Jersey Oil and Gas Unearths Wengen Prospect The Greater Buchan Area (GBA) now has four drill-ready prospects to add to discoveries already slated for development. In a new subsurface evaluation, Jersey Oil & Gas, a British-independent North Sea-focused upstream oil and gas company, has uncovered a new prospect, named Wengen, to complement its Verbier Deep, Cortina NE, and Zermatt drill-ready prospects. The four are estimated to host some 222 million bbl of P50 prospective resources, all in the immediate vicinity of Jersey’s planned GBA production facility. The consolidated Greater Buchan venture comprises Buchan field (80 million bbl), Verbier (c25 million bbl), J2 (c20 million), and Glenn (14 million). The new prospect, located in License P2170, is directly west of the Tweedsmuir field and should host some 62 million bbl of potential resources (P50), with the probabilistic range set at 31 million bbl at P90 (higher confidence) and 162 mil-lion for P10 (lower confidence). Probability of geological success is 22% for the prospect. Contractor Rockflow previously estimated the recoverable resources in the GBA at 94.7 million bbl, including the parts within P2170. In late November, Jersey announced it is taking full ownership of License P2170, which hosts most of the Verbier discovery, as part of the GBA. In March, Jersey told investors the project is fully funded and that it intends to take the project to potential industry partners via a farm-out process. An exploratory drilling campaign is being planned for 2022. Jordan Finds “Promising” Gas Reserves Near Iraq Border Jordan’s majority state-owned National Petroleum Company (NPC) has discovered “promising” natural gas in the Risha gas field along its eastern border with Iraq. Risha makes up nearly 5% of the kingdom’s consumption of natural gas of around 350 MMcf/D for power generation, Jordanian officials said. The flow of new gas supplies will raise the productivity of the gas field and help Jordan cut dependence on oil imports to fuel its power sector and industries. The country, which now imports over 93% of its total energy supplies, is burdened by a $3.5-billion annual bill, comprising almost 8% of Jordan’s GDP. Although British supermajor BP abandoned the eastern desert area in 2014 after investing over $240 million, Jordanian exploration has stepped up since 2019, boosting quantities by at least 70%, Mohammad al Khasawneh, head of NPC, said. An ambitious 10-year energy plan unveiled in 2019 aims to secure nearly half of the country’s electricity generation from local energy sources com-pared to a current 15%, according to Iraq Energy Minister Hala Zawati. The plan is meant to diversify local energy sources by expanding investments in renewable and oil shale to reduce costly foreign fuel imports, Zawati added. ExxonMobil Discovers Hydrocarbons Offshore Suriname ExxonMobil and Petronas have discovered several hydrocarbon-bearing sandstone zones with good reservoir qualities in the Campanian section of the Sloanea-1 exploration well on Block 52 offshore Suriname, adding to ExxonMobil’s finds in the Guyana-Suriname basin. The well was drilled by operator Petronas. ExxonMobil said in November that it is prioritizing near-term capital spending on advantaged assets with the highest potential future value. Maersk Drilling reported in early July that it had secured the Maersk Developer from Petronas subsidiary PSEPBV in a $20.4-million one-well exploration con-tract offshore Suriname. The semisubmersible rig drilled the Suriname-Guyana basin well to a total depth of 15,682 ft. “We are pleased with the positive results of the well,” Emeliana Rice-Oxley, Petronas’ vice president of upstream exploration, said. “It will provide the drive for Petronas to continue exploring in Suriname, which is one of our focus basins in the Americas.” Block 52 covers an area of 1.2 million acres and is located approximately 75 miles offshore north of Paramaribo. The water depths on Block 52 range from 160 to 3,600 ft. ExxonMobil E&P Suriname BV, an affiliate of ExxonMobil, holds 50% interest in Block 52. PSEPBV is operator and holds 50% interest. CNOOC Starts Production on Penglai 25-6 Oil Field Area 3 Project China National Offshore Oil Corporation (CNOOC) announced on 14 December that its Bohai Sea Project - the Penglai 25-6 oil field area 3 - has started production ahead of schedule. The biggest offshore oil field and the second biggest oil field in China, the Penglai is located in the south central Bohai Sea, with average water depth of about 27 m. In addition to fully utilizing the existing processing facilities of Penglai oil fields, the project has built a new wellhead platform and plans 58 development wells, including 38 production wells and 20 water-injection wells. The project is expected to reach its peak production of approximately 11,511 B/D of crude oil in 2023. Six successful appraisal wells were also drilled, which confirmed the presence of hydrocarbons in reservoirs located with-in Miocene, Lower Minghuazhen, and Guantao sandstones. The Penglai 19-3 oil field is located in Block 11/05 of Bohai Bay, approximately 235 km southeast of Tanggu. The production-sharing contract for block 11/05 was signed between CNOOC and ConocoPhillips China (COPC) in December 1994; the field was discovered jointly by CNOOC and COPC in 1999. The oil field was developed in two phases. Phase I production started in December 2002; production from the wellhead platform C, which is tied back temporarily to the production facilities of Phase I, began in June 2007. Since June 2020, CNOOC has announced five production startups: the Jinzhou 25-1 oilfield 6/11 area project, the Liuhua 16-2 oilfield/ 20-2 oil-field joint development project, the Nan-bao 35-2 oilfield S1 area project, the Luda 21-2/16-3 regional development project, and the Qinhuangdao 33-1S oilfield phase-I project. In Q3 2020, CNOOC achieved a total net production of 131.2 million BOE, which the company said represented an increase of 5.1% year over year. Production from China was said to have increased by 10.4% year over year to 88.6 million BOE. In November, CNOOC revealed that the Liuhua 29-1 gas field had begun production; in September, the company said the Bozhong 19-6 condensate gas field pilot area development project had also begun. Operator