in-person gathering the first week of November: HSES Focus on the Future—Responding to Changes and How the HSES Function Will Grow (3–5 November). This event will primarily cover health, environment, and sustainability with one panel on land transportation safety. It is strategically planned for the same week and at the same hotel in Fort Worth, Texas, where the American Institute of Mining, Metallurgical, and Petroleum Engineers will hold its first Joint Congress on Safety (1–3 November). A key element in building strategies within the SPE HSES discipline is the future of the function. Leading the efforts around this will be the newly formed HSES Executive Advisory Committee (EAC). This EAC, led by Fawaz (Fuzzy) Bitar, senior vice president of HSE and carbon at BP and former chair of the International Association of Oil and Gas Producers, includes HSE leadership from various upstream operators and contractors and will help with guidance and direction for SPE HSES Technical Director Annamaria Petrone. The EAC will hold a meeting and participate in plenary panels during the SPE HSES event in November. Recommended additional reading at OnePetro: www.onepetro.org. SPE 202737 6×6 Occupational Health Hazard Risk Rating Matrix: A Useful Tool in the Determination of Risk Levels of Workplace Health Hazards by Bufford Ang, Abu Dhabi National Oil Company, et al. OTC 30840 Self-Certification and Safety Compliance for Robotics Platforms by Osama Farouk Zaki, Heriot-Watt University, et al. SPE 201312 Long-Term, Periodic Aerial Surveys Cost-Effectively Mitigate Methane Emissions by Sri Sridharan, Pioneer Natural Resources, et al.

Description: This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 30644, “Discovery of New Oil Reserves by Combining Production Logging With Openhole-Log Interpretation in Low-Resistivity Pay,” by Xinlei Shi, Peichun Wang, and Jinxiu Xu, CNOOC, et al., prepared for the 2020 Offshore Technology Conference, originally scheduled to be held in Houston, 4–7 May. The paper has not been peer reviewed. Copyright 2020 Offshore Technology Conference. Reproduced by permission. In this paper, the authors examine the evaluation of a low-resistivity-pay siliciclastic reservoir in Bohai Bay, China. A significant amount of irreducible water is bound to the rock surface, dramatically lowering the resistivity of the pay zone. The authors explore a theory that the low resistivity is caused by bound water trapped in clay minerals, using production logging to provide the ground truth of reservoir fluids in the low-resistivity pay and improve the petrophysics model. With the improved model, production predictions were made for offset wells based on their openhole logs. The production histories of these wells are highly consistent with the authors’ predictions. Introduction LD oil field is in the eastern Bohai Sea, China, structurally in the transition zone between the Liaohe depression of the Tanlu fault and the Bozhong depression and at the dip end of the Bodong low uplift extending to the northeast. The main oil reservoirs are developed in the Guantao and Dongying formations. Reservoir depth ranges from approximately 1022.1 to 2585.8 m. Reservoir lithology is mainly sandstone and gravelly sandstone. The porosity distribution range of the Guantao formation is 24 to 30%. Permeability distribution range is 333 to 3333 md belonging to medium-high-porosity and - permeability reservoirs. The porosity distribution range of the Dongying formation is from 6 to 12%, and the permeability distribution range is from 3 to 33 md belonging to medium-low- porosity and -permeability reservoirs.

Description: Flow assurance in subsea oil and gas fields often presents significant challenges. Every field has its own combination of difficulties, and no universal process or system can be used to mitigate these. Detailed knowledge across a broad range of competencies, therefore, is required to find solutions that can minimize the risk of not getting the hydrocarbons safely to the process facilities. Many subsea fields that are being developed today are long tiebacks, taking advantage of existing offshore infrastructure or producing directly to shore. These developments must deal with the long-distance transport of hydrocarbons in deep cold water, commonly increasing the risk of hydrate formation and wax deposition, for example. In addition, large elevation changes from deep water to surface and topographical challenges along the pipeline can create flow-regime effects that can hinder production. The loss of temperature in a long subsea pipeline also creates challenges for fields that produce heavy oil because the oil viscosity in some cases increases dramatically at low temperatures, in addition to effective viscosities increasing because of oil and water emulsions. Other phenomena such as scale deposition, foaming, sand production, erosion, and corrosion must be considered and dealt with as well. Various smart-technology innovations for subsea oil and gas production contribute to reducing the risk of these flow-assurance issues. Some of them are described in this month’s selected SPE papers. A good example is as follows: When wells start to produce water, the operator needs to understand where the water is coming from and quantify volumes in order to start a mitigation program to avoid hydrate formation. This is one of the reasons why subsea multiphase flowmeters have become an essential feature in all new subsea fields. The most common remedy for flow-assurance problems is probably the use of chemical additives. A sensor technology that can directly determine the ratio between produced water and chemicals such as monoethylene glycol has been recently introduced in subsea production systems. This measurement enables the optimization of chemical-injection rates, thereby contributing to significant savings in capital expenditure (reduced design margins) and operational expenditure (reduced overdosage margins). Another effective way to prevent hydrates and wax is to keep the process temperature above critical limits by applying active flowline heating. New technologies for highly reliable and efficient subsea electrically heat-traced flowlines have recently been qualified, industrialized, and installed. Technologies as described here can play an important role in future subsea field developments. The recommended readings for this feature date back further back in time than usual, but are relevant to the theme of this year’s main selections. Recommended additional reading at OnePetro: www.onepetro.org. OTC 29232 Real-Time Subsea Hydrate Management in the World’s Longest Subsea Tieback by Christophe Vielliard, OneSubsea, a Schlumberger Company, et al. OTC 31078 Electrically Heated Trace Flowline on the Ærfugl Project—A Journey From Product Qualification to Offshore Campaign by Guy Mencarelli, Subsea 7, et al. SPE 195784 A New Flow-Assurance Strategy for the Vega Asset: Managing Hydrate and Integrity Risks on a Long Multiphase Flowline of a Norwegian Subsea Asset by Stephan Hatscher, Wintershall Norge, et al.

Description: This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 30732, “Economic Feasibility Study of Several Usage Alternatives for a Stranded Offshore Gas Reservoir,” by Khoi Viet Trinh, SPE, and Rouzbeh G. Moghanloo, SPE, University of Oklahoma, prepared for the 2020 Offshore Technology Conference, originally scheduled to be held in Houston, 4–7 May. The paper has not been peer reviewed. Copyright 2020 Offshore Technology Conference. Reproduced by permission. This paper compares economics of a floating liquefied natural gas (FLNG) project with those of an onshore LNG plant and gas-to-wire (GTW) processes. Sensitivity analyses and tornado charts are used to evaluate the importance of various uncertain parameters associated with FLNG construction and operation. This study will be helpful for future considerations in using FLNG to convert offshore gas reservoirs previously considered stranded into economically viable resources. The results from this economic model can play a key role in the future of the natural gas industry and energy market in West Africa. Assumptions Before presenting different economic scenarios, the following assumptions must be established: * The pipeline will have the correct diameter, pressure rating, and metallurgy to transport produced gas. Only the pipe length will be considered a variable. * Operating expenses (OPEX) of both onshore LNG and FLNG will be the same. Realistically, however, OPEX of FLNG will be different from that of onshore LNG. * A subsidy from the Nigerian government has been obtained for the onshore LNG plant. * The electricity price is assumed to be $0.25/kWh. * An assumed upstream cost of $2/Mscf to cover onshore LNG gas pretreatment is assumed. * The onshore LNG plant and FLNG will have the same lifespan. However, in reality, availability of FLNG can be lower than that of onshore LNG. Pricing Models FNLG. Because of the relative recency of FNLG, few pricing models have been readily available. For the complete paper, Shell’s Prelude project is the basis for pricing of FLNG. Prelude costs averaged out to approximately $14 billion, which will be used as the cost of the facility for the FLNG scenario in the economic analysis.

Description: This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 201694, “Interwell Fracturing Interference Evaluation of Multiwell Pads in Shale Gas Reservoirs: A Case Study in WY Basin,” by Youwei He, SPE, Jianchun Guo, SPE, and Yong Tang, Southwest Petroleum University, et al., prepared for the 2020 SPE Annual Technical Conference and Exhibition, originally scheduled to be held in Denver, Colorado, 5–7 October. The paper has not been peer reviewed. The paper aims to determine the mechanisms of fracturing interference for multiwell pads in shale gas reservoirs and evaluate the effect of interwell fracturing interference on production. Field data of 56 shale gas wells in the WY Basin are applied to calculate the ratio of affected wells to newly fractured wells and understand its influence on gas production. The main controlling factors of fracturing interference are determined, and the interwell fracturing interacting types are presented. Production recovery potential for affected wells is analyzed, and suggestions for mitigating fracturing interference are proposed. Interwell Fracturing Interference Evaluation The WY shale play is in the southwest region of the Sichuan Basin, where shale gas reserves in the Wufeng-Longmaxi formation are estimated to be the highest in China. The reservoir has produced hydrocarbons since 2016. Infill well drilling and massive hydraulic fracturing operations have been applied in the basin. Each well pad usually is composed of six to eight multifractured horizontal wells (MFHWs). Well spacing within one pad, or the distance between adjacent well pads, is so small that fracture interference can occur easily between infill wells and parent wells. Fig. 1 shows the number of wells affected by in-fill well fracturing from 2016 to 2019 in the basin. As the number of newly drilled wells increased between 2017 and 2019, the number of wells affected by hydraulic fracturing has greatly increased. The number of wells experiencing fracturing interaction has reached 65 in the last 4 years at the time of writing.

Description: This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 200427, “Evaluation of Eagle Ford Cyclic Gas Injection EOR: Field Results and Economics,” by George Grinestaff, SPE, Chris Barden, and Jeff Miller, SPE, Shale IOR, prepared for the 2020 SPE Improved Oil Recovery Conference, originally scheduled to be held in Tulsa, 18–22 April. The paper has not been peer reviewed. Cyclic-gas-injection-based enhanced oil recovery (CGEOR) in the Eagle Ford was begun in late 2012 by EOG Resources and, at the time of writing, has expanded to more than 30 leases by six operators (266 wells). An extensive EOR evaluation was initiated to analyze the results recorded in these leases. The authors write that CGEOR in Eagle Ford volatile oil can yield substantial increases in estimated ultimate recovery (EUR) with robust economics, depending on compressor use and field life. Introduction Eagle Ford Source Rock and Reservoir. The Eagle Ford shale represents some of the world’s richest source rocks. The Upper Cretaceous seafloor received abundant organic debris and preserved it in an anoxic environment. The low permeability of the shale and limestone helped generate hydrocarbons when pore pressure exceeded overburden pressure. The resulting natural fractures provided a means to expel oil, much of it migrating into the overlying Austin Chalk and Tertiary sandstones. The primary target area for produced-gas injection EOR is currently in the volatile oil window between 9,000 and 11,000 ft true vertical depth, which yields oil API gravity of greater than 40. Initial gas/oil ratio (GOR) typically ranges from 1,000 to 3,000 scf/bbl. Eagle Ford EOR History. The first large-scale CGEOR project was implemented in October 2014. Rapid development has occurred since then, but, in the complete paper, the authors present the first commercial EOR projects by EOG Resources because these have the longest CGEOR production history. Recent projects show more-efficient startup, cycling, and higher optimization of gas injection. Therefore, the analysis of EOR in this paper takes a conservative approach of using the first projects because they appear to have lower EOR recovery but more production history. Evaluation Methodology Unconventional EOR Work Flow. Analysis of CGEOR production and results has been completed using production history and reservoir simulation to provide a rigorous evaluation. The authors use a 14-component fracture element model with a very fine grid to predict well GOR, EUR, and reservoir behavior for the compositional process. The element model is then scaled up to mimic the average well for a given pad or lease, and then cycle operations are developed based on CGEOR simulation runs and criteria. Unconventional CGEOR provides a direct response after the first cycle of gas injection; however, the base depletion profile also is important for understanding economics for increased oil production or incremental EOR. A history match of the base depletion is first completed to match an average well at the pad level (approximately one 640-acre section with 10 to 14 wells). The element is then scaled up based on well completion, stimulated rock volume, and EUR for the base depletion.

Description: Nearly three-quarters (71%) of senior oil and gas professionals have sharpened their focus on digitalization over the past year, according to a 2021 survey by DNV (DNV Outlook). The pandemic has not only increased attention on how digital solutions can make organizations more adaptable and cost efficient, it has also forced companies to discard the normal rules and become more open to change. While data collaboration, cloud-based applications, and remote surveillance top the investment priorities for the year ahead, a growing number of respondents (7%) see additive manufacturing (AM)—the industry equivalent of 3D printing—on their spending list. As an emerging technology, AM uses 3D model data to fabricate parts, enabling, among other benefits, significant cost and time savings in contrast to many traditional manufacturing methods, where the final parts are machined out of a pre-made form. Its purpose is to alleviate and avoid long, expensive production shutdowns and reduce supply chain carbon footprints. Building trust in “printed” parts is key to unlocking this potential. Rapid, Reliable Reproduction The global AM market is expected to reach $350 billion by 2035 (DailyAlts 2021). The technology also has the potential to be enhanced by—or in the other direction, augment—other digital solutions, given it is based on a 3D file. Though accelerating at a slower rate compared to the aerospace and automotive industries, there is increased pressure to shorten the development cycle of components for the oil, gas, and renewables sectors and perform rapid proto-typing and testing of new, more sustain-able concepts. New business models will be developed and a new way of thinking adopted by design engineers to fully utilize its potential (DNV Technology Outlook 2030). To support the digital transformation of the energy industry, DNV, which has been actively investigating the potential of AM since 2014, has unveiled a new service specification document to ensure AM products, assets, and systems are safe, economical, and efficient. DNVGL-SE-0568 “Qualification of Additive Manufacturing Service Providers, Manufacturers, and Parts,” is part of a portfolio of six different AM-related standards and recommended practices (Fig. 1).

