ALBERT

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: 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: 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: 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: 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: 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.

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: 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: 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: 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.