CNOOC holds 51% interest while COPC holds 49% interest in the Penglai 25-6 oilfield area 3 project. Equinor’s Snorre Expansion Project Starts Ahead of Schedule, Below Cost Work began in December on the Snorre Expansion Project in the southern part of the Norwegian Sea. This increased-oil-recovery project will add almost 200 million bbl of recoverable oil reserves and help extend the productive life of the Snorre field through 2040. The expansion project is proposed in blocks 34/4 and 34/7 of the Tampen area, approximately 124 miles west of Florø in the Norwegian North Sea. “I am proud that we have managed to achieve safe startup of the Snorre Expansion Project ahead of schedule in such a challenging year as 2020. In addition, the project is set to be delivered more than NOK 1 billion below the cost estimate in the plan for development and operation,” Geir Tungesvik, Equinor’s executive vice president for technology, projects, and drilling, said. Originally scheduled to come onstream in the first quarter of 2021, the project comprises 24 new wells divided into six subsea templates, drilled to recover the new volumes. Bundles connecting the new wells to the platform have been installed, in addition to new risers. The project also includes a new module and modifications on Snorre A. In December 2017, Equinor submitted a modified plan for development and operation of the field. With the expansion, the recovery factor will increase from 46 to 51%, representing significant value for a field with 2 billion bbl of recoverable oil reserves. Wind power will supply about 35% of the power requirement for the Snorre and Gullfaks fields. The Hywind Tampen project, featuring 11 floating wind turbines, should start up in Q3 2022. The investments in the expansion project total NOK 19.5 billion (2020 value). The project has had substantial spin-off effects for the supply industry in Norway, particularly in eastern Norway and in Rogaland. The Snorre field partnership comprises Equinor (operator) 33.27%, Petoro 30%, Vår Energi 18.55%, Idemitsu 9.6%, and Wintershall Dea 8.57%. Petrobras To Sell Entire Stake in Onshore Field of Sergipe Petrobras on 11 December signed a contract with Energizzi Energias do Brasil to sell its entire stake in the onshore field of Rabo Branco, located south of the Carmópolis field in the Sergipe-Alagoas Basin, Sergipe state. The Rabo Branco field is part of the BT-SEAL-13 concession. The $1.5-million sale is in line with Petrobras’ strategy to cut costs and improve its capital allocation, to focus its resources increasingly on deep and ultradeep waters. The average oil production of the field, from January to October 2020, was 138 B/D. Energizzi Energias do Brasil will own 50% stake in the Rabo Branco field; operator Produção de Óleo e Gás (Petrom) holds the remaining 50%. On 10 December, Petrobras closed the divestiture of its full ownership in four onshore fields at the Tucano Basin site in the state of Bahia. Petrobras sold its entire interest to Eagle Exploração de Óleo e Gás (Eagle). Petrobras earned $2.571 million from this sale, in addition to the $602,000 that the company received at the time of signing the sale contract, for a total of $3.173 million. BP, Reliance Announce First Gas From Asia’s Deepest Project Oil-to-telecom conglomerate Reliance Industries Limited (RIL) and BP have started production from India’s first ultradeepwater gas project, the first of three such projects in the KG D6 block. The R Cluster gas field is located off the east coast of India, about 60 km from the existing KG D6 control-and-riser platform (CRP), and comprises a subsea production system tied back to the CRP via a subsea pipeline. It is the deepest offshore gas field in Asia at a depth greater than 2000 m. The companies’ next project, the Satellites Cluster, is expected to come on stream this year, followed by the MJ project in 2022. These projects will utilize the existing hub infrastructure in the KG D6 block. “Growing India’s own production of cleaner-burning gas to meet a significant portion of its energy demand, these three new KG D6 projects will support the country’s drive to shape and improve its future energy mix,” BP Chief Executive Bernard Looney said. The R Cluster field is expected to reach plateau gas production of about 12.9 million standard cubic meters per day (MMscm/D) in 2021. Peak gas production from the three fields should be 30 MMscm/D (1 Bcf/D) by 2023, about 25% of India’s domestic production, and will help reduce the country’s dependence on imported gas. RIL is the operator of KG D6 with a 66.67% interest; BP holds a 33.33% participating interest.

Shell Explores Plans for North Slope Development Dutch oil major Shell is looking to further develop its North Slope oil position in Alaska. The company’s offshore unit applied to form the West Harrison Bay Unit offshore from the National Petroleum Reserve–Alaska with plans for drilling and exploration. The proposed West Harrison Bay Unit comprises 18 leases in West Harrison Bay approximately 34 miles northwest of the Colville River Unit. Shell holds 100% working interest in those 18 leases, covering more than 78,000 acres in the proposed unit. The company is identifying partners to share in the risk and costs, with plans to drill exploration wells in the West Harrison unit with at least one sidetrack each in 2023 and 2024. Because economic uncertainty from the pandemic and oil-price crash made negotiations difficult with potential partners, Shell requested the initial West Harrison Bay exploration plan to be for 5 years to allow enough time to find a partner and improve its plan. The wells would target the Nanushuk oil formation first identified by the Repsol-Armstrong Energy partnership in the Pikka Unit. The shallow, conventional formation also forms the basis of ConocoPhillips’ large Willow oil prospect to the south of Harrison Bay and is believed by many in the industry to be prolific across much of the western North Slope. Shell has been operating in Alaska since the 1950s when it began exploration in the Cook Inlet Basin. It acquired the West Harrison Bay leases in 2012, and redirected focus to the leases in 2017, generating five standalone prospects in the Nanushuk and multiple leads in the Torok formation and Jurassic Alpine-like plays.