Description: Leading into the third quarter of this year, I am honored to be able to highlight and share three impactful SPE papers that demonstrate integration at its best. In reviewing the papers, five main technical themes emerged. These include * Machine learning and artificial intelligence as applied to formation evaluation * Production analysis methodologies and their effect on understanding rock characterization and behavior * Subsurface characterization primarily focused on rock typing and permeability * Tool advancements (openhole, cased-hole, or laboratory-based tools) * Subsurface-to-production integration across subdisciplines (e.g., geology, geochemistry, petrophysics, and engineering) The latter is the common thread between the three papers recommended and discussed here. In this new decade, the prevalence of integration is at the forefront of the scientific community. Every discipline, scientist, or company has a way in which they define the term “integration.” Regardless of how you define the effort that links disciplines quantitatively, the importance of constraining subsurface characterization to link it to production results and drive toward a predictive model is a critical accomplishment for our industry. As such, I’d like to highlight three papers in this feature (OTC 30644, SPE 201417, and SPE 202683) and the knowledge and workflow applications they define and demonstrate. Sharing these integrated work flows with the community aids in teaching and leads to best-practice components of integrative studies. These efforts also share and demonstrate how to bridge the gap between in-situ characterization and wellhead performance prediction and results—in other words, the static-to-dynamic link between rock and fluid properties as quantified and how they will inevitably produce hydrocarbon through the rock and fluid interactions. Recommended additional reading at OnePetro: www.onepetro.org. SPE 201334 Combined Experimental and Well-Log Evaluation of Anisotropic Mechanical Properties of Shales: An Application to Wellbore Stability in the Bakken Formation by Saeed Rafieepour, The University of Tulsa, et al. SPE 201486 A New Safe and Cost-Effective Approach to Large-Scale Formation Testing by Fluid Injection on a Wireline Formation Tester by Christopher Michael Jones, Halliburton, et al. SPE 201735 Integrated Reservoir Characterization With Spectroscopy, Dielectric, and Nuclear Magnetic Resonance T1-T2 Maps in a Freshwater Environment: Case Studies From Alaska by ZhanGuo Shi, Schlumberger, et al.

Description: This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 199003, “Subsea Systems Innovations and the Use of State-of-the-Art Subsea Technologies Help the Flow Assurance of Heavy-Oil Production in Ultradeep Water,” by Carlos Alberto Pedroso, SPE, Geraldo Rosa, SPE, and Priscilla Borges, Enauta Energia, et al., prepared for the 2020 SPE Latin American and Caribbean Petroleum Engineering Conference, Bogota, Colombia, 17–19 March. The paper has not been peer reviewed. Flow assurance in ultradeep water is a major issue for production. The Atlanta field, which produces heavy oil in ultradeep water, is a project combining several challenges: hydrates formation, emulsion tendency, scale formation, foaming, and high viscosities. The complete paper discusses innovations and technologies applied to make Atlanta a successful case of ultradeepwater heavy-oil production. Introduction Discovered in 2001, the Atlanta field is in the presalt exclusion area in the north of the Santos Basin, 185 km southeast of Rio de Janeiro, at a water depth of 1550 m. The postsalt reservoir is contained in the Eocene interval and is characterized by high net-to-gross sands (82–94%) with a high average porosity of 36% and high permeabilities in the range of 4–6 Darcies. These excellent rock properties, however, are offset by the poor quality of the Atlanta crude, which is heavy (14 °API), viscous (228 cp at reservoir conditions), and highly acidic. The development of the field took place in two phases, an early production system (EPS) and a definitive production system (DPS). First oil occurred in May 2018. The EPS is expected to last from 4 to 5 years, producing from three horizontal wells to a floating production, storage, and offloading vessel (FPSO) with a processing capacity of 30,000 BOPD. The DPS will consist of 12 horizontal producers tied to a larger-capacity FPSO.

Description: This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 201272, “Lessons Learned in Developing Human Capital for the Oil and Gas Industry in Kazakhstan,” by Zhassulan Dairov, SPE, KIMEP University and Satbayev University; Murat Syzdykov, SPE, Satbayev University; and Jennifer Miskimins, SPE, Colorado School of Mines, prepared for the 2020 SPE Annual Technical Conference and Exhibition, originally scheduled to be held in Denver, Colorado, 5–7 October. The paper has not been peer reviewed. The World Economic Forum’s (WEF) Human Capital initiative has been implemented at Satbayev University (SU), Almaty, Kazakhstan, during the last 2 years. Participating in this effort are Chevron, Eni, Shell, and the Colorado School of Mines (Mines). The complete paper assesses the effectiveness of project components, such as industry guest lectures, summer internships, and program improvement, and provides lessons learned for human-resource-development initiatives. Introduction In most cases, the industry/ university alliance is intermittent, short-term, and underdeveloped. The engagement of three stakeholders, such as government, industry, and the university, is the most-successful model of joint performance. This approach allows all participants to create competitive advantages in the achievement of common objectives. Moreover, the role of governmental agencies is critical alongside professional organizations in facilitating such cooperation.

Description: It’s a problem as old as the industry itself. The initial oil rush in the late 1800s spread like wildfire through Pennsylvania, and by 1891 the state’s annual crude output had hit 31 million barrels, or 58% of the nation’s total oil production for that year. However, by the turn of the century the bloom was off the rose. Pennsylvania’s once-robust oil allure had been eclipsed by finds in Texas, California, and Oklahoma, each spawning its own regional oil booms. So why the history lesson? Because it’s important to understand the potential volume and impact of orphan wells in the US. In the infancy of the industry, plugging-and-abandonment (P&A) techniques were crude at best, if anyone even went to the trouble. Worse still was the overall record keeping at the time. With oil booms around the country setting off races to harness as much black gold as possible, wells were being drilled at breakneck pace. Once these earliest wells were tapped of their commercial usefulness, operators moved on to the next. There was little-to-no over-sight. No regulations. No standards. The result? Thousands, if not more, of scattered, undocumented wells. “Back in the day, you have people drilling wells, and nobody’s keeping track of where the wells are drilled and who owns the wells,” said Daniel Raimi, fellow with Resource for the Future, an independent institution that conducts environmental, energy, and natural resource research. “The government’s not keeping track and has little to no regulation in place to ensure that operators safely decommission their assets at the end of their lives. As a result, you have wells that maybe produce for a couple of years, and then the owners walk away. Multiply that by a couple of hundred thousand and now you’ve got a problem.” Today, there is plenty of oversight and regulation for the industry to leave abandoned wells in much better shape than those earliest probes. However, orphan wells are still a problem. To paint the clearest picture, it would be prudent to define what an orphan well is. This is where we run into our first problem. Definitions can vary wildly from state to state and organization to organization. Some lump all abandoned, unplugged wells into their counts as orphan wells. Others count all idle wells. However, for the sake of clarity we will define orphan wells as those nonproducing, idle wells whose ownership is unknown. By that definition it is safe to say that many of the nation’s earliest wells fit that criteria. In more modern times, orphans result from idle wells whose owner goes belly-up prior to any P&A work. In most of these cases, bonds are employed to help offset the cost of plugging these wells. However, while they vary state to state, most bonding minimums do not cover the full cost of abandonment and remediation, if needed. According to the US Environmental Protection Agency, there are about 2 million unplugged, abandoned oil and gas wells scattered across the US. Other experts place the number higher; some believe it is lower. Some researchers believe as many as half of those could be orphan wells. A survey by the Interstate Oil and Gas Compact Commission in 2018 put the range of orphaned and idle wells at around 560,000 to 1.1 million. Again, abandoned doesn’t always mean orphaned. One fact that can be extrapolated from the data gathered to date is that no one knows for sure just how many orphaned wells are out there. But that is changing.

Description: Forecasts for oil demand are looking up, according to OPEC and the International Energy Agency as of mid-July. Will the optimistic views prove to be on target? We have learned how the market can shift or wildly careen, both historically and in the very recent past. Looking at the forecasts, which reflect a consensus of sorts, is encouraging for producers. OPEC’s monthly report of 15 July projected global oil demand to reach nearly 100 million B/D next year, a level similar to pre-pandemic in 2019. The 2021 oil demand growth remains unchanged at 5.95 million B/D, or approximately 6.6%. Led by demand growth in the US, China, and India, a 3.4% increase is expected in 2022 to 99.86 million B/D and would average more than 100 million B/D in the second half of the year. “Solid expectations exist for global economic growth in 2022,” OPEC said. “These include improved containment of COVID-19, particularly in emerging and developing countries, which are forecast to spur oil demand to reach pre-pandemic levels in 2022.” If the actual recovery tracks with these predictions, OPEC can dial back further its record-level supply cuts made in 2020. The IEA points to the growth expected in global electricity demand as spurring fossil-fuel demand, including oil, coal, and natural gas. After falling by around 1% in 2020, electricity demand growth may approach 5% in 2021 and 4% in 2022. The Asia Pacific region will account for the majority of the increases. China, the world’s largest consumer of electricity, leads the tally, accounting for more than 50% of the 2022 growth. India, the third largest, will account for 9% of the global electricity growth. Renewables are expected to be able to serve around half of the projected growth in global demand in 2021 and 2022. IEA wrote, “Renewable electricity generation continues to grow strongly—but cannot keep up with increasing demand. After expanding by 7% in 2020, electricity generation from renewables is forecast to increase by 8% in 2021 and by more than 6% in 2022.” Fossil fuel-based electricity is set to cover 45% of additional demand in 2021 and 40% in 2022. After declining by 4.6% in 2020, coal-fired electricity generation will increase by nearly 5% in 2021, exceeding pre-pandemic levels. In 2022, it will grow another 3% and could reach an all-time high. Natural gas-generated electricity lags coal because it is less commonly used in the Asia Pacific and competes with renewables in the US and Europe. It is expected to increase globally by 1% in 2021 and by nearly 2% in 2022 after declining by 2% in 2020. The US Energy Information Administration published a global financial review last month of 91 oil and gas companies, most headquartered in the US, in the first quarter 2021. It indicated that companies are implementing their plans announced over the past year to reduce capital expenditures to pay down debt. Capital expenditure in 1Q2021 was reported as $48 billion, 28% lower than in 1Q2020 and the second- lowest amount for any quarter since 2016. Cash from operations in Q1 this year totaled $79 billion, 19% higher than in 1Q2020; about 76% of companies had positive free cash flow. Overall, the companies decreased debt by $16 billion in 1Q2021, and the long-term debt-to-equity ratio decreased to 54%.

Description: Equinor could play a critical role in Brazil’s drive to boost its economy by opening up its gas markets. The Norwegian oil company operates two huge deepwater blocks with enough gas to lower prices in the country where big users pay some of the highest prices in the world. The development plan for one of those blocks, BM-C-33 in the Campos Basin, would deliver an average of 14 million m3/d of gas—about 15% of the country’s gas demand on a high-consumption day, which is about 92 million m3/d, based on data from Rystad. A second project in the heart of the presalt, Bacalhau, could become a model for how an international oil company can market gas successfully in the country’s richest oil play, the Santos Basin presalt. The gas potential in that play is also huge; the gas/oil ratio is high compared with other Brazilian fields but has largely been untapped. So far, Equinor and its partners in the projects have not committed to developing gas on either lease, but Equinor appears to be seriously considering doing so. The big question it needs to answer is what the gas market there will look like in a year or so. Brazil has set out to promote domestic gas supplies by ending Petrobras’ virtual monopoly in the pipeline business in favor of a less-regulated, competitive gas market. Equinor avoided gas sales at Bacalhau with an $8 billion Phase 1 plan that will use the popular practice of reinjecting produced gas. Gas reinjection maintains reservoir pressure and allows the development to comply with Brazil’s ban on routine flaring. Brazil’s energy regulator, ANP, said that when Equinor develops a plan for its second phase of development, the company needs to con-sider gas production. The role of gas market pioneer is the latest technical challenge taken on by Equinor in Brazil. Previously, it became the operator of an offshore heavy-oil field—Perigrino—and an aging giant—Roncador—both in the Campos Basin. While the Norwegian company has not promised to take on that role, it has a huge incentive to do so as the operator of Block BM-C-33, where most of the reserves are in the form of gas. The resource is estimated at 3 Tcf of gas and 700 million bbl of condensate, according to Offshore Technology. Equinor and its partners Repsol and Petrobras have developed a plan that would move the liquids by tanker from the platform, which is in water as deep as 2900 m, and build a pipeline about 200 km from there to shore. When asked about the status of the project, Geir Tungesvik, senior vice president for project development at Equinor, said the company is working to “improve the business case.” A Potential Case Study Tungesvik’s bland description fails to reflect the risks and uncertainties faced by those trying to put together offshore gas marketing plans in Brazil. If Equinor and its partners go forward with their plan to monetize that massive gas reserve, the result is likely to be a case study for those who follow. It could either be a model for successful development or a cautionary tale.

Description: Background A new extended-release (ER) scale-inhibitor technology showing significantly increased lifetimes has been applied in the Permian Basin. Tomson Technologies and Group 2 Technologies, in partnership with Occidental Petroleum (Oxy), implemented a scale-squeeze program for this carrier system. It allows for fewer squeeze treatments, which results in lower chemical usage, decreased plugging risk, and reduced environmental impact. Squeeze programs are an effective field treatment strategy to prevent scale formation in wells for extended periods of time. However, in some cases, squeeze lifetimes can be short, leading to frequent re-squeezing and production decreases, lowering overall economic recoveries. The ER phosphonate-based chemistry (SI1313) was used in selected wells where incumbent (previous chemical provider) treatment lifetimes were shorter than expected. The incumbent squeeze volumes and additives were used, and the scale-inhibitor (SI) chemistry was replaced with SI1313 to obtain directly comparable results. The wells selected are vertical wells, with predominantly carbonate mineralogy and 14–18% porosity and 9–16 mD permeability. Bottomhole temperature is 105°F (40°C). These wells are under continuous CO2 flooding operations, and the scales of interest are calcium carbonate and calcium sulfate predominantly. The selected wells were targeted to have a good squeeze history for comparison and stable water production. Pre-Job Validation Work Coreflood laboratory experiments were performed to simulate the adsorption and desorption under these specific Oxy Permian conditions. The coreflood showed over 10,000 pore volume (PV) of flow with inhibitor concentration remaining above the minimum effective concentration (MEC) during the entire run. Once greater than two times incumbent performance was reached, the coreflood was stopped, although the return concentration was still above MEC. For reference, corefloods with incumbent phosphonate chemistry under the same conditions usually drop below MEC around approximately 3,000–5,000 PVs. The adsorption of SI1313 to core material was measured during the coreflood experiment and the results show 12.5 mg of inhibitor adsorbed per gram of core material. As a comparison, a typical incumbent phosphonate scale inhibitor adsorbs 1–2 mg of inhibitor per gram of core material. This increase in adsorption is considered a large improvement over traditional chemistry. The carrier platform’s superior adsorption, when combined with controlled desorption, is the basis for extending the lifetimes of scale- inhibitor treatments. The corefloods results validate the ER characteristics expected from SI1313 and allowed for field squeezes to be conducted. Field Application Group 2 Technologies provided SI1313 to be squeezed for Oxy in January 2020, into five vertical conventional wells. The selected wells are in one area where CO2 flooding is in place and there is risk of calcium carbonate (CaCO3) and calcium sulfate (CaSO4) scaling. These wells have had many scale squeezes performed on them, yielding an excellent data set to compare against. The goal of this trial was to show significant lifetime extension compared to previous incumbent squeeze lifetimes.