This article, written by JPT Technology Editor Judy Feder, contains highlights of paper OTC 29925, “Slug-Flow Root-Cause Analysis: A Data-Driven Approach,” by Anders T. Sandnes, Vidar Uglane, and Bjarne Grimstad, Solution Seeker, prepared for the 2019 Offshore Technology Conference Brasil, Rio de Janeiro, 29-31 October 2019. The paper has not been peer reviewed. Copyright 2019 Offshore Technology Conference. Reproduced by permission. The complete paper discusses the successful application of a data-driven approach to analyze production data and identify root causes of slugging in a subsea production system on the Norwegian Continental Shelf. The approach used machine-learning techniques to model and analyze historical production data to identify the drivers behind slug flow. The results were used in combination with simulator studies and engineering experience to create a better understanding of the underlying root cause and to make it easier for field engineers to leverage all available information to reduce slugging and optimize production.

This article, written by JPT Technology Editor Judy Feder, contains highlights of paper OTC 30715, “Floating Production Systems: What’s Next?” by William Judson Turner, SPE, Welligence Energy Analytics, 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. The complete paper provides insight on the commercial drivers that significantly changed floating-production-system (FPS) design philosophy after 2014, with a particular focus on the US Gulf of Mexico (GOM). The paper explores near-term and longer-term outlooks for FPS design, touching on technology and automation that can relocate staff onshore to increase safety, reduce capital expenditure (CAPEX) and operating expenses (OPEX), and increase return on investment (ROI). The authors note that the commercial analyses presented in the paper are indicative and are subject to revision. Introduction The drastic fall of oil prices in late 2014 forced a harsh but necessary overhaul to the design philosophy of deepwater projects. Bigger was no longer better; the industry set to work using methods such as lean design and standardization for commercial improvement. Through a slow recovery in commodity prices and a steady persistence in innovating and implementing improvements, the deepwater sector made significant strides in commercial and operational efficiency. This overhaul was a rough 4-year journey as investment capital, and even some operators, retreated from deep water for lower-cost and faster-cycle onshore projects - at least, that was the perception at the time. Deep-water projects were delayed or canceled, and the industry saw consolidation among operators and the service sector. While the period may have been uncomfortable, it was a much-needed turnaround for an industry with average breakeven costs at $70 per barrel. The rework resulted in an industry fit to compete with onshore production, with breakeven costs reduced by half in some cases.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 30721, “Floating Offshore Windfarm Integrated Into Subsea Field Development: Case Study of the Saipem Windstream Concept,” by Benjamin Mauries, Giorgio Arcangeletti, SPE, and Christophe Colmard, Saipem, 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. Operators are moving active production and injection equipment onto the seabed with the aim of reducing capital expenditures (CAPEX) or topside space requirements. Moreover, they want to minimize new production floating facilities. Given this scenario, overall electric power needs may become an issue because of the extra power demand caused by the increasing number of electric consumers placed subsea. The complete paper discusses a floating wind-turbine solution that is particularly cost-competitive for deepwater locations and that can unlock the possibility of deploying large wind-powered generators far from the coastline in deep water. Introduction Saipem launched an initiative aimed at finding a solution for management of subsea field power demand bearing in mind two primary considerations: Minimize CAPEX by reducing the distance between the subsea-field production location and the topside equipment supporting this production Decarbonize the field by adopting a renewable energy source Concept Background and Potential Application The operator has developed a floating substructure technology for offshore wind farms known as HexaFloat. This concept uses a minimal floating hexagonal tubular substructure supporting wind-turbine tower and providing necessary floatability. The substructure is connected by tendons to a basket counterweight filled with solid ballast providing stability with pendulum-restoring forces. The assembly of the basket and the substructure behaves as a rigid body if all tendons are loaded. This assembly provides flotation with excellent stability thanks to the distance between the center of gravity and the center of buoyancy. Because this stability is provided by weight, large hydrostatic stiffness is unnecessary. As a result, only the central cylinder is exposed to the wave energy. The whole floating system can be anchored with three to six low-tension mooring lines, depending on environmental conditions.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 30709, “The Spar Platform: Transforming Deepwater Development,” by Anil Kumar Sablok and Tim Otis Weaver, TechnipFMC/Genesis, and John Edwin Halkyard, Deep Reach Technology, 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. The spar is the only successful dry-tree solution for deepwater production that can operate successfully in the deepest fields and the most severe environments. Its deep draft results in natural periods outside the range of waves, which has led to its wide acceptance for different field scenarios. The complete paper is an extensive review of the evolution of spar designs, focusing on the progression of work that ultimately led to the application of a transformative concept to the oil industry. Introduction The spar can support a drilling rig as well as top-tensioned production risers in water depths thousands of feet greater than the water depth limit for a tension-leg platform (TLP). It is especially well equipped to support steel catenary risers (SCRs) using the pull-tube option, which allows the SCR to serve as a continuous welded steel containment for hydrocarbons from the seafloor to the topsides and protects the riser from vortex-induced vibration in the fastest part of the current profile. Broadly speaking, there are three configurations of spars: classic, truss, and cell, with the common feature being that the center of buoyancy is higher than center of gravity. Table 1 of the complete paper lists all oil and gas spar production platforms that have been installed at the time of writing, in chronological order of installation. The complete paper devotes several pages to the spar’s initial development, including the crucial role of Edward Horton, the inventor and designer behind the spar production and storage concept and the TLP, and some of his colleagues. Years of development and navigation of various design challenges culminated in the installation of the Neptune spar in 1996 on time and budget. After the installation and success of Neptune , several other classic-design spars were implemented. The riser system on the Neptune spar had two unique features: buoyancy cans provided the tension, and the riser passed through a point of high bending and potential wear at the keel. The keel joint was a straightforward design; a sleeve around the main riser pipe pro-vided wear protection and distributed the bending in the riser to two endpoints rather than at a single contact point.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 30752, “The Tension Leg Platform: From Hutton to Big Foot,” by Steven J. Leverette, Leverette Offshore, and Stephen B. Hodges, Shell (Retired), 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. The complete paper is a comprehensive discussion of the development and deployment of the tension leg platform (TLP), one of the four major platform types that also include floating production, storage, and offloading (FPSO) vessels; semisubmersible floating production systems; and spar platforms. The authors summarize the evolution of the TLP during a nearly 4-decade span and provide a retrospective of the progression of TLP technology, including hull shapes, tendon connectors, flex elements, and riser systems. A Design Driven by Function Although the technology involved may be impressive, the authors remind that essentially it is merely a means of supporting a payload economically in deep water within required motion limits. The ultimate objective is to provide the most cost-effective, safe, reliable platform to meet functional requirements. After almost 50 years of deep water development, platform concepts have broadly stabilized into four categories of functionality: semisubmersibles, TLPs, spars, and ship-shaped FPSOs. Each of these concepts brings unique functionality with different cost/benefit tradeoffs. The driver behind the TLP concept was straightforward from an operator’s perspective: Provide a platform that behaves like a fixed platform with regard to the wells (i.e., dry trees; direct vertical access to wells; minimal tensioner stroke, allowing an array of wells in close proximity without giant tensioner systems such as those found on drilling semisubmersibles; and enabling export risers) in water depths much deeper than any fixed platform. This functionality, however, comes at a cost. While a semisubmersible may look similar in terms of hull and topsides, a TLP designed for the same payload requires 10 to 30% more displacement to provide the pretension in the tendons that keeps them in tension even in the most severe environmental conditions. The TLP also features 10 to 30% more freeboard to account for set-down at large offsets. While a semisubmersible, spar, or FPSO rides the tide and waves, a TLP acts like a fixed structure and, furthermore, is pulled down in the water geometrically at offset positions. The cost of this phenomenon must be offset by improved functionality. Thus, a large TLP with a full drilling rig and 24 wells can be an excellent choice for a large, centralized reservoir that can be drilled from a single location, but it makes little sense in developing a group of small reservoirs spread out over a region.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper 2019-1016 OMC, “Sulfur Removal on an FPSO: A Liquid-Redox-Process Case Study,” by William I. Echt, Merichem, prepared for the 2019 Offshore Mediterranean Conference and Exhibition, Ravenna, Italy, 27-29 March. The paper has not been peer reviewed. Eni began producing oil reserves from the Aquila reservoir in the Adriatic Sea soon after its discovery in the early 1980s. As primary production decreased, a decision was made to begin enhanced recovery with artificial gas lift. With the play in deep water (815 m) and 46 km off the southern coast of Italy, a floating production, storage, and offloading (FPSO) vessel was needed. After a 5-year run, the Firenze halted operations in 2018 because of low oil production. The complete paper examines the decision to use hydrogen-sulfide- (H 2 S) removal technology, the cost of operation, and the unit’s availability over its lifetime. Introduction As the industry searches for reserves in ever-deeper formations, the requirement of contending with sulfur increases. Several H 2 S-removal technologies are available, including nonregenerative liquid scavengers (triazine-based), nonregenerative solid-bed absorbents, and the regenerative liquid-reduction/oxidation (redox) process. These technologies remove sulfur from associated gas streams and do not release them to the environment. The nonregenerative technologies are often referred to as scavengers. Process Evaluation During the initial design phase, several H 2 S-removal technologies were evaluated per the following criteria: Turndown capability H 2 S-removal efficiency Degree of operator involvement required Maintenance requirement and waste material produced Proven reliability in marine conditions The evaluation led to the selection of the liquid-redox process after it received the highest marks in four of the five criteria. Both liquid and solid H 2 S scavengers were considered as alternatives to the liquid-redox process for this installation. The considerations for each criterion are detailed in the complete paper.

Welcome to the Offshore Facilities feature of this month’s JPT . It was my pleasure to review 161 conference papers submitted in this field during the past year. As noted in the May JPT, our offshore industry began January 2020 with its third-best year on record. The breakeven point (BEP) for deepwater projects prefinal-investment decision had fallen to approximately $50/bbl, and greenfield offshore development BEP was expected to reach below $40/bbl. In mid-January 2020, I attended and enjoyed the first International Petroleum Technology Conference in Saudi Arabia and witnessed an optimism across our industry. But all excitement changed unexpectedly in April 2020, when COVID-19 became a global pandemic, oil was oversupplied, and markets crashed. This low-oil-price situation is not the first in the history of our industry, and we again are going to see the challenges of reduction in demand; equipment; services, including financial support; asset and manpower excess reduction; and supply-change distraction. Yes, it is a cycle, and survival is the only mode to be able to move forward. However, what is different nowadays is that we should begin to propose a radical approach in how to improve our offshore development business cycle to be more agile and resilient. The COVID-19 pandemic accelerates transformative moments, particularly the search for the best strategy and innovation to secure offshore megaprojects not underpinned by higher oil prices. We have seen a drop of almost 20% in capital expenditures (CAPEX) this year, and Rystad predicted that total industry spending on exploration and production (E&P) will be cut by $100 billion by the end of the year and another $150 billion in 2021. As with previous downturns, three classical examples exist with regard to how offshore E&P companies typically react. First, capital spending is reduced. Second, projects are delayed. Third, companies reorganize. If we look back to 2014, the drastic fall of oil prices has successfully pushed more innovation and efficiency. The crisis is a catalyst to innovation. The new normal might become an opportunity to standardize unmanned offshore design. Radical thinking such as demanning and reuse of offshore oil and gas facilities might become a breakthrough to keep CAPEX and operational expenditures (OPEX) low. I have been fortunate to have some discussions with Robert Perrons, a professor from the Queensland University of Technology, about how to succeed at innovation with-in the industry under these conditions. He mentioned that the key for startups is to have the business case clearly articulated. Discussions about startups are far less likely to sound interesting unless you can explain to an operator how you can save them money right away. For offshore greenfield projects, standardization of design, efficiency of subsea technology, increase in digitization and automation, CAPEX/OPEX discipline, and increasing return on investment will trend after COVID-19. Meanwhile, for brownfield projects, digitalization and facilities debottlenecking can reduce OPEX significantly. Innovations related to nonintrusive and robotic methods for inspection also will be demanding after COVID-19. The three papers and recommended additional reading presented here support CAPEX/OPEX discipline, cost optimization, offshore development breakthroughs, and technology transformation. I hope you enjoy reading these papers as much as I did.

2020 set the stage for a profound transformation in the oil and gas industry. The oil and gas industry was already facing a challenging transition process as economies move toward a low-carbon future; however, surviving and prospering in a low-oil-price and high-risk environment is an even greater and more urgent challenge. Producers with relatively high-cost production will bear the brunt of production curtailments, since none are able to sustain uneconomic production for very long. In the years leading to 2019, shale plays stole the show, increasing production as long as prices sustained the frantic pace of drilling required for the production increases observed in the US. On the other hand, the intrinsic characteristics of deepwater plays - highly front-loaded investments and long project cycles - worked against them. Relatively low prices that were just as challenging for shale plays were considered a reason to delay deepwater projects (Rigzone 2016). Portfolio diversification is an important risk-mitigation strategy, whether by region, country, environment, or play type. However, for the majors of the industry, it is increasingly difficult and risky to rely on many relatively small projects to keep their portfolio pipeline full. Given the size of large companies, large projects are required to guarantee high levels of production over long periods and to keep their project portfolio manageable. Larger plays, and those that are less subject to environmental restrictions, tend to be found in large offshore basins, where deepwater plays dominate. At the same time, the world offers fewer opportunities with acceptable country risk. Thus, larger plays in safer regions have become essential elements of the core business of large oil and gas players. Besides offering the potential for large production, deepwater plays often can provide low Opex because of their scale and productivities, such as in the Brazilian pre-salt trend (the “pre-salt”), where many wells have consistently delivered sustained average production above 40 thousand BOPD (ANP 2020). Furthermore, deepwater plays involve large, complex projects that are well suited to the megaproject management capabilities of large players of the industry. Those projects are also amenable to technological innovations that have delivered impressive performance improvements and cost reductions. As an example, Petrobras claims that in 2020 its lifting costs for deepwater pre-salt fields have come down to below $3.00/bbl, and under $5.00/bbl including rig-leasing costs (Petrobras 2020a). As to innovation-related gains, two Petrobras programs represent unprecedented achievements in deep waters. Prod1000 expects to reach first oil within 1,000 days of a discovery, and Exp100 seeks to achieve a 100% discovery rate in exploratory wells, a feat that breaks the paradigm that has assigned high exploratory risks to deepwater exploration everywhere in the world (Petrobras 2020b). Existing infrastructure in deepwater plays has also become key in locating exploration and production (E&P) activities, since it can lower Capex and aid the viability of projects that would otherwise be uneconomical.

Despite uncertainties related to oil and gas industry dynamics and new requirements to reduce CO 2 emissions, energy demand is expected to continue to grow. It is also expected that the mix of energy shares will change significantly in the next 10-20 years. Natural gas and renewables (wind and solar) gradually will represent a larger part of the energy mix, balanced by a drop in reliance upon fossil fuels such as oil and coal. Some of the largest reserves of natural gas are located under deep waters, far from shore or any other existing infrastructure. Examples of areas where such field development is under way include western Australia, the North Sea, the Mediterranean, and southeast Africa. Among the many challenges often experienced in such fields is the requirement to transport gas in ultralong pipelines back to shore; in some instances, tie-backs are 100- to 250-km long and water depths can reach more than 2000 m. Subsea gas-compression technologies have been developed, tested, and successfully deployed in recent years, and operators now are using these technologies to make remote subsea gas fields profitable. Systems for subsea gas compression have reached Technical Readiness Level 7. After being in operation at the Gullfaks field and at the Åsgard field in the North Sea for several years, these technologies are now being considered for future field developments, not only in the North Sea but also in other parts of the world. In the Åsgard subsea-compression system, the gas condensate is separated subsea so that the gas can be compressed by a centrifugal compressor and the liquids can be pumped. Gas and liquid then are commingled downstream of the compressor station, and the mix travels in a pipeline to a processing facility 40 km away. The Gullfaks compression system uses a multiphase compressor technology that has been developed to handle mixtures of gas and liquid; hence, no separation or liquid pumps are required subsea. The result is that the weight and volume per unit of compression power are greatly reduced and the system becomes relatively small and less complex. Both operational experience and studies of future offshore gas-field developments are showing that subsea gas-compression systems not only reduce investment costs but also increase recovery significantly. New solutions, supported through relevant field studies, will be analyzed in the studies presented in this section.