Description: This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 203350, “How Technology Can Support Tackling Drivers’ Fatigue: Case From Petroleum Development Oman,” by Demir Hadzic and Hamed Al Esry, Petroleum Development Oman, and David Marsh, Sheida International, prepared for the 2020 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, held virtually 9–12 November. The paper has not been peer reviewed. Petroleum Development Oman operates in harsh environments over which their drivers cover more than 320 million km annually. Driver fatigue is one of the leading causes of motor vehicle incidents (MVIs) associated with operations. The objective of the complete paper is to understand further how technology can support the prevention of driver fatigue and to explore driver beliefs related to fatigue and the technology designed to assist in fatigue avoidance. This study helped the operator’s safety specialists understand driver fatigue and develop mechanisms to prevent it. Introduction Previous research has found that motor vehicle crash fatalities in the oil and gas industry are up to 8.5 times more com-mon than in other occupations. A qualitative study by the operator indicated that participants commonly perceived fatigue as a main factor in MVIs. However, understanding of the nature and role of fatigue in MVIs was revealed to be relatively limited. Among the driver group interviewed, a common view existed that the responsibility for managing driver fatigue lay with the employer and not with drivers. In addition, among the driver group, there appeared to be little understanding of the effects that lifestyle outside of work has on driver fatigue. The pilot study showed that driver fatigue occurred once every three journeys on average, whereas driver distractions could occur more than four times in a single journey. Equipment and Processes Technology used in the study consists of in-cabin hardware units, analytical software integration with in-vehicle monitoring systems (IVMS), and participation of a monitoring team. In addition, event verification is performed by human monitors and feedback. Driver fatigue is part of a comprehensive integrated journey-management system developed by the operator, including standard operating procedures with regard to monitoring and event classification, verification, and response.

Description: This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 30656, “Decommissioning of Subsea Structures in Brazil: Effect of Invasive Species and Genome Sequence of the Azooxanthellate Coral Tubastraea sp.,” by João Humberto Guandalini Batista, SPE, Repsol; Mauro Rebelo, Universidade Federal do Rio de Janeiro; and Giordano Soares-Souza, SENAI CETIQT, prepared for the 2020 Offshore Technology Conference, originally scheduled to be held in Houston, 4–7 May. The paper has not been peer reviewed. Copyright 2020 Offshore Technology Conference. Reproduced by permission. Decommissioning of offshore assets in Brazil is subject to high levels of uncertainty because of Tubastraea, an invasive species of sun coral. This species has a high capacity for dispersion and recruitment and has been associated with the replacement of native species in rocky shores, exerting a serious effect on native biodiversity. The complete paper explores the biology of the invasive species, aiming to identify methods to eliminate or diminish its spread. The authors write that data generated in this study will foster the development of effective technologies in coral-species management, whether species are invasive or threatened. Introduction Originally from the Coral Triangle in the Pacific Ocean—a highly diverse region with hundreds of coral species—Tubastraea was first observed in the Campos Basin in the 1980s. Tubastraea sp. have high fecundity and growth rates with the ability to reproduce asexually, establishing very dense populations. This fast reproduction allows larvae to outcompete native species in both natural and artificial substrates in the sea. Sun coral is extremely resistant to environmental change. It has been found in shallow waters, sometimes exposed to air, showing tolerance even to short periods of desiccation. Recently, new species have been identified in Brazilian waters, heightening concern over the proliferation of sun coral. In the past, the common understanding was that subspecies coccinea and tagusensis were those found in Brazilian waters. However, recent studies dedicated to the research of the Tubastraea genus raised suspicion of the presence of diaphana and aurea, with the possible occurrence of hybrids as well. The preference of Tubastraea is to live in structures that are static or mostly motionless, such as production platforms, subsea structures, and drilling rigs. This trait has made sun coral a major challenge for the local oil and gas industry. While in the Campos Basin, the main objective is to decrease dispersion of already bioencrusted production units and subsea structures, in the Santos Basin, the goal is to avoid colonization in structures in operation or those scheduled to be installed soon. To further complicate matters, drilling and intervention vessels and rigs are contracted to service both basins. They work in dynamic-positioning mode, stationary around the production units and subsea structures for lengths of time that exceed the reproduction cycle time of the sun coral, allowing larval dispersion.

Description: This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 202375, “Validation of a Novel MEG Sensor Employing a Pilot-Scale Subsea Jumper,” by Asheesh Kumar, The University of Western Australia; Mauricio Di Lorenzo, SPE, CSIRO Energy; and Bruce W.E. Norris, SPE, The University of Western Australia, et al., prepared for the 2020 SPE Asia Pacific Oil and Gas Conference and Exhibition, originally scheduled to be held in Perth, Australia, 20–22 October. The paper has not been peer reviewed. Online pipeline-management systems provide real-time and look-ahead functionality for production networks. They are limited, however, by a dearth of data with which to inform their predictions. This represents a barrier to a true, high-fidelity digital twin. Greater integration with new sensor technologies is needed to bound model predictions and improve their reliability. In this work, the authors present a novel monoethylene-glycol (MEG) sensing system and validate it in a specially constructed flow loop. Introduction Subsea jumpers experience a high probability of hydrate blockages. The most common practice used to avoid hydrate formation in subsea wellhead jumpers essentially is based on the injection of thermodynamic hydrate inhibitors such as MEG and methanol at high flow rates to flush out and inhibit the water pooled in the low spots of the jumper spools. Such hydrate management operations in deep water require adequate planning to minimize unproductive time and may not be feasible in unplanned well shutdowns. To improve the models implemented in current sensing technologies and explore their potential for new functionalities to detect hydrate formation, measurements under realistic field conditions in a controlled environment are vital. In this work, a flow loop that replicates the geometry of industrial subsea jumpers was deployed to investigate the performance of a new MEG sensor for subsea applications under hydrate-forming conditions. Preliminary baseline experiments were performed at steady state and during gas-restart operations in the absence of any hydrates in the jumper flow loop. Experiments were performed at 64.4°F with nitrogen (N2) gas at 1,200 psig and superficial gas velocity ranges from 0.82 to 2.88 ft/s. The MEG-sensing system’s performance was investigated under hydrate-forming conditions with and without MEG (10–30 wt% in water) in the jumper test section. These experiments were performed at temperatures ranging from 25.2 to 35.6°F. Experimental Flow Loop The flow loop consists of a test section connected to independent gas and liquid injection equipment at the inlet and gas-separation facilities at the outlet, which allows for continuous recirculation of gas and a once-through pass of the liquid. The test section has a complex geometry, with three identical low points (LPs) and two high points. The horizontal length of each low and high points is 12 ft, 10 in., and 7 ft, 7 in., respectively, and total height is 13 ft, 2 in. The test section is equipped with 12 pressure and temperature sensors distributed at regular intervals, a MEG sensor at the second LP, a throttling valve downstream of the first high point to mimic a wellhead choke, and a viewing window at the outlet.

Description: Though expensive and complex, extended-reach drilling (ERD) is moving more into the mainstream as the industry is driven to develop frontier reserves in fragile environments like the Arctic where drilling from shore to off-shore targets reduces a project’s infrastructure costs and environmental footprint. A form of directional drilling, ERD is also being used increasingly to tap into hard-to-produce reservoirs, making viable projects that might otherwise be written off as noncommercial. This article highlights how the Russian Far East became the ERD epicenter in the past decade, given ExxonMobil and Rosneft’s extensive use of ERD in developing Arctic resources offshore Sakhalin Island, and how ERD is becoming more widely used in regions as diverse as the Gulf of Thailand, off-shore Brazil, and the Arab Gulf. By definition, an extended-reach well (ERW) is one in which the ratio of the measured depth (MD) vs. the true vertical depth (TVD) is at least 2:1 (PetroWiki). An ERW differs from a horizontal well in that the ERW is a high-angle directional well drilled to intersect a target point, a feat requiring specialized planning to execute well construction. ExxonMobil subsidiary Exxon Neftegas Limited (ENL), which operates the Sakhalin-1 license area offshore Russia’s Sakhalin Island (Fig. 1), has been pushing the limits of ERD for nearly 2 decades with innovative technologies and sophisticated well planning, making the Sea of Okhotsk a place where any ERD drilling record set today may easily be broken tomorrow. Russia’s state-owned Rosneft (which has a 20% stake in Sakhalin-1) owns bragging rights for having drilled the longest ERW well on record to date. Rosneft announced in November 2017 it had drilled a 15000-m horizontal ERW from the offshore Orlan gravity-base platform at Chayvo field situated in 14 m water depth in the Sea of Okhotsk, topping four previous records set between 2013 and 2015 that had reached between 12450 m and 13500 m (Fig. 2). In a news release at the time, Rosneft called the well “super complex with a DDI [directional drilling index] of 8.0 and a 14129-m stepout.” The release went on to say that the Sakhalin-1 Consortium could (as of the 2017 announcement) claim to have drilled nine out of the world’s 10 longest ERD wells. According to Rosneft, the project had set five world records for measured depth of wells between 2013 and 2017. In April 2015, development well O-14 was drilled with a length of 13500 m. That broke a 2014 record when the 13000-m Z-40 well was completed. In 2013, records were announced for wells Z-43 and Z-42 which were drilled, respectively, in April and in June 2013 with lengths of 12450 m and 12700 m. Rosneft credited ExxonMobil’s patented “Fast Drill” drilling optimization process that can increase rates of penetration (ROP) by up to 400% as a significant innovation contributing to the ERD success story at Sakhalin-1. One of the largest foreign direct investments in Russia, Sakhalin-1 operates under a production sharing agreement (PSA) with its license area off the northeastern coast of Sakhalin Island, comprising the Chayvo, Odoptu, and Arkutun Dagi fields.

Description: This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 202683, “Marrying the Static and Dynamic Worlds: Enhancing Saturation and Permeability Interpretation Using a Combination of Multifrequency Dielectric, Nuclear Magnetic Resonance, and Wireline Formation Testers,” by Hassan Mostafa, Ghassan Al-Jefri, SPE, and Tania Felix Menchaca, SPE, ADNOC, et al., prepared for the 2020 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, held virtually 9–12 November. The paper has not been peer reviewed. Accurate water saturation evaluation and permeability profiling are crucial factors in determining volumetrics and productivity of multiple, stacked carbonate reservoirs offshore Abu Dhabi and derisking reservoir management. The case study presented in the complete paper illustrates how the integration of static measurements, such as dielectric dispersion and nuclear magnetic resonance (NMR) with dynamic measurements improves understanding of reservoir properties and supports more-accurate reservoir evaluation. Sampling and downhole fluid analysis (DFA) performed by wireline formation tester (WFT) identifies the fluid and rock properties in various flow units. Field Background and Challenges Optimal field development requires accurate estimations of water saturation and permeability. In this greenfield, the hydrocarbon is generally oil (medium to light) with very low asphaltene content. Overall, the reservoir quality is controlled by a combination of depositional environment, sequence stratigraphy, and diagenesis. Some reservoirs have good porosity, but reconciliation of log-based water saturation results with well-test results has been an issue. The objective in this case study was to drill a pilot hole for data gathering in a poorly characterized field location. Phase I included drilling a hole with a 55° deviation to cover all reservoirs for data gathering only, with the openhole reservoir section then being plugged and abandoned. Phase II of the plan was to sidetrack and complete the well as dual water-injector boreholes. In the reservoir section of the pilot borehole, a variety of logs was acquired for evaluation, including both logging-while-drilling and wireline measurements. While drilling, triple- combination data were acquired, consisting of gamma ray, resistivity, and nuclear logs (density neutron) along with resistivity images. The wireline-logging program was carried out in two stages to avoid differential sticking. In the first stage, the WFT was used to acquire 10 pressure points, seven points in the first reservoir and three points in the second. Two DFA stations were also recorded in Zone 1 to confirm whether the oil/water contact was deeper than expected. Logging was conducted using a high-tension wireline cable, which facilitates quicker accessibility to the openhole sections. In the second stage, multiple wireline runs were performed for the formation evaluation of the complete section, followed by the WFT pressure and fluid-sampling run on the drillpipe conveyance. Another critical challenge was to obtain accurate water saturations in the heterogeneous, minor, thin reservoirs, which are bounded by dense layers above and below and cause shoulder-bed effects. The third challenge in this well was to obtain an accurate, continuous, and representative permeability profile for the multiple reservoirs. WFT mini-drillstem test (DST) stations along with NMR logs were used to address this important requirement.

Description: This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 201417, “Reservoir Characterization and Geostatistical Model of the Cretaceous and Cambrian-Ordovician Reservoir Intervals, Meghil Field, Sirte Basin, Libya,” by Mohamed Masoud, Sirte Oil Company; W. Scott Meddaugh, SPE, Midwestern State University; and Masud Eljaroshi Masud, Sirte Oil Company, prepared for the 2020 SPE Annual Technical Conference and Exhibition, originally scheduled to be held in Denver, Colorado, 5–7 October. The paper has not been peer reviewed. The study outlined in the complete paper focuses on developing models of the Upper Cretaceous Waha carbonate and Bahi sandstone reservoirs and the Cambrian-Ordovician Gargaf sandstone reservoir in the Meghil field, Sirte Basin, Libya. The objective of this study is to develop a representative geostatistically based 3D model that preserves geological elements and eliminates uncertainty of reservoir properties and volumetric estimates. This study demonstrates the potential for significant additional hydrocarbon production from the Meghil field and the effect of heterogeneity on well placement and spacing. Introduction The reservoir of interest consists of three stratigraphic layers of different ages: the Waha and Bahi Formations and the Gargaf Group intersecting the Meghil field. The Waha reservoir is a porous limestone that forms a single reservoir with underlying Upper Cretaceous Bahi sandstone and Cambro-Ordovician Gargaf Group quartzitic sandstone. The Waha provides excel-lent reservoir characteristics. The Bahi has fair to good reservoir characteristics, while the Gargaf Group has very poor reservoir quality. The Waha and Bahi contain significant amounts of hydrocarbons. The Bahi is composed of erratically distributed detritus from the eroded Gargaf Group. The characteristic of the Gargaf sediments is quartzitic sandstones indurate to a quartzite with low reservoir quality.