This article, written by JPT Technology Editor Judy Feder, contains highlights of paper OTC 30667, “How Technology Enables a Lower Cost for Subsea Tiebacks,” by Fabrice Bacati, Giorgio Arcangeletti, SPE, Bruno Breuskin, Saipem, 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. The traditional subsea tieback model is evolving, supported by advances in flow assurance that allow tiebacks over much longer distances and by the introduction of new technologies that increase overall cost effectiveness. Paper OTC 30667 discusses several of these technologies, their maturity status, and how they can be integrated economically. Introduction During the past 15 years, operating companies have relied increasingly on effective subsea field-development solutions to eliminate the need for traditional platforms or vessels with topside processing facilities, particularly in geographically remote areas and small-pool developments of maturing brownfield areas. Technical and economic challenges include flow assurance and the cost of the umbilical and flowlines, which increase with length. These aspects, together with others independent of length, such as power and space availability, affect project economics significantly. Technologies developed recently or in their final stage of qualification can help not only in solving technical challenges but also in finding cost-effective configurations, either through reduction or re-apportioning of capital and operational expenditures, extension of reserves recoverability, or reduction of associated risks. The complete paper outlines several configurations, beginning with those enabled by conventional technologies, and compares them to those enabled by the new technologies. Each section of the complete paper discusses the subject technology’s composition, application, maturity, and impact on cost effectiveness. Subsea Boosting Subsea boosting systems that ensure pressure to enable production flow for the life of the field have matured during the last 10 years. Boosting can reduce backpressure at wellheads, and also can transport the production fluid at higher pressure to minimize flowline diameter and control possible instability issues. For gas fields, recovery can be increased by allowing the reservoir to deplete and then using compression to produce the field over a longer time. Currently, several boosting systems operate internationally. The type of pump technology used depends on the fluid to be boosted and the performance required. Single-phase pumps are used for water injection and oil boosting up to 15% of gas/volume fraction (GVF). Hybrid pumps are used for GVF up to 30%, and multiphase pumps for up to 95%. Subsea compressors are used for higher GVF.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 29391, “Bringing Forward the Next-Generation Multiphase Compressor,” by John Olav Fløisand, Bernt Helge Torkildsen, Joakim Almqvist, SPE, and Hans Fredrik Lindøen-Kjellnes, OneSubsea, prepared for the 2019 Offshore Technology Conference, Houston, 6-9 May. The paper has not been peer reviewed. Copyright 2020 Offshore Technology Conference. Reproduced by permission. In 2015, the world’s first subsea multiphase gas compression system was installed offshore Norway. The system comprises two-off 5-MW machines configurable for serial or parallel compression. This system has now gained considerable and valuable operational experience. The multiphase compressor not only ensures efficient power system compatibility but also can contribute to stepout topologies because of the low transmission frequency required for the power supply. Minimizing the complexity of both process and power architecture is crucial in terms of cost, robustness, and system reliability. Gullfaks Subsea Compression The realization of the subsea multiphase gas compression system was made possible through major technology investments during 2007-2012, including facilities, design models, and engineering as well as component and full-assembly qualification testing. This extensive technology-qualification program made the technology robust and reliable and enabled the engineering, procurement, and construction delivery of the subsea multiphase compression system to the Gullfaks field in March 2015 per schedule (Fig 1). The dynamic commissioning of the Gullfaks subsea wet-gas-compression (WGC) system was begun in July 2017. The work was first performed on both compressors in single mode to verify control-system functionality. Different wells and production lines were used to reach desired operation points. After initial commissioning, the compressors were run first in single mode and later in parallel at different suction-pressure setpoints. The system has been operating successfully since its commissioning in 2017. The subsea compressor system is boosting multiphase gas, increasing the production from several wells, and has recently achieved Technology Readiness Level 7. The system flexibility is exploited in extended ways compared with the initial project phase approach and allows the operator to take advantage of many opportunities, including increased oil recovery. Some key achievements of the system include increased oil production by kicking off dead wells and enabling stable well backpressures.