Description: Either move or be moved. - Ezra Pound, American poet, 1885–1972 Flank Speed (a ship’s maximum speed) Character cannot be developed in ease and quiet. Only through experience of trial and suffering can the soul be strengthened, ambition inspired, and success achieved. - Helen Keller, American author, 1880–1968 (she was blind and deaf from birth) I will be uncharacteristically brief: if there were ever a time for operating at maximum capacity/capability, then this is it. I ask that everyone reading this column think of 10 tasks/ideas/concepts that they can perform right now that will change their trajectory (and hopefully SPE’s as well), distill those 10 tasks to three, and commit like your life depends on it to performing at least one of those tasks in the next 6–12 months. Call it homework if you want, but every person reading this column can create, innovate, and deliver some task/idea/concept that will significantly benefit our industry. Don’t say you have more important things to do—this is your profession and your passion. Get started, push directly to flank speed, and get it done. Then move to the next idea on your list. SPE needs its member contributions as never before. SPE and You Democracy is finding proximate solutions to insoluble problems. - Reinhold Niebuhr, American theologian, 1892–1971 It is very easy to sit on the fence, but sooner or later the post will hurt you where it counts. You must do something constructive in this life to be alive. More simply, in the words of the British clergyman John Henry Newman, “Growth is the only evidence of life.” SPE must grow its missions, but its missions must also include what we do now to prepare for the foreseeable future. Energy transition is not a fad; it is a critical path we as an industry and as a professional society must pursue to provide energy for all. Oil and gas are simultaneously our most secure energy resources, as well as our “battery backup” for situations where renewable options are either unavailable or impractical. Energy sustainability will evolve (I guarantee it), but let’s never forget what will pave the way to that sustainable and renewable energy future—oil and gas. Every conceivable product that is part of the energy transition is either fueled by or dependent on oil and gas as raw materials. Regardless of how you feel about SPE as a professional organization, it cannot and will not grow into what it must become without your volunteerism and your engagement. I understand that “change=pain,” but we are in a different world now. We can choose to be patient (wait and see what happens), pause (basically be in a state of paralysis), or we can pivot, which is to say that we can push or change/evolve to another path. It is complicated, because in the last year on an individual basis most if not all, of us have done all three.

Description: The market turmoil of 2020 left the upstream industry with diminished ranks, palpable concerns over long-term demand, and mounting pressure to reduce its carbon footprint. This made for what many consider a bullish case, as JPT has reported, for robotics uptake over the course of the decade. But there are reasons to temper expectations. After all, this is the oil and gas industry. The upstream land-scape is as vast as it is specialized. Each silo is a fortress of status quo to which robot developers must dedicate significant time and fortune in conquering. Some are worth the battle, especially in the offshore arena where factors of cost and safety have made this the most active corner of oil and gas robotics. Many other use cases may be worth bypassing. About 70% of the world’s oil and gas supply is produced onshore which, of course, is much more accessible to human operators. That means a robot dog in the Permian Basin has to jump over a much higher bar in order to create value than a robot dog tasked with inspecting a platform in the middle of the Norwegian Sea. Speaking of inspection, this is both the chief strength and upper limit for much of the current generation of robots. The next generation will be asked to fix things. And whatever they can’t do - or are just not the right tool for - look for it to be covered by industrial automation. As a new class of oil and gas robots finds its niche, and fights for investment dollars along the way, here are a few developments to track and points to consider. This Time It’s Different, Right Boss? The upstream sector pulled back from exploring the frontier of robotics and drone technologies in the last decade relative to other industries, but it is now being pulled forward by societal and technological shifts, according to Ed Tovar who runs an Austin-based consulting company, InTechSys, that serves the defense and energy industry.

Description: Energean Secures Rig for Multiwell Program off Israel Energean has signed a contract with Stena Drilling for an up to five-well drilling program offshore Israel, which is expected to target the derisking of unrisked prospective recoverable resources of more than 1 billion BOE. The contract is for the drilling of three firm wells and two optional wells using drillship Stena Icemax. The first firm well is expected to spud in early 2022. The firm wells are all expected to be drilled during 2022. “Our five-well growth program off-shore Israel, commencing in the first quarter of 2022, has the potential to double Energean reserve base with resource volumes that can be quickly, economically, and safely monetized,” said Mathios Rigas, chief executive of Energean. “Combined with first gas from our flagship Karish gas development project in mid-2022, the next 12 months are set to be truly transformational for Energean.” One of the firm wells is the Karish North development well. The scope includes re-entry, sidetracking, and completion of the previously drilled Karish North well and completion as a producer. The Karish North development will commercialize 1.2 Tcf of natural gas plus 31 million bbl of liquids and is expected to deliver first gas during the first half of 2023. The program also includes the Karish Main-04 appraisal well and the Athena exploration well, located in Block 12, directly between the Karish and Tanin leases. Athena is estimated to contain unrisked recoverable prospective resource volumes of 0.7 Tcf of gas plus 4 million bbl of liquids. Exxon Hits, Misses off Guyana ExxonMobil made another new discovery in the Stabroek Block offshore Guyana but came away empty with a well on the Canje block. The Longtail-3 well on the Stabroek block struck 230 ft of net pay, including newly identified reservoirs below those intervals found in the Longtail-1 probe. “Longtail-3, combined with our recent discovery at Uaru-2, has the potential to increase our resource estimate within the Stabroek block, demonstrating further growth of this world-class resource and our high-potential development opportunities offshore Guyana,” said Mike Cousins, senior vice president of exploration and new ventures at ExxonMobil. Exxon operates the 6.6-million-acre Stabroek Block as part of a consortium that includes Hess and China’s CNOOC. The new well was drilled 2 miles south of Longtail-1, which was drilled in 2018 and encountered 256 ft of oil-bearing sandstone. The Uaru-2 well in the Stabroek Block was announced in April. That well struck 120 ft of pay. While Stabroek drilling success continues, the operator suffered a set-back on the nearby Canje block and its Jabillo-1 well. The Stena Carron drillship reached a planned target depth of 6475 m; however the well failed to encounter commercial hydrocarbons. According to partner Eco Oil and Gas, the well was drilled to test Upper Cretaceous reservoirs in a stratigraphic trap. Drillship Stena Drillmax will next mobilize to drill the Sapote-1 prospect located in the south-eastern section of Canje, in a separate and distinct target from Jabillo. Sapote-1 lies approximately 100 km southeast of Jabillo and approximately 50 km north of the Haimara discovery in the Stabroek Block, which encountered 207 ft of gas-condensate-bearing sandstone reservoir. Erdogan Touts Turkish Black Sea Natural Gas Discoveries Turkey President Recep Tayyip Erdogan announced the discovery of new natural gas deposits in the Black Sea, where the country plans to start production in 2023. State energy company Tpao found 135 Bcm of gas at the Amasra-1 off-shore well, bringing the total amount of deposits discovered over the past year to 540 Bcm, according to Erdogan. Turkey has ramped up offshore exploration for hydrocarbons over the past few years. Last year, explorers found 405 Bcm of gas at the Tuna-1 well in Sakarya field. Turkey currently imports nearly all the 50 Bcm of gas it consumes annually. Equinor Hits Oil Near Visund Equinor struck oil in Production License 554 with a pair of wells at its Garantiana West prospect. Exploration wells 34/6-5 S and 34/6-5 ST2 were drilled some 10 km north-east of the Visund field, with the former encountering a total oil column of 86 m in the Cook formation. The latter well encountered sandstones in the Nansen formation, but did not encounter commercial hydro-carbons. Recoverable resources are esti-mated at between 8 and 23 million BOE. “This is the first Equinor-operated well in the production license, and the fifth discovery on the Norwegian continental shelf this year,” said Rune Nedregaard, senior vice president, exploration and production south. “The discovery is in line with our roadmap of exploring near existing infrastructure in order to increase the commerciality.” Well 34/6-5 S was drilled using Seadrill semisubmersible rig West Hercules. Equinor operates the discovery; partners include Var Energi and Aker BP. ExxonMobil Eyes Flemish Pass Well ExxonMobil is looking to secure a semi-submersible to complete the drilling of a deepwater wildcat in the Flemish Pass offshore eastern Canada. The operator began drilling the Hampden K-41 probe in the spring of last year using Seadrill semisubmersible rig West Aquarius, but the unit was pulled off the well soon thereafter for reasons unknown. ExxonMobil is currently prequalifying companies to supply a mobile offshore drilling unit to continue the well at Hampden in Exploration License (EL) 1165A. The operator is targeting a mid-year 2022 start to the probe to be drilled in around 1175 m of water, some 454 km from St. John’s, Newfoundland. Meanwhile, China’s CNOCC has wrapped up drilling on its Pelles prospect, its first exploration well offshore Newfoundland. The prospect, in about 1163 m of water, is located within license EL 1144. The wildcat was originally set to spud in early 2020 but was delayed due to impacts of the COVID-19 pandemic. The company confirmed that drilling operations onboard drillship Stena Forth were complete and the rig plugged and abandoned the well. The results of the well were not released. Equinor To Drop Mexican Offshore Leases Equinor will exit two Mexican deepwater blocks as part its upstream investment strategy to focus on assets offering rapid and strong returns. The two blocks located in the Salina Sureste basin were acquired in Mexico’s 1.4 bid round in an equal equity split with BP and TotalEnergies. Block 3, where Equinor holds a 33% operating interest, has water depths ranging from 900 to 2500 m. Block 1, where BP is the operator, has water depths ranging from 200 to 3100 m. Exploration commitments include a single well on each block, not yet drilled. The announcement to exit Mexico was made by Executive Vice President for E&P International Al Cook during the company’s Capital Markets Day event held in June. The company also unveiled plans to leave Nicaragua and Australia, as part of its upstream investment plans. Cook added that Equinor will only operate offshore assets moving forward and will no longer operate onshore, unconventional projects. The company will instead opt to partner with others on those projects. Equinor will also look to offload its exploration assets in the Austin Chalk play in the US and Terra Nova in Canada, he said. Var Energi Strikes North Sea Oil Var Energi has confirmed a discovery at its King and Prince exploration wells in the Balder area in the Southern North Sea. Success at the combined King and Prince exploration wells lifts preliminary estimates of recoverable oil equivalents between 60 and 135 million bbl. King/Prince was drilled in PL 027 by semisubmersible rig Scarabeo 8. The Prince well encountered an oil column of about 35 m in the Triassic Skagerrak formation within good to moderate reservoir sandstones, while the King well discovered a gas column of about 30 m and a light oil column of about 55 m with some thick Paleogene sandstone. An additional King appraisal side-track further confirmed a 40-m gas column and an oil column of about 55 m of which about 35 m are formed by thick and massive oil-bearing sandstone with excellent reservoir quality. The licensees consider the discoveries to be commercial and will assess tie-in to the existing infrastructure in the Balder area. The wells are located about 6 km north of the Balder field and 3 km west of the Ringhorne platform. Var Energi operates and holds a 90% stake of the license. Mime Petroleum holds the remaining 10%.

Description: Every engineer and manager knows that you can only improve performance that you measure and track. That is why we have key performance indicators (KPIs). Similarly, we can only optimize what we can predict. If we really want to lower carbon emissions, we will need to implement a consistent method of measuring and tracking the right data. There are challenges in improving what we track because tracking comes from so many sources. We need to work on optimizing what we predict if we are going to start making high-value decisions around emissions. Carbon emissions occur during all phases of the hydrocarbon extraction industry right through to the final use of the product. We call the total life cycle of emissions “well to wheels.” SPE members are generally focused on one phase of the carbon emissions. The largest contribution is the combustion and use of produced oil, from refinery to wheels. This is typically about 350–400 kg of CO2 equivalent per barrel. We use CO2 equivalent to include the greenhouse-gas (GHG) impact of methane. Then, there is the energy and carbon expenditure of producing that hydrocarbon, well to refinery. This includes drilling, completions, production, and transportation. Carbon emissions from the wells to refinery vary from less than 25 kg to more than 300 kg CO2 equivalent per barrel, averaging about 100. Flaring and fugitive emissions are generally the largest contributors to these emissions. Environmental, social, and governance (ESG) activism is driving changes in behavior for public investors, private investors, lenders, and management teams. When will the measuring be done? Who will set the industry standards? How will the model be developed? Carbon emissions from shale production vary dramatically and are also driven by flaring and fugitives. While flaring is preferable to venting, most low-volume flares are inefficient. Operators flare for a variety of reasons including lack of pipeline capacity, upsets, and low value for natural gas. Fugitive emissions also enter the equation. Fugitive emissions are any leakage or irregular release to the atmosphere of natural gas. This can be caused by human error, mechanical operations (such as pneumatic actuators), or faulty equipment. Fugitive emissions and flaring both factor into the well-to-reservoir carbon footprint. Many operators already report the carbon intensity of their activities, usually prior-year activities. Carbon intensity is the carbon emissions per unit of energy or per barrel. A variety of regulatory bodies and others argue the definitions of such reporting. We are arguing for reporting estimated carbon intensity of reserves.

Description: This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 201586, “Effect of Silica Nanoparticles on Oil Recovery During Alternating Injection With Low-Salinity Water and Surfactant Into Carbonate Reservoirs,” by Saheed Olawale Olayiwola, SPE, and Morteza Dejam, SPE, University of Wyoming, prepared for the 2020 SPE Annual Technical Conference and Exhibition, originally scheduled to be held in Denver, Colorado, 5–7 October. The paper has not been peer reviewed. Although the potential of nanoparticles (NPs) to improve oil recovery is promising, their effect during alternating injection is still uncertain. The main objective of the authors’ study is to investigate the best recovery mechanisms during alternating injection of NPs, low-salinity water (LSW), and surfactant and transform the results into field-scale technology. The outcome of these experiments revealed that tertiary injection of NPs results in additional oil recovery beyond the limits of LSW. Introduction A series of coreflooding experiments was conducted using several cores with an effective permeability of approximately 1 md to the brine at a temperature and pressure of 70°C and 3,000 psi. The study performs four different alternating injections of NPs with LSW and surfactant to determine optimal oil recovery. The wettability of the rock and fluid and the interfacial tension (IFT) of oil and water are measured to understand the mechanisms of interactions between the fluids and the reservoir rock. Materials A 12×12×12-in. block taken from an outcrop of Indiana limestone reservoir was purchased for this study. Four core plugs with a diameter of 1.5 in., used for the coreflooding experiments, were selected from this block. A synthetic 100,000-ppm (10 wt%) brine was prepared in the laboratory by dissolving sodium chloride (NaCl) and calcium chloride with a ratio of 4:1 in deionized water. The crude oil used in this study was a volatile oil (properties are described in Table 2 of the complete paper) obtained from the Permian Basin in Texas. Injected Fluids. A 10,000-ppm (1 wt%) LSW was prepared by diluting the synthetic brine 10 times. The surfactant solutions were prepared from an anionic sodium dodecyl sulfate (SDS) surfactant. A 1,000-ppm (0.1 wt%) surfactant solution used throughout the experiments was selected on the basis of the estimated critical micelle concentration of 600 to 2,240 ppm for SDS and nanofluid/NaCl. The concentration of silica NPs used in this study was 500 ppm (0.05 wt%). The nanofluids were pre-pared either as a simple solution or as a mixture with other chemicals to make a concentration of 500-ppm silica NPs. Coreflooding System. The established coreflooding system used for this experimental study was custom-made to determine the oil recovery and the relative permeabilities at steady-state and unsteady-state flows. However, the focus of this study is to investigate the effect of silica NPs on oil recovery. The schematic diagram of the coreflooding system is shown in Fig. 1.

Description: This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 201254, “Reinforcement Learning for Field-Development Policy Optimization,” by Giorgio De Paola, SPE, and Cristina Ibanez-Llano, Repsol, and Jesus Rios, IBM, et al., prepared for the 2020 SPE Annual Technical Conference and Exhibition, originally scheduled to be held in Denver, Colorado, 5–7 October. The paper has not been peer reviewed. A field-development plan consists of a sequence of decisions. Each action taken affects the reservoir and conditions any future decision. The presence of uncertainty associated with this process, however, is undeniable. The novelty of the approach proposed by the authors in the complete paper is the consideration of the sequential nature of the decisions through the framework of dynamic programming (DP) and reinforcement learning (RL). This methodology allows moving the focus from a static field-development plan optimization to a more-dynamic framework that the authors call field-development policy optimization. This synopsis focuses on the methodology, while the complete paper also contains a real-field case of application of the methodology. Methodology Deep RL (DRL). RL is considered an important learning paradigm in artificial intelligence (AI) but differs from supervised or unsupervised learning, the most commonly known types currently studied in the field of machine learning. During the last decade, RL has attracted greater attention because of success obtained in applications related to games and self-driving cars resulting from its combination with deep-learning architectures such as DRL, which has allowed RL to scale on to previously unsolvable problems and, therefore, solve much larger sequential decision problems. RL, also referred to as stochastic approximate dynamic programming, is a goal-directed sequential-learning-from-interaction paradigm. The learner or agent is not told what to do but instead has to learn which actions or decisions yield a maximum reward through interaction with an uncertain environment without losing too much reward along the way. This way of learning from interaction to achieve a goal must be achieved in balance with the exploration and exploitation of possible actions. Another key characteristic of this type of problem is its sequential nature, where the actions taken by the agent affect the environment itself and, therefore, the subsequent data it receives and the subsequent actions to be taken. Mathematically, such problems are formulated in the framework of the Markov decision process (MDP) that primarily arises in the field of optimal control. An RL problem consists of two principal parts: the agent, or decision-making engine, and the environment, the interactive world for an agent (in this case, the reservoir). Sequentially, at each timestep, the agent takes an action (e.g., changing control rates or deciding a well location) that makes the environment (reservoir) transition from one state to another. Next, the agent receives a reward (e.g., a cash flow) and an observation of the state of the environment (partial or total) before taking the next action. All relevant information informing the agent of the state of the system is assumed to be included in the last state observed by the agent (Markov property). If the agent observes the full environment state once it has acted, the MDP is said to be fully observable; otherwise, a partially observable Markov decision process (POMDP) results. The agent’s objective is to learn policy mapping from states (MDPs) or histories (POMDPs) to actions such that the agent’s cumulated (discounted) reward in the long run is maximized.

Description: 2022 SPE President Kamel Ben-Naceur Kamel Ben-Naceur is CEO of Nomadia Energy Consulting, where he advises on sustainable energy policies and global and regional energy economics and outlooks. He has worked as the chief economist for a major oil and gas company and for an oilfield services company. Ben-Naceur has also worked as a director of the International Energy Agency and as the industry, energy, and mines minister for the Tunisian government. He has chaired several SPE global committees, including Business Management and Leadership, the International Forum Series, and CO2 Capture, Utilization, and Storage. He has also taught several SPE courses on global energy and strategic thinking and planning. He was technical director for the Management and Information discipline on the SPE International Board of Directors from 2008 to 2011. Ben-Naceur was also an SPE Distinguished Lecturer during the 2009–2010 season and received an SPE Distinguished Member Award and SPE Distinguished Service Award in 2014, the AIME Charles F. Rand Memorial Gold Award in 2019, and the 2020 Sustainability and Stewardship in the Oil and Gas Industry Award. He has coauthored more than 150 publications and 17 books. Ben-Naceur holds the Agrégation de Mathématiques degree from the École normale supérieure and a master’s degree in engineering from École Polytechnique in Paris. What key issues will you emphasize as 2022 SPE President? Our industry, along with many other economical sectors, has experienced a major impact from the pandemic. The magnitude of the drop in oil demand in 2020, both in absolute and relative terms, is unprecedented. It led also to a major reduction in oilfield investment activity around the world, in the order of 30% compared to pre-COVID-19 levels. The fast-track development of vaccines and their availability, even though progress is still required to ensure that they are distributed fairly around the world, is raising hope that the worst may be behind us. SPE members have also been impacted in their ability to meet at technical conferences and exhibitions and participate in workshops or forums. As 2022 SPE President, the theme I wish to develop is the “sustainable recovery” for our industry and for SPE. The industry has experienced in 2020–2021 a major loss of valuable employees ranging from young professionals to senior members. This has followed a major downcycle in 2014–2015. After a 30% drop in Capex in 2020 compared to 2019, 2021 should see a modest recovery in activity (6–8% increase). The next year should welcome a 10–12% activity surge, providing an increase in employment opportunities for our members in transition, as well as for our student members. Barring new negative developments in the pandemic, the recovery in activity should strengthen to reach pre-COVID levels by 2025, albeit 15–20% below the level that was expected before. The recovery of demand and activity should also be linked to a more sustainable trajectory of energy demand and supply. Sustainability will be my second area of focus, with SPE having already engaged significantly. I had the opportunity to participate in the startup of the SPE GAIA Sustainability Program, which is now developing into many different directions, thanks to the efforts of SPE volunteers. 2019 SPE President Sami Al-Nuaim had put sustainability at the heart of his presidency, and I am pleased to see several of his initiatives materialize. The third area of focus will be a gradual restart of physical meetings, where we will transition with the increase of hybrid (in-person/virtual) events, which is eagerly anticipated by our members. The fourth area of focus is related to the development of the new SPE Strategic Plan. Last but not least, is the proposed merger between SPE and the American Association of Petroleum Geologists (AAPG).

Description: This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 201520, “Advances in Understanding Relative Permeability Shifts by Imbibition of Surfactant Solutions Into Tight Plugs,” by Mohammad Yousefi, Lin Yuan, and Hassan Dehghanpour, SPE, University of Alberta, prepared for the 2020 SPE Annual Technical Conference and Exhibition, originally scheduled to be held in Denver, Colorado, 5–7 October. The paper has not been peer reviewed. Various chemical additives have been proposed recently to enhance imbibition oil recovery from tight formations during shut-in periods after hydraulic fracturing operations. In the complete paper, the authors develop and apply a laboratory protocol mimicking leakoff, shut-in, and flowback processes to evaluate the effects of fracturing-fluid additives on oil regained permeability. A conventional coreflooding apparatus is modified to measure oil effective permeability (koeff) before and after the surfactant-imbibition experiments. Methodology Proposed Technique for Measuring Oil Effective Permeability. Despite the simplicity of the steady-state method, measuring permeability of tight rocks with this technique is challenging because of its time-consuming nature and the fact that accurate measurement is necessary of extremely low flow rates corresponding to low injectivity of tight rocks. The authors use a pair of plugs from a well drilled in the Montney formation that is a stratigraphic unit of the Lower Triassic age in the western Canadian sedimentary basin located in British Columbia and Alberta. It is mainly a low-permeability siltstone reservoir. In the modified coreflooding apparatus, the authors reduce the effect of compressibility in order to reduce the duration of the transient period by approximately one order of magnitude. Because monitoring changes in pressure is much easier and more accurate than monitoring flow-rate changes, a constant flow-rate mode is used and pressure is recorded with time. Oil is injected at different constant flow rates (qo), and the inlet pressure is monitored. The stable pressure difference across the plug is recorded for each flow rate. After steady-state conditions are reached based on the pressure profile, the qo is increased. This process is repeated until four stable pressure differences corresponding to four different qo are obtained. After the highest qo is reached, it is decreased in similar steps to check the repeatability of each data point. The permeability is calculated with the Darcy equation and slope of the qo vs. stable pressure difference across the plug.

Description: The digital transformation that began several years ago continues to grow and evolve. With new advancements in data analytics and machine-learning algorithms, field developers today see more benefits to upgrading their traditional development work flows to automated artificial-intelligence work flows. The transformation has helped develop more-efficient and truly integrated development approaches. Many development scenarios can be automatically generated, examined, and updated very quickly. These approaches become more valuable when coupled with physics-based integrated asset models that are kept close to actual field performance to reduce uncertainty for reactive decision making. In unconventional basins with enormous completion and production databases, data-driven decisions powered by machine-learning techniques are increasing in popularity to solve field development challenges and optimize cube development. Finding a trend within massive amounts of data requires an augmented artificial intelligence where machine learning and human expertise are coupled. With slowed activity and uncertainty in the oil and gas industry from the COVID-19 pandemic and growing pressure for cleaner energy and environmental regulations, operators had to shift economic modeling for environmental considerations, predicting operational hazards and planning mitigations. This has enlightened the value of field development optimization, shifting from traditional workflow iterations on data assimilation and sequential decision making to deep reinforcement learning algorithms to find the best well placement and well type for the next producer or injector. Operators are trying to adapt with the new environment and enhance their capabilities to efficiently plan, execute, and operate field development plans. Collaboration between different disciplines and integrated analyses are key to the success of optimized development strategies. These selected papers and the suggested additional reading provide a good view of what is evolving with field development work flows using data analytics and machine learning in the era of digital transformation. Recommended additional reading at OnePetro: www.onepetro.org. SPE 203073 - Data-Driven and AI Methods To Enhance Collaborative Well Planning and Drilling-Risk Prediction by Richard Mohan, ADNOC, et al. SPE 200895 - Novel Approach To Enhance the Field Development Planning Process and Reservoir Management To Maximize the Recovery Factor of Gas Condensate Reservoirs Through Integrated Asset Modeling by Oswaldo Espinola Gonzalez, Schlumberger, et al. SPE 202373 - Efficient Optimization and Uncertainty Analysis of Field Development Strategies by Incorporating Economic Decisions in Reservoir Simulation Models by James Browning, Texas Tech University, et al.

Description: This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 203321, “Integrated Debottlenecking Approach Revitalizes Aging Platform by Increasing Production 30% in Gulf of Mexico,” by Ankur Gandhi, Sara L. McConkey, and Jeremy Kimbrough, SPE, Occidental, et al., prepared for the 2020 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, held virtually 9–12 November. The paper has not been peer reviewed. Successful identification, evaluation, and management of bottlenecks in a complex offshore production processing system is challenging but can increase daily production significantly. The Constitution platform in the Green Canyon area of the Gulf of Mexico, which was commissioned in 2006 with a nameplate capacity of 70,000 BOPD, is a complex system with four fields in varying stages of development. The complete paper focuses on a multidisciplinary process developed to identify, evaluate, and eliminate interdependent bottlenecks on the platform and its flowline network during a 16-month period; this synopsis details some of these findings. Integrated Process A study and field trial during 2016–17 demonstrated the ability to separate fluids above the design capacity, but the team faced challenges in terms of flow reliability even at lower production rates. Therefore, in 2017, an effort was launched to understand and mitigate this issue. The underlying process used for the effort stemmed from principles of Six Sigma and Gemba walks. The steps of the process, detailed in the complete paper, are as follows: 1. Define 2. Measure and analyze 3. Design 4. Verify and execute 5. Review The process allows the team to see the variance between perception and reality. The results-driven, continuous-improvement approach also increases visibility among leaders, giving them a chance to interact with subject-matter experts (SMEs) and to understand key bottlenecks. Platform Bottlenecks and Responses Reservoir and Subsea Network Deliverability. The rate uplift from the debottlenecking efforts was estimated using a reservoir simulation model that included a fully integrated subsea flow net-work model, which solved the reservoir and flow network equations in the same Newtonian iteration. This type of simulation model particularly is suited for the problem at hand, provided that the reservoir model adequately matches historical well performance and the network model matches historical friction pressure losses as a function of rate. The simulation model predicted that the reservoir should be able to deliver a rate uplift of 30% above the production rate before debottlenecking. Topsides Fluids Processing Debottlenecking: General. The late-life debottlenecking of the platform posed many process engineering challenges, some of which stemmed from the inherent flexibility for which the platform was designed. The multitude of gas paths available led to many viable operating alignments of sources to separators and then separators to compressor stages. One initial exercise for debottlenecking was to develop a matrix of potential future operating modes, which would account for the required operator flexibility, as well as to address compressor downtime and the resulting temporary rerouting of sources. Once this matrix was developed, topsides process simulations were developed for each to identify capacity requirements for each equipment item. As detailed in the complete paper, topsides fluids processes involving the oil-cooling system and oil-system hydraulics were also debottlenecked.

Description: Purchasing carbon offsets is a widespread means of attempting to meet carbon-reduction and net-zero emissions goals across many industries. Also widespread is the increasing scrutiny of the practice. How “real” are the offsets? How are they quantified and verified, and by whom? Purchasing carbon offsets, or carbon credits, is an option when a company’s efforts to eliminate its carbon emissions through mitigation methods fall short. The offsets are purchased through investments in projects that remove carbon from the atmosphere such as nature-based solutions (e.g., REDD, or reducing emissions from deforestation and forest degradation), negative-emission technologies (including carbon capture and storage [CCS] and bioenergy with CCS), and renewable energy. Here’s where the criticism arises: How is the amount of carbon captured by these projects measured? For example, how much carbon can a tree or forest handle? Are all trees equal in their carbon intake? The uncertainty and variability in carbon-accumulation rates is acknowledged in research studies that are attempting to provide quantification. A study published in Nature compiled more than 13,000 georeferenced measurements to determine the rates for the first 30 years of natural forest regrowth. A map showed more than 100-fold variation in rates across the globe and indicated that default rates from the Intergovernmental Panel on Climate Change may underestimate the rates by 32% on average and do not capture eightfold variation within ecozones. On the other hand, the study concluded that the maximum mitigation potential from natural forest regrowth is 11% lower than previously reported because of the use of overly high rates for locations of potential new forest. While the study was not intended to provide verification to be used in the carbon-offset market, it points to the difficulty in getting the numbers right. Third-party verifiers are casting light on the validity of offsets. Various organizations such as the Climate Registry and the American Carbon Registry (ACR) aim to set standards and best practices. In both the regulated and voluntary carbon markets, ACR says it “oversees the registration and verification of carbon-offset projects following approved carbon accounting methodologies or protocols and issues offsets on a transparent registry system.” In July, CarbonPlan, a nonprofit that analyzes climate solutions based on the best available science and data, rated BCarbon, a standard created by Rice University’s Baker Institute for Public Policy, as one of the best publicly available protocols for soil carbon offsets in the US. BCarbon, a nature-based mitigation system, aims to remove CO2 from the atmosphere and store it in soil as organic carbon. Based on independent verification and certification requirements, the credits under the system are issued for the removal of CO2 by photosynthesis and storage as carbon in soil. Landowners are eligible for storage payments. The Baker Institute said the approach could unlock the potential for removal, storage, and certification of upwards of 1 billion tons of CO2 and lead to the protection and restoration of hundreds of millions of acres of grassland. Scrutiny of carbon offsets is beneficial in this expanding carbon market. Verification and certification will serve to increase the trust of both buyers and sellers—and the public—in what will likely be a bridge toward longer-term solutions to reduce global carbon emissions. And getting the numbers right is essential.

Description: This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 200957, “Application of Specially Designed Polymers in High-Water-Cut Wells: A Holistic Well-Intervention Technology Applied in Umm Gudair Field, Kuwait,” by Ali Abdullah Al-Azmi, SPE, Thanyan Ahmed Al-Yaqout, and Dalal Yousef Al-Jutaili, Kuwait Oil Company, et al., prepared for the 2020 SPE Trinidad and Tobago Section Energy Resources Conference, originally scheduled to be held in Port of Spain, Trinidad and Tobago, 29 June–1 July. The paper has not been peer reviewed. A significant challenge faced in the mature Umm Gudair (UG) field is assurance of hydrocarbon flow through highly water-prone intervals. The complete paper discusses the field implementation of a downhole chemical methodology that has positively affected overall productivity. The treatment was highly modified to address the challenges of electrical-submersible-pump (ESP)-driven well operations, technical difficulties posed by the formation, high-stakes economics, and high water potential from these formations. Field Background and Challenge The UG field is one of the major oil fields in Kuwait (Fig. 1). The Minagish oolite (MO) reservoir is the main oil producer, contributing more than 95% of current production in the UG field. However, water cut has been increasing (approximately 65% at the time of writing). The increasing water cut in the reservoir is posing a major challenge to maintaining the oil-production rate because of the higher mobility of water compared with that of oil. The natural water aquifer support in the reservoir that underlies the oil column extends across the reservoir and is rising continuously. This has led to a decline in the oil-production rate and has prevented oil-producing zones from contributing effectively. The reservoir experiences water-coning phenomena, especially in high-permeability zones. Oil viscosity ranges from 2 to 8 cp, and hydrogen sulfide and carbon dioxide levels are 1.5 and 4%, respectively. During recent years, water production has increased rapidly in wells because of highly conductive, thick, clean carbonate formations with low structural dip as well as some stratified formations. Field production may be constrained by the capacity of the surface facilities; therefore, increased water production has different effects on field operations. The average cost of handling produced water is estimated to be between $5 billion and $10 billion in the US and approximately $40 billion globally. These volumes often are so large that even incremental modifications can have major financial effects. For example, the lift-ing cost of one barrel of oil doubles when water cut reaches 50%, increases fivefold at 80% water cut, and increases twenty-fold at 95% water cut.

Description: This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 203152, “Generative Well-Pattern Design Applied to a Giant Mature Field Leads to the Identification of Major Drilling Expenditure Reduction Opportunities,” by Maddalen Lepphaille, Total; Arthur Thenon, Modis; and Pierre Bergey, Total, et al., prepared for the 2020 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, held virtually 9–12 November. The paper has not been peer reviewed. A generative well-pattern-design (GWPD) work flow was benchmarked against traditional manual designs to leverage three reservoir-development planning opportunities applicable to a giant mature Middle Eastern carbonate field. People remained central in ensuring efficient problem setup and exploration guidance, but the work flow proved able to identify substantially better patterns than the traditional approach for each of the opportunities at the cost of only a few hundred simulations. GWPD Overview The work flow used to tackle the different problems of this study, which the authors call the GWPD “well-improvement scheme” (WISH), consists of the following steps. Each step is detailed in the complete paper. 1. Definition of design space 2. Constraint of design space 3. Qualification of design space 4. Nondominated sorting (a specific ranking of all of the cells of the con-strained design space according to the value of their quality indicators) 5. Candidate design investigation 6. Investigation of preferred designs 7. Optimization of preferred design GWPD Application Context. The application study was con-ducted at the beginning of the industrialization of WISH, a proprietary software tool dedicated to GWPD. The authors call the work flow GWPD-WISH. In the studied oil field, more than 400 oil producers and water- or gas-injector strings have been drilled from approximately 100 platforms in a series of reservoirs. The study focused upon two specific reservoirs holding most of the field reserves. These reservoirs are developed with peripheral water injection and gas injection into the gas cap. According to the latest development plan, hundreds of wells will be drilled during the next 40 years in order to maintain a production plateau. The context was deemed favorable because a 3D gridded dynamic reservoir model was available, the geology and development history defined a large and complex design problem, and large liquid hydrocarbon reserves were thought to remain. While the software and method used enables considering an ensemble of realizations capturing reservoir uncertainties, only a single history-matched realization of the model was available. Consequently, the study did not deal with reservoir uncertainties.

Description: This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 31250, “Wandoo B: Application of Advanced Reinforced Concrete Assessment for Life Extension for Non-Jacket Structures,” by Robert Sheppard, Spire Engineering; Colin O’Brien, Vermilion Oil and Gas; and Yashar Moslehy, Spire Engineering, et al., prepared for the 2021 Offshore Technology Conference, originally scheduled to be held in Houston, 4–7 May. The paper has not been peer reviewed. Copyright 2021 Offshore Technology Conference. Reproduced by permission. Wandoo B is a concrete gravity-based structure (GBS) and is the main production facility for the Wandoo field offshore northwest Australia. It was installed in 1997 with a design life of 20 years. The structural assessments discussed in this paper are part of a comprehensive life-extension project encompassing wells, subsea systems, marine and safety systems, and topsides facilities and structures to demonstrate fitness for service through the end of field life. Background The GBS serves as the support structure for the Wandoo B facility and provides oil storage for the Wandoo field. The structure has four shafts approximately 11 m in diameter that support the top-sides facilities and a base structure with permanent ballast and oil storage cells (Fig. 1). It was originally developed as an ExxonMobil-led project and now is owned and operated wholly by Vermilion Oil and Gas Australia. The reinforced concrete (RC) shafts and the base top slab are pretensioned. In the shafts, tendons are enclosed in 20 ducts distributed around the circumference. The top of the shafts provides a mating point with the steel topsides structure with the connection formed by embedded anchor bolts in a bulge in the shaft cross section. The topsides structure is a three-level braced steel frame system supporting production operations for 12 well conductors contained within the northeast shaft and three outboard well conductors. Life-Extension Project The facility was designed with a target life of 20 years. The life-extension project was intended not only to satisfy the operator’s responsibility to continue safe operations and adhere to their safety case but also to meet the expectations of the regulator. The structural aspects of the project included four phases, the first two of which are detailed in this synopsis: - Design assessments per latest standards and modifications where required - Ultimate capacity assessments with retrofit modifications where required - Risk studies and workshops to demonstrate that risk is as low as reasonably practicable (ALARP) - Integrity-management manual and inspection plan The first two phases were addressed using the latest condition-assessment, weight, and environmental data available. The phased approach allowed the assessment team to use basic linear approaches to demonstrate code compliance and only use the more-advanced analysis techniques to evaluate the critical components that did not satisfy code or were needed to provide input to the ALARP assessment and establish target reliability for the facility.

Description: This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 201698, “Finding a Trend Out of Chaos: A Machine-Learning Approach for Well-Spacing Optimization,” by Zheren Ma, Ehsan Davani, SPE, and Xiaodan Ma, SPE, Quantum Reservoir Impact, et al., prepared for the 2020 SPE Annual Technical Conference and Exhibition, originally scheduled to be held in Denver, Colorado, 5–7 October. The paper has not been peer reviewed. Data-driven decisions powered by machine-learning (ML) methods are increasing in popularity when optimizing field development in unconventional reservoirs. However, because well performance is affected by many factors, the challenge is to uncover trends within all the noise. By leveraging basin-level knowledge captured by big data sculpting, integrating private and public data with the use of uncertainty quantification, a process the authors describe as augmented artificial intelligence (AI) can provide quick, science-based answers for well spacing and fracturing optimization and can assess the full potential of an asset in unconventional reservoirs. A case study in the Midland Basin is detailed in the complete paper. Introduction Augmented AI is a process wherein ML and human expertise are coupled to improve solutions. The augmented AI work flow (Fig. 1) starts with data sculpting, which includes information retrieval; data cleaning and standardization; and smart, deep, and systematic data quality control (QC). Feature engineering generates all relevant parameters entering the ML model. More than 50 features have been generated for this work and categorized. The final step is to perform model tuning and ensemble, evaluating model robustness and generating model explanation and uncertainty quantification. Geology The complete paper provides a detailed geological background of the Permian Basin and its Wolfcamp unconventional layer, an organic-rich shale formation with tight reservoir properties. To find a solution for the multidimensional well-spacing problem in the Permian Basin, multiple sources and types of data were gathered using publicly available sources. The detailed geological attributes, including structure, petrophysics, geochemistry, basin-level features, and cultural information (such as counties or lease boundaries) have been combined in an integrated database to extract and generate features for the ML algorithm. Most attributes are available either in a limited number of wells, mostly vertical, or through the low number of available cored wells across the basin. Therefore, a significant amount of data imputation has been processed with mapping exercises using geostatistical modeling techniques. The mapping process augmented the ML attribute-generation step because these features were distributed in both vertical and lateral dimensions. All horizontal wells within the area of interest across the Permian Basin have been resampled with the logged and mapped information. The geological features also are reengineered into multiple indices to reduce the number of labeled features to include in the ML process. This feature-reduction process also has helped in ranking and selecting the most-important parameters relevant to the well-spacing problem. Here, a key attribute called the shale-oil index was introduced, which is generated for the ML-driven process and is used in understanding the level of contribution of geological sweet spots to well-spacing optimization. In addition, the initial well, reservoir, or laboratory data, including logs, have been normalized before mapping and modeling to eliminate potential bias. This study has focused on Wolfcamp layers; however, both geological and engineering attribute generation work flows used for this practical ML methodology to find optimization solutions for common problems are highly applicable to other unconventional layers, such as Bone Spring or Spraberry.

Description: Eni Confirms Block 10 Oil Strike Offshore Mexico Eni confirmed it encountered oil shows in the Upper Miocene sequences on the Sayulita Exploration Prospect in Block 10 in the mid-deep water of the Cuenca Salina Sureste Basin. Preliminary estimates put the new find at between 150 and 200 million BOE in place. Sayulita-1 EXP is the seventh successful well drilled by Eni in the basin and the second commitment well of Block 10. It is located approximately 70 km off the coast and just 15 km away from the previous oil discovery of Saasken that will be appraised toward year-end. The well was drilled to a total depth of 1758 m by the semisubmersible Valaris 8505 in a water depth of 325 m. APA Touts Appraisal Success Off Suriname APA Corp. said its Sapakara South-1 appraisal well, located on the eastern edge of the Sapakara area, encountered approximately 30 m of net black-oil pay in a single zone of high-quality Campano-Maastrichtian reservoir. Drillship Maersk Valiant will soon mobilize to the next exploration prospect at Bonboni, about 45 km to the north, before returning later in the year to flow-test Sapakara South-1. A second appraisal well encountered two thin intervals of black oil above water in the Campano-Maastrichtian at Kwaskwasi, impacting a small portion of the eastern edge of Kwaskwasi. The Campano-Maastrichtian intervals at Kwaskwasi and the Sapakara South-1 discovery are separate and unrelated. Shell Begins Barracuda Production Shell Trinidad and Tobago, through BG International, a subsidiary of Royal Dutch Shell plc, has started production on Block 5C in the East Coast Marine Area in Trinidad and Tobago. Block 5C, known as Project Barracuda, is a backfill project with approximately 140 MMcf/D of sustained near-term gas production with peak production expected to be about 220 MMcf/D. It is Shell’s first greenfield project in the country and one of its largest in Trinidad and Tobago since the BG Group acquisition. “Today’s announcement strengthens the resilience and competitiveness of Shell’s position in Trinidad and Tobago,” said Maarten Wetselaar, director of integrated gas, renewable, and energy solutions for Shell. “This is a key growth opportunity that supports our long-term strategy in the country as well as our global LNG growth ambitions.” Eni Strikes Oil With Eban Well Off Ghana Eni has struck a significant oil discovery on the Eban exploration prospect in CTP Block 4, offshore Ghana. The Eban-1X well is the second well drilled in CTP Block 4, following the Akoma discovery. Preliminary estimates place the potential of the Eban-Akoma complex between 500 and 700 million BOE in place. The Eban-1X well is located approximately 50 km off the coast and about 8 km northwest of Sankofa Hub, where the John Agyekum Kufuor FPSO is located. It was drilled by drillship Saipem 10000 in a water depth of 545 m and reached a total depth of 4179 m. The well encountered a single light-oil column of about 80 m in a thick sandstone reservoir interval of Cenomanian age with hydrocarbons encountered down to 3949 m. Talos Lines Up Gulf of Mexico Successes Talos Energy drilled a successful sidetrack of its Crown and Anchor well at Viosca Knoll Block 960. The probe was drilled to a true vertical depth of about 13,000 ft and encountered around 50 ft of net oil pay in the M62 Middle Miocene target horizon. The project has moved to the completion phase and will produce through existing subsea infrastructure to the nearby Marlin tension-leg platform. First production is targeted by the late third quarter of 2021. Talos holds a 34% working interest in the project along with Beacon Offshore Energy (operator) and Ridgewood Crown & Anchor LLC. Greenland Calls Halt to New Oil Exploration Greenland has ended its decades-long pursuit to become an oil-producing nation after announcing 16 July it would stop granting oil and gas exploration licenses, adding that “the future does not lie in oil.” Oil exploration began for the country in the 1970s, with several major operators coming in to test the area’s prospectivity. Exploration for hydrocarbons in Greenland peaked between 2002 and 2014, when more than 20 offshore licenses were granted. Those companies that drilled walked away empty-handed. “There’s no doubt that our subsoil is rich in oil resources,” the government said in the 16 July press release. “But oil extraction won’t only have positive effects on our society, it will adversely affect our nature and environment, and may adversely affect fisheries as well as contribute to the worsening global climate crisis.”

Description: Fluid samples collected using either wireline or logging-while-drilling (LWD) formation-testing technology for reservoir fluid characterization have long been accepted as the most representative of reservoir fluid. This, though, comes with a caveat that the collected sample is clean and devoid of any mud-filtrate contamination. With both techniques performed soon after drilling a well, there is always a risk of contaminating the collected fluid with mud filtrate. Toward the goal of reducing this risk, since the early 2000s, technologies have been brought forth to help identify the fluid down hole. There have been multiple developments with sensors for absorbance spectroscopy, fluorescence, fluid resistivity, fluid refractive index, and so on. Each sensor development was targeted toward a specific fluid interaction with the mud filtrate, thereby helping to differentiate the reservoir fluid from the mud filtrate. Downhole sampling conditions can be classified into two broad groups: one case where the reservoir fluid is miscible with the mud filtrate and the other where the reservoir fluid is not miscible with the mud filtrate. The immiscible cases are generally straightforward, since sensors such as absorbance spectroscopy can easily differentiate among oil, water, and gas. In addition, the technique can be used to determine the fractional portion of each phase in the flow. Complications arise when the reservoir fluids happen to be miscible with the mud filtrate system; for example, while sampling reservoir water in the presence of water-based mud filtrate, absorbance spectroscopy by itself is unable to differentiate among the fluids. Table 1 provides generic information about different fluid systems as well as the sensors used to differentiate the fluids. While there are other sources of correlation-based fluid-property information, the basic sensors mentioned are the ones used for correlations. As mentioned, each sensor provides detailed information for specific cases, but only sound speed provides a single-sensor solution for the conditions expected. Sound-Speed (SS) Measurement While acoustic data have long been used for reservoir characterization, data have been used for fluid characterization during downhole sampling for only a decade. Experience has shown that this measurement is sensitive enough to not only differentiate injection water or formation water but also to track and quantify small changes in oil compressibility—an important step in focused sampling. The measurement uses a pulse-echo technique based on the principle that an acoustic signal propagates approximately as a plane wave, and that the speed of sound is based on the distance the pulse travels divided by the time it took to traverse the distance. (SPWLA-2013-FFF). The 10-MHz piezoelectric transducer is mounted onto a machined flat surface on the flowline of RCX (the wireline formation testing tool reservoir characterization instrument) as schematically shown in Fig. 1. The travel path length is the distance between the two internal surfaces of the flowline. The result was a bulk measurement of the speed of sound across all the fluid flowing though the flowline. The only calibration needed is for this path length, which can differ due to slight machining variations. A calibrated sensor was able to differentiate fluids which exhibited sound-speed differences as small as 4.7 m/sec (0.5 msec/ft of sound-speed slowness).

Description: This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 30407, “Case Study of Nanopolysilicon Materials’ Depressurization and Injection-Increasing Technology in Offshore Bohai Bay Oil Field KL21-1,” by Qing Feng, Nan Xiao Li, and Jun Zi Huang, China Oilfield Services, et al., prepared for the 2020 Offshore Technology Conference Asia, originally scheduled to be held in Kuala Lumpur, 2–6 November. The paper has not been peer reviewed. Copyright 2020 Offshore Technology Conference. Reproduced by permission. Nanotechnology offers creative approaches to solve problems of oil and gas production that also provide potential for pressure-decreasing application in oil fields. However, at the time of writing, successful pressure-decreasing nanotechnology has rarely been reported. The complete paper reports nanopolysilicon as a new depressurization and injection-increasing agent. The stability of nanopolysilicon was studied in the presence of various ions, including sodium (Na+), calcium (Ca2+), and magnesium (Mg2+). The study found that the addition of nanomaterials can improve porosity and permeability of porous media. Introduction More than 600 water-injection wells exist in Bohai Bay, China. Offshore Field KL21-1, developed by water-flooding, is confronted with the following challenges: - Rapid increase and reduction of water-injection pressure - Weak water-injection capacity of reservoir - Decline of oil production - Poor reservoir properties - Serious hydration and expansion effects of clay minerals To overcome injection difficulties in offshore fields, conventional acidizing measures usually are taken. But, after multiple cycles of acidification, the amount of soluble substances in the rock gradually decreases and injection performance is shortened. Through injection-performance experiments, it can be determined that the biological nanopolysilicon colloid has positive effects on pressure reduction and injection increase. Fluid-seepage-resistance decreases, the injection rate increases by 40%, and injection pressure decreases by 10%. Features of Biological Nanopolysilicon Systems The biological nanopolysilicon-injection system was composed of a bioemulsifier (CDL32), a biological dispersant (DS2), and a nanopolysilicon hydrophobic system (NP12). The bacterial strain of CDL32 was used to obtain the culture colloid of biological emulsifier at 37°C for 5 days. DS2 was made from biological emulsifier CDL32 and some industrial raw materials described in Table 1 of the complete paper. Nanopolysilicon hydrophobic system NP12 was composed of silicon dioxide particles. The hydrophobic nanopolysilicons selected in this project featured particle sizes of less than 100 nm. In the original samples, a floc of nanopolysilicon was fluffy and uniform. But, when wet, nanopolysilicon will self-aggregate and its particle size increases greatly. At the same time, nanopolysilicon features significant agglomeration in water. Because of its high interface energy, nanopolysilicon is easily agglomerated, as shown in Fig. 1.

Description: Russia’s market influence as an exporter of liquefied natural gas (LNG) is growing, possessing the world’s largest reserves of natural gas and the logistical options to deliver it at competitive prices to Asia and Europe along the now-navigable Northern Sea Route (NSR). The country became a player in the LNG market when it shipped its first cargo in 2009 to Japan from what was then Russia’s first offshore gas project, Sakhalin-2 in the Far East, operated by Sakhalin Energy Investment Company Ltd. and owned by Russia’s pipe-line gas monopoly Gazprom (50% plus one share), Shell (27.5% minus one share), and Japan’s Mitsui (12.5%) and Mitsubishi (10%). Sakhalin Energy operates three oil and gas platforms producing its current resource base from the Piltun-Astokhskoye oil field and the Lunskoye gas field off the northeastern coast of Sakhalin. To date, Sakhalin Energy has sold all the LNG produced at its 11.49-mtpa-capacity Prigorodnoye LNG production complex on the southern tip of Sakhalin Island, under long-term contracts to buyers in the Asia Pacific and North America, according to Shell’s website. In 2024–2026, the partners say they will add a third train to expand capacity by 5.4 mtpa, though they have repeatedly delayed this expansion for years due to a lack of investment capital to develop a new resource base and low gas prices in Asia. The same holds true for Gazprom’s plan for an LNG plant near Vladivostok. However, the market has now changed with rising demand for gas to replace coal, giving gas producers an incentive to invest into new E&P gas projects and mid-to-downstream megaprojects like those for producing LNG. https://jpt.spe.org/compared-to-last-year-gas-prices-are-looking-good In 2018 and again this past January, European spot gas prices spiked on Gasunie’s leading TTF (title transfer facility) virtual trading platform and other European trading hubs when Asian gas markets began offering high premiums to divert LNG cargos from Europe, according to the EU Commission’s latest European Gas Market report. The Rise of a Russian IOC—Novatek in Yamal Russia’s largest independent natural gas producer Novatek was Russia’s second entrant into the LNG market when its Yamal LNG project rose above the permafrost atop an estimated 65,000 piles on the Yamal Peninsula, home to Russia’s largest gas deposits and the source of Russian pipeline gas sold into Europe. Yamal LNG shipped its first cargo (170000 m3) in December 2017. It then upped the ante with exports from a second train in August 2018, and added a third train in November 2018, according to Novatek’s website. Situated on the South Tambeyskoye field on the coast of Ob Bay, the plant boasts a capacity of 17.4 mtpa.

Description: This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 202747, “Fluid-Tracking Modeling for Condensate/Oil Production and Gas Use Allocation: An Abu Dhabi Onshore Example,” by Yun Wang and Gary Jerauld, SPE, BP, and Yatindra Bhushan, SPE, ADNOC, et al., prepared for the 2020 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, held virtually 9–12 November. The paper has not been peer reviewed. A reservoir in a giant field onshore Abu Dhabi has been producing for 6 decades. The reservoir was already saturated at the time of production commencement, with a large oil rim and a gas cap. This paper presents a comprehensive comparison of two modeling-based approaches of fluid tracking for condensate allocation and gas usage: a tracer modeling option in a commercial reservoir simulator and a full-component fluid-tracking approach. Introduction Examples of benchmarking fluid-tracking options against an independent fluid-tracking approach are rare in the literature. The goal of this paper, therefore, is to document a comprehensive and detailed comparison between the fluid-tracking option (TRACK) in NEXUS (a commercial reservoir simulator used by companies of the coauthors of this paper) and a full-component fluid-tracking (FCFT) approach. This work is motivated by the commercial arrangement of a concession covering an onshore field in Abu Dhabi. Because of different equity entitlements among the shareholders for the oil rim and gas cap per the concession commercial terms, a need exists to allocate the condensate vs. oil-rim oil production and the injected lean-gas usage. FCFT The idea of FCFT is relatively straightforward. Before discussing the approach, it is important to note that the focus of this paper is to compare the modeling of different tracking approaches. It is assumed that a fit-for-purpose fully compositional reservoir simulation model already exists. For fluid-tracking modeling with a full-field model (FFM), this means that the compositional reservoir model has already been history matched properly at both field and individual well levels and that no additional reconciliation is required before the hydrocarbon liquid and vapor streams are split into tracked substreams. In this paper, FCFT is completed on the field level for the comparison with the TRACK option in NEXUS. One could easily extend the field level tracking to either regional well-group levels or individual well levels. In the case of the onshore reservoir, lean-gas injection has been active during much of the producing history. In future development schemes under consideration, lean-gas injection, carbon dioxide (CO2) injection, and gas lift are all possible scenarios, raising the question of how to treat injected gas components within the FCFT framework. Different approaches exist to handle the injected gas components. One may treat the injected gas components as either the gas-cap components, the oil-rim components, or entirely new components. Lean gas injected in the onshore field example is actually a dry gas, according to the 11-component equation-of-state (EOS) prediction. Thus, the lean gas can be reasonably modeled with only one new component as long as that component replicates the volumetric behavior of the injected lean gas.

Description: The concept of a standalone production system on the seabed with automated wellbore construction and production processes has been an industry goal for a long time. Electrification of subsea facilities and of wellbore and reservoir equipment offers many opportunities to improve operational efficiency, reduce life-of-field capital and operating expenses, and reduce carbon footprint, among other benefits. Talk of a subsea electrification revolution being “just around the corner” has been ongoing for more than 20 years. And, millions of dollars in investments and numerous joint industry projects (JIPs) over the past decade have moved the vision closer to fruition (Fig. 1). But the upstream industry continues to lag others in replacing hydraulics with electrics. The reasons echo those for slow uptake of other new technologies and methodologies—fear of change, the unknown, and failure. Now, recent events are stirring up interest and expectations. “Four to five years ago, only a very small percentage of the buying community were making big noises about the future state of the electrified subsea or subsurface,” said John Kerr, subsea production systems and technology director for Baker Hughes, in a recent interview. “During the past 18 months the narrative has increased rapidly with many more operators looking at electrification as the base case for subsea solutions. We’ve seen a groundswell of interest to the point that we now see 3-, 5-, and 7-year lookaheads with electric solutions as the base case design concept,” Kerr said. What has changed? “Electrification of subsea devices has always been a solution to solve specific technical needs,” said Kerr. “The predominant one was extreme long-distance stepouts, where once you get to 250 miles or so, the ability to pump hydraulic fluids through small umbilicals presented so much pressure loss that it became impractical to implement a hydraulic solution, so all-electric became the solution of choice. Now we are seeing much more understanding of what electrification can deliver in the commercial and operational sense. “During the last 2 years, there has also been rapid adoption of dialogue around the aspect of increased carbon credentials and carbon reduction as an advantage,” Kerr continued. “The interest is much more comprehensive, driving different behavior in concept selection for operators.” Has the pandemic played a role? The consensus of participants in a subsea electrification panel at the virtual 2020 SPE Annual Technical Conference and Exhibition (ATCE) was that unless you’re surrounded by a crisis, you’re not encouraged to change. “The moment you put someone in a crisis situation, they understand that they have to change,” said Rory Mackenzie, leader for subsea electrical technologies at Total. “2020—the pandemic, oil price collapse, and environmental issues—this created a crisis. People are now much more open to considering change.” The panelists included Alvaro Arrazola, completions engineer, Chevron, North America Upstream; Glenn-Roar Halvorsen, project manager subsea all-electric, Equinor; Christina Johansen, managing director, Norway, TechnipFMC; Samantha McClean, intelligent wells technical advisor, BP; Rory Mackenzie, head of subsea electrical technologies, Total R&D; and Thomas Scott, global product line director, intelligent production systems and reservoir information, Baker Hughes. Edward O’Malley, director of strategy and portfolio, oilfield services, Baker Hughes, moderated the session.

Description: It is not unusual to compare a team of subsurface professionals to a team of detectives piecing together a sequence of events to solve a crime. To make sense of what is happening in a hydrocarbon reservoir, subsurface teams, like detectives, typically have incomplete, sparse data sets, sampled at different points in time and space. The data only provide a partial picture of what has happened and what is likely to happen in the future. In either case, surveillance is an essential tactic to build a mental model of the situation. Fortunately, both detectives and subsurface teams have growing surveillance toolboxes to help fill information gaps and narrow the range of possible scenarios. In the oil and gas industry, an endless set of questions can be asked to characterize the state and history of a hydrocarbon reservoir. Teams need to understand the capability of the reservoir to store fluids, stresses acting on the reservoir, what fluids exist and how they interact with each other and the rock, and how fluids are moving (or are likely to move) through the reservoir. Information, however, is rarely free, and different surveillance tools provide varying qualities of information, so it is essential for subsurface professionals to choose wisely in terms of which problems to solve and which tools to pull out of the toolbox. Ultimately, we need to apply the right tools to the right problems to maximize the value of the information we gather. In this feature, we will explore innovative approaches to help better understand the stress state of the reservoir, interactions between different fluids and rocks, and how to track the movement of specific fluid components throughout the reservoir. To do so, the authors of the papers highlighted in this month’s feature apply advanced log data analysis, experimental laboratory work, and compositional reservoir simulation, key tools that every subsurface team should have in its toolbox. Recommended additional reading at OnePetro: www.onepetro.org. SPE 201679 - A Fast Method To Estimate the Correlation Between Confining Stresses and Absolute Permeability of Propped Fractures by Faras Al Balushi, The Pennsylvania State University, et al. SPE 202224 - Downhole Surveillance During the Well Lifetime Using Distributed Temperature Sensing by Ludovic Paul Ricard, CSIRO, et al. SPE 201635 - Predicting Reservoir Fluid Properties From Advanced Mud Gas Data by Tao Yang, Equinor, et al.

Description: This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 31284, “Greater Tortue Ahmeyim Project for BP In Mauritania and Senegal: Breakwater Design and Local Content Optimizations,” by Alexis Replumaz, Yann Julien, and Damien Bellengier, Eiffage Génie Civil Marine, prepared for the 2021 Offshore Technology Conference, originally scheduled to be held in Houston, 4–7 May. The paper has not been peer reviewed. Copyright 2021 Offshore Technology Conference. Reproduced by permission. During summer 2017, the authors’ company was invited by BP to bid for the construction of a concrete caisson breakwater protecting an offshore liquefied natural gas (LNG) floating terminal at a water depth of 33 m on the Mauritanian/Senegalese maritime border. As a result of subsequent front-end engineering design (FEED) studies, including 3D model testing, the company was able to reduce the amount of concrete required by 40% compared with the initial design, leading to financial and environmental benefits. Introduction The BP Tortue development comprises a subsea production system tied back to a pretreatment floating, production, storage, and offloading (FPSO) unit, which transfers gas to a near-shore hub for LNG production and export. Phase 1 will provide sales gas production and domestic supply and will generate approximately 2.5 mtpa of LNG to Mauritania and Senegal. The Phase 1 FPSO, in 100–130 m of water, will process inlet gas from the subsea wells located across several drill centers by separating condensate from the gas stream and exporting conditioned gas to a hub, where LNG processing and export will occur. The hub, 10 km from shore, comprises a breakwater to protect marine operations, including LNG processing and carrier loading. A single floating LNG vessel will condition the gas for LNG export. Hub construction began early in 2019 and should be completed in 2021 for a first-gas target in 2022. The breakwater design was conceived during the bidding stage of the project at the end of 2017 by proposing an alternative design for the breakwater adapted to project-specific conditions and regional facilities. The design has been improved continuously and optimized during the FEED stage based on a collaborative approach between the client and the contractor. Client Preliminary Design Optimizations During pre-FEED and bidding stages, the client performed an intensive geotechnical campaign based on several shallow and deep boreholes and a large-area geophysical survey. In water depths greater than 18 m along the maritime boundary between Mauritania and Senegal, a significant layer of soft soil exists, except around the outcrop located on the west side (10–11 km offshore in approximately 33 m of water). Although rock quantities could be slightly higher in the western location, the reduction of the dredging quantities and the reduction of the effect on the nearby coastal community of Saint Louis (lighting, noise, and vessel traffic) led to selection of this location for the hub terminal. The initial breakwater type was a rubble-mound structure. However, a composite breakwater (caisson on berm foundation) allowed for optimization of dredging and rock quantities. The change in breakwater type allowed a rock-quantity drop from 5.8 million to 1.1 million m3.

Description: If you talk to a typical subsurface professional working on unconventionals today (e.g., a reservoir engineer, completion engineer, geologist, petrophysicist, etc.) as I have in person and through media such as LinkedIn, you will find that many lament one key thing: Our sophisticated models have been reduced too much. Of course, I am generalizing and those are not the words they use; the lamentations come in many forms. The dissatisfaction with oversimplification is most easily observed as dis-taste for the type curve, the simplified model we use to predict upcoming new drills. (Yes, I know many of you will want to refer to them by their “proper” name: type well curve; I will be sticking with the colloquial version.) A simple meme posted on LinkedIn about type curves garnered one of the most engaged conversations I have seen amongst technical staff. The responses varied from something like “Thank God someone finally said this out loud” to comments such as “I don’t know anything better than type curves.” Most comments were closer to the former than the latter. What is even more remarkable is that our investors feel the same. In personal conversations, many of them refer to our type curves simply as “lies.” This perception, coupled with the historical lack of corporate returns, led investors away from our industry in droves. Many within the industry see it differently and want to blame the exodus on other factors such as oil and gas prices, climate change, competition from renewables, other environmental, social, and governance (ESG) issues, the pandemic, or OPEC’s unwillingness to “hold the bag” any longer. If you ask them, though, investors will tell you a simple answer: The unconventional business destroyed way too much capital and lied too much through the type curves. Why is it that both investors and technical staff are unhappy with our ability to accurately model future performance? Why can’t we deliver returns? The typical unconventional-focused oil and gas company has two models that are critical to the business. First is the subsurface model, with which we are all intimately familiar in its various forms, and the second is the corporate financial model, which is focused on cash flows, income, and assets/liabilities. It is unfortunate that the two models are separate. It means we must simplify one or both so they can communicate with each other. How can you observe this oversimplification while it is happening? It is happening when the finance staff say, “Please just give me a simple type curve and well count; I need to model, optimize, and account for debt/leverage, equity, and cash flows.” Meanwhile, the technical staff say, “Please just give me a CAPEX budget or a well count; I need to model, optimize, and account for well spacing, completion design, land constraints, and operational constraints.” Looking back, we know that the winner in this tug-of-war of competing needs was the type curve.

Description: Helium is one of the most abundant in advanced medical technologies such as MRIs, and in cryogenics, aerospace applications, and microchip manufacturing. It is also used to fill party balloons. It’s essential, expensive, and supplies are running low. Helium is about 100 million times more abundant in one place—but that place is on the moon. While trace amounts can even be found in the very air we breathe, the gas is difficult to find in commercial quantities, and those quantities are usually found as a byproduct of natural gas discoveries. Historically, about 40% of the US supply of helium came from the Federal Helium Reserve, a US Bureau of Land Management (BLM)-operated storage reservoir, enrichment plant, and pipeline system near Amarillo, Texas. The reserve was set up in 1960 as a strategic repository so that BLM could supply crude helium to private helium refining companies, which in turn refined it and marketed it to consumers. In the mid-1990s, Congress passed a bill to sell off a large part of the reserve’s supply to help pay off the facility’s debt, and effectively set in motion the federal government’s exit from the helium business. In 2013, BLM said it would begin auctioning off an increased percentage of the reserve annually as part of the bill. Last year, BLM announced the closure of the reserve. At the time of the announcement, BLM Deputy Director for Policy and Programs William Perry Pendley said “now it is time for the US government to remove itself from the helium business and allow the private sector to further develop this industry to meet the supply needs of the United States, creating a sustainable economic model and jobs for Americans.” BLM held its final crude helium auction in 2019, with the price rising 135%, from $119/Mcf a year earlier to $280/Mcf. Market pricing for helium is difficult to know. It is not a traded commodity, and pricing is normally based on long-term, confidential contracts. It’s a niche market that suffers from a lack of detailed analysis due in large part to the availability of its closely held data. The helium industry shares many aspects of the oil and gas business. Commercial deposits are found via geological survey; then, once identified, drilling begins. Outside of the search and discovery, helium can also be a useful tool for those in the oil business. It can be used for leak detection and in specialized welding due to its inert properties and high heat transfer. Additionally, as the oil field moves more toward digitalization, storage of big data will need helium for the construction of storage drives and to keep server farms cool. Swapping Hydrocarbons for Helium As scientific developments advance, the need for helium increases—a notion not lost on Canada-based Avanti Energy. The company’s CEO Chris Bakker has more than 2 decades of experience in oil and gas, most recently working as a commercial negotiator with Encana/Ovintiv for major facilities and pipelines in the Montney gas play. Today, he and his team are looking for commercial helium deposits in southern Alberta and northern Montana.

Description: This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 202260, “Inversion of Advanced Full Waveform Sonic Data Provides Magnitudes of Minimum and Maximum Horizontal Stress for Calibrating the Geomechanics Model in a Gas Storage Reservoir,” by Zachariah J. Pallikathekathil, SPE, Xing Wang Yang, and Saeed Hafezy, Schlumberger, et al., prepared for the 2020 SPE Asia Pacific Oil and Gas Conference and Exhibition, originally scheduled to be held in Perth, Australia, 20–22 October. The paper has not been peer reviewed. In 1D geomechanics projects, calibration of stress is extremely important in the construction of a valid mechanical earth model (MEM). The effective minimum horizontal stress (Shmin) data usually are available from traditional measurements, but these have a few deficiencies. The complete paper presents a technique for deriving stresses in which the radial variation of acoustic velocity from an advanced dipole sonic logging tool is inverted to obtain stress. These derived stresses are then used to calibrate the 1D MEM for a gas storage field. Regional Geology The field is in the Otway Basin in Western Victoria. Gas is trapped in the Late Cretaceous Waarre formation at depths between 1155 and 1200 m subsea. The reservoir is sealed by the overlying marine Belfast mudstone, which is the common seal in the stratigraphy across the onshore Otway Basin. The reservoir has excellent reservoir quality and has proved ideal for gas storage. Challenge Posed by the 1D MEM Challenge Posed by the 1D MEM Well 1 was recently drilled in the basin. A 1D MEM - a numerical representation of the geomechanical properties and stress state of the earth at any depth - was planned to be constructed to obtain the current-day far-field principal stresses (Shmin), effective maximum horizontal stress (SHmax), and effective vertical stress (SV)] in the Belfast and Waarre formations. Understanding the stress field was important, especially in the caprock (Belfast) and in the reservoir (Waarre) so that the pressure limits for safe gas-storage operation could be defined better. However, for a variety of reasons, no conventional stress measurements were available to calibrate the modeled stress in the 1D MEM. Without any calibration of the stress, the geomechanics model would feature high uncertainty to be used to define the pressure operational limits for gas-storage operation. Fortunately, a new wireline sonic tool was recorded in the reservoir section and the overburden sections of the borehole in Well 1. A quick dispersion analysis of the waveforms showed that the Paaratte formation, above the Belfast formation, was acoustically stress-sensitive and that advanced processing could be performed to invert the acoustic information to stress values.

Description: For this feature, I have had the pleasure of reviewing 122 papers submitted to SPE in the field of offshore facilities over the past year. Brent crude oil price finally has reached $75/bbl at the time of writing. So far, this oil price is the highest since before the COVID-19 pandemic, which is a good sign that demand is picking up. Oil and gas offshore projects also seem to be picking up; most offshore greenfield projects are dictated by economics and the price of oil. As predicted by some analysts, global oil consumption will continue to increase as the world’s economy recovers from the pandemic. A new trend has arisen, however, where, in addition to traditional economic screening, oil and gas investors look to environment, social, and governance considerations to value the prospects of a project and minimize financial risk from environmental and social issues. The oil price being around $75/bbl has not necessarily led to more-attractive offshore exploration and production (E&P) projects, even though the typical offshore breakeven price is in the range of $40–55/bbl. We must acknowledge the energy transition, while also acknowledging that oil and natural gas will continue to be essential to meeting the world’s energy needs for many years. At least five European oil and gas E&P companies have announced net-zero 2050 ambitions so far. According to Rystad Energy, continuous major investments in E&P still are needed to meet growing global oil and gas demand. For the past 2 years, the global investment in E&P project spending is limited to $200 billion, including offshore, so a situation might arise with reserve replacement becoming challenging while demand accelerates rapidly. Because of well productivity, operability challenges, and uncertainty, however, opening the choke valve or pipeline tap is not as easy as the public thinks, especially on aging facilities. On another note, the technology landscape is moving to emerging areas such as net-zero; decarbonization; carbon capture, use, and storage; renewables; hydrogen; novel geothermal solutions; and a circular carbon economy. Historically, however, the Offshore Technology Conference began proactively discussing renewables technology—such as wave, tidal, ocean thermal, and solar—in 1980. The remaining question, then, is how to balance the lack of capital expenditure spending during the pandemic and, to some extent, what the role of offshore is in the energy transition. Maximizing offshore oil and gas recovery is not enough anymore. In the short term, engaging the low-carbon energy transition as early as possible and leading efforts in decarbonization will become a strategic move. Leveraging our expertise in offshore infrastructure, supply chains, sea transportation, storage, and oil and gas market development to support low-carbon energy deployment in the energy transition will become vital. We have plenty of technical knowledge and skill to offer for offshore wind projects, for instance. The Hywind wind farm offshore Scotland is one example of a project that is using the same spar technology as typical offshore oil and gas infrastructure. Innovation, optimization, effective use of capital and operational expenditures, more-affordable offshore technology, and excellent project management, no doubt, also will become a new normal offshore. Recommended additional reading at OnePetro: www.onepetro.org. SPE 202911 - Harnessing Benefits of Integrated Asset Modeling for Bottleneck Management of Large Offshore Facilities in the Matured Giant Oil Field by Yukito Nomura, ADNOC, et al. OTC 30970 - Optimizing Deepwater Rig Operations With Advanced Remotely Operated Vehicle Technology by Bernard McCoy Jr., TechnipFMC, et al. OTC 31089 - From Basic Engineering to Ramp-Up: The New Successful Execution Approach for Commissioning in Brazil by Paulino Bruno Santos, Petrobras, et al.

Description: As production chemists, we are all aware of the overall concepts of improved oil recovery (IOR) and enhanced oil recovery (EOR). Perhaps, though, fewer of us are aware of the different idiosyncrasies that exist within (and even between) these two broad categories of recovery and then how chemistry and chemicals can have an effect upon these processes. I would like to propose that the lines once were quite distinct between IOR and EOR: IOR was a standard waterflood operation, and EOR (from a chemist’s perspective) was the addition of chemistry to that waterflood (typically polymer or surfactant). Nowadays, the science has evolved massively to create many sub-genres of IOR and EOR. A waterflood is rarely just a waterflood anymore. We can alternate water and gas injection. We can add chemical conformance aids to direct better the flow of water. We can change the salinity of the water to promote better wettability for higher recovery factors. The list goes on. One just has to search out the number of EOR papers vs. (pretty much) every other discipline of production chemistry to see the commitment this industry still has to the research of this discipline. In recent years, the focus has tended to move away from deep-reservoir EOR to focus on near-wellbore stimulation. Interestingly, the mechanistic considerations that we make as production chemists are nearly identical in all cases, and significant synergies exist between these subdisciplines. Therefore, from the recent research published by SPE, two focused topics of IOR/EOR have arisen: the use of nanoparticles and the use of water-shutoff technologies. Nanoparticle use is gaining significant traction in the oil and gas industry, and field applications are now being reported. The area of IOR/EOR is no exception. Water shutoff is not a new technology area. However, are these established, production-sustaining IOR techniques seeing a resurgence caused by the headwinds our industry has faced during the COVID-19 pandemic? Recommended additional reading at OnePetro: www.onepetro.org. OTC 30123 - Thermal and Rheological Investigations on N,N’-Methylenebis Acrylamide Cross-Linked Polyacrylamide Nanocomposite Hydrogels for Water-Shutoff Applications by Mohan Raj Keishnan, Alfiasal University, et al. IPTC 20210 - Chemical and Mechanical Water Shutoff in Horizontal Passive ICD Wells: Experience and Lessons Learned in Giant Darcy Reservoir by Mohamed Abdel-Basset, Schlumberger, et al. SPE 203831 - Efficient Preparation of Nanostarch Particles and Mechanism of Enhanced Oil Recovery in Low-Permeability Oil Reservoirs by Lei Zhang, China University of Geosciences, et al.