This article, written by JPT Technology Editor Judy Feder, contains highlights of paper 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, SPE, and Luis Ugueto, Wintershall Norge, prepared for the 2019 SPE Offshore Europe Conference and Exhibition, Aberdeen, 3-6 September. The paper has not been peer reviewed. The Vega field on the Norwegian Continental Shelf has been producing successfully using continuous monoethylene glycol (MEG) injection, topped with means of corrosion inhibition. A topside reclamation process allows reuse of MEG but limits the possibilities of producing saline water. The complete paper presents a discussion of a feasibility study of a new flow-assurance and -integrity philosophy to manage wells without continuous MEG injection. The paper describes options for hydrate and integrity management and the required modifications to both subsea and topside facilities to enable an operational philosophy change. Current Subsea Flow-Assurance Approaches Gas-hydrate formation in wet gas flowlines is considered one of the primary challenges seen in subsea assets. Its mitigation requires considerable capital expense and often significant operating expense (OPEX) over field life. Although the thermodynamic stability of the ice-like structures is well understood, the same is not the case for the kinetics of their formation or the dispersion in multiphase systems, which might be a crucial aspect in hydrate plug formation. Traditionally, the approach to hydrate mitigation has been to keep the system outside the hydrate-formation region by various means, including the following: Insulation of flowlines or direct heating possibilities Depressurization on shutdown Hydrate inhibition by thermodynamic or low-dosage hydrate inhibitors Subsea separation and drying of gas For long multiphase flowlines, options are limited. Insulation or direct heating often is uneconomical. Depressurization on shutdown requires significant storage space on a host facility for liquids and leads to massive volumes of flared gas. Subsea separation and gas drying are not yet fully mature, so use of hydrate inhibitors is common. Hydrate inhibitors can be classified as either thermodynamic or kinetic inhibitors. The latter are also called low-dosage hydrate inhibitors (LDHI) because of the lower concentration required. The main advantage of thermodynamic inhibitors is that they shift the hydrate curve to fully protect the system, whereas the kinetic inhibitors tend to wear off after time, leaving the systems un- or underprotected. However, their use often allows for infrastructure reduction and simplified production operations. The most typical thermodynamic inhibitors are based on salts (as from the formation water) or alcohols such as methanol, ethanol, or glycols. The advantage of the latter is that their separation from water is technically viable, so they can be used in a recycle, or closed-loop, system, which can only function well in systems free of salinity or with limited saline formation water ingress.

Lukoil Starts Drilling Caspian Sea Prospects Lynnmarie P. Flowers, Technology Editor Lukoil has begun wildcat drilling at an exploration well at the Shirotno-Rakushechnaya prospect structure, located north of the V.I. Grayfer field in the Caspian Sea. The well is at a water depth of 4.5 m and will be drilled to a target depth of 1650 m from Eurasia Drilling Co.’s (EDC) jackup rig Astra . The company said it also began studying the Khazri and Titonskaya features of a new block in the south part of the Caspian Sea, within the central Caspian license block in the East Sulaksky bank. It is drilling at the Khazri feature from EDC’s jackup floating rig Neptune to the target depth of 5200 m; the sea is 45 m deep at the point of well. Lukoil is constructing the sixth well at a riser block platform at the Yury Korchagin field. The length of the borehole of this horizontally directed producing well is 5165 m, and daily target production is 348 mt. The drilling is being done by EDC’s jackup rig Mercury. Since it began developing the Russian sector of the Caspian Sea in 1999, Lukoil has discovered 10 fields in the sector and has produced 7 billion BOE of recoverable hydrocarbon reserves. Petrobras Starts Production in Atapu Pre-Salt Petrobras started production of oil and natural gas from the shared deposit of Atapu, through platform P-70, in the eastern portion of the Santos Basin pre-salt, near the Búzios field offshore Brazil. The platform is the fifth floating, production, storage, and offloading (FPSO) of the series of replicants; it can process up to 150,000 B/D and treat up to 6 million m 3 of natural gas. The unit will operate in a depth of 2300 m, with an interconnection of up to eight producing and eight injection wells. Petrobras holds 89.257% of the rights to the deposit in partnership with Shell Brasil Petróleo (4.258%), Total E&P do Brasil Ltda (3.832%), Petrogal Brasil (1.703%) and PPSA, representing the Union (0.950%). With continued developments on the Iara, Mero, and Lapa projects, Brazil’s group production should reach 150,000 B/D by 2025, Total’s President of Exploration and Production Arnaud Breuillac said. Egypt: Twelve Deals Worth $1 Billion Egypt has completed 12 petroleum agreements worth at least $1 billion in addition to a $19-million signature bonus for drilling 21 wells, said Tarek E-Molla, Egypt’s Minister of Petroleum and Mineral Resources. These bills include eight projects for the Egyptian Natural Gas Holding Co. in the Mediterranean; Ganoub El Wadi Petroleum Holding Co.’s three projects in Blocks 1, 3, and 4 in the Red Sea; and Egyptian General Petroleum Corp.’s project in East Abu Sennan in the western desert. The agreements were made with several American, British, French, Emirati, and Kuwaiti companies including Chevron, Edison, BP, Total, Shell, Nobel, Kufpec, and Mubadala. Majors Partner To Develop Norwegian Shelf Aker BP, Equinor, and LOTOS Explo-ration and Production Norge AS have reached agreement on commercial terms to jointly develop the Krafla and Fulla region and the north of Alvheim area (NOA) on the Norwegian Continental Shelf. Total investments are forecast to exceed $5.2 billion. The area comprises several licenses and complex reservoirs that contain oil and gas discoveries with recoverable resources exceeding 500 million BOE. Equinor is the operator of the Krafla license and Aker BP operates the NOA and Fulla licenses. The parties are preparing to submit plans for development and operation of these fields in 2022. Their proposal calls for a processing platform in the south operated by Aker BP, an unmanned processing platform in the north operated by Equinor, and various satellite platforms and tiebacks. CNOOC Makes Discovery in South China Sea CNOOC Ltd, a branch of the China National Offshore Oil Corp., said in late June it had made a discovery at Huizhou 26-6 in the eastern South China Sea. The company said the discovery marked a “breakthrough” in the Paleo-gene and buried-hill complex oil and gas reservoir in the Pearl River Mouth Basin. This is its first time to achieve commercial and “highly productive” oil and gas flow in buried-hill exploration in the eastern South China Sea. CNOOC expects the field to become the first mid-to-large sized condensate oil and gas field in the shallow-water area of the basin. The field was tested to produce around 2,020 B/D and 15.36 MMcf/D. CNOOC encountered oil and gas pay zones with a total thickness of approximately 1,385 ft. In March, CNOOC made a “large-sized” discovery in Bohai Bay. Kenli 6-1 encountered oil pay zones with a total thickness of approximately 65 ft and produced around 1,178 B/D. Energean, Edison Slice $284 Million From E&P Deal Italy’s Edison has cut $284 million from the sale of its E&P business to Energean after excluding Algerian and Norwegian assets from the deal. Last year, Mediterranean-focused Energean agreed to buy Italy-based Edison’s oil and gas operations for up to $850 million, but the parties later revised the deal. In April, Edison’s Algerian assets, worth $155 million, were excluded from the scope of its sale to Energean, citing a lack of authorization from Algeria’s Ministry of Energy. Then in mid-May, Neptune Energy terminated its agreement to acquire Edison’s UK and Norwegian subsidiaries from Energean. The acquisition had been contingent on the closing of Energean’s acquisition of Edison, which is expected by the end of this year. Neptune would have paid up to $280 million for the North Sea producing, development, and exploration assets; it will pay Energean $5 million for cancelling the deal. Edison will retain control of Edison Norge, which controls the group’s upstream activities in Norway. The company’s E&P portfolio includes producing assets in Egypt, Italy, Algeria, the UK North Sea, and Croatia, as well as development assets in Egypt, Italy, and Norway. Energean will still acquire Edison’s UK North Sea subsidiaries, which include interests in the large Glengorm and Isabella gas-condensate discoveries. Energean said it still plans to complete the sale of Edison E&P’s UK and Norwegian subsidiaries to Neptune for $250 million plus contingent consideration of up to $30 million “as soon as reasonably practicable.” Energean has access to more than $1 billion in credit and debt to complete the development of the Karish and Tanin gas fields offshore Israel, where production is due to start early in 2021. Petrobras Sets New Production Records Offshore Brazil Brazilian oil and gas company Petrobras has reached a production record on Búzios field located in the Santos Basin pre-salt offshore Brazil. Petrobras reported that on 27 June, platforms P74, P75, P76, and P77 - installed on the Búzios field - had reached new production records of 664,000 B/D and 822,000 BOED. Petrobras says its 13 refineries in Brazil increased oil processing in May but are still operating below pre-COVID levels, rising to 1.645 million B/D from a 20-year low in April. In January, hydrocarbons output in Brazil topped 4 million BOED for the first time ever, as Petrobras reached plateau at four floating production, storage, and offloading vessels at the Búzios field. The field was discovered in 2010 and started production in April 2018 through the P74 FPSO; the rest of the units were subsequently added to the field. Saudi Aramco Suspends Contract With Seadrill Rig Saudi Aramco has suspended the contract for the Seadrill co-owned jackup drilling rig for up to 1 year. The 2013-built AOD II, an independent leg cantilever jackup, has an $89,900 a day contract with Saudi Aramco in Saudi Arabia. The 3-year contract was signed in April 2020. The rig is owned by Asia Offshore Drilling Ltd., which is co-owned by Seadrill and the Thai offshore services provider Mermaid Maritime. Mermaid said the suspension was due to the drop in crude oil prices and adverse impacts to the oil and gas industry, the offshore drilling services sector, and the “ultimate customer” - which likely is Saudi Aramco. The suspension, which had started on completion of the last well in progress, will be at a zero day rate and will extend the term of the contract for a period equal to the suspension, Mermaid said. Saudi Aramco has also suspended jackup contracts for Shelf Drilling’s High Island IV rig, and Noble Energy’s Noble Scott Marks. Petronas Hires Maersk Rig for Suriname Drilling Malaysian oil company Petronas has hired Maersk Drilling’s rig Maersk Developer for a one-well exploration campaign off the coast of Suriname. The campaign will take place in Block 52 which covers an area of 1,834 sq mi in the Suriname-Guyana basin. Maersk Drilling said the contract is expected to start in Q3 or Q4 2020, with an estimated duration of 75 days. The value of the contract is approximately $20.4 million, including integrated drilling services, mobilization, and demobilization fees. The contract includes an additional one-well option. In May, Petronas completed the farm-down of 50% of its participating interest in Block 52 offshore Suriname to ExxonMobil Exploration and Production Suriname. The Maersk Developer is a DSS-21 column-stabilized dynamically positioned semisubmersible rig, able to operate in water depths up to 10,000 ft. It is currently warm-stacked in Aruba following its latest contract offshore Trinidad and Tobago.

Large, unmanned floating facilities may be on course to become the embodiment of all that is promised by the oil and gas industry’s digital revolution. Fewer people working in remote corners of the globe, leaving behind fewer carbon footprints. Thanks to the advent of the internet-of-things, all systems are monitored from the safety of an onshore center. In the background, a digital twin peers into the future for equipment failures. Minor tasks, such as leak detection and corrosion monitoring, are done by a diverse cast of robots and fixed sensors. Bigger maintenance projects are performed by human crews who visit only once or twice a year via a service vessel - there will be no helipad. Also absent are any staff accommodations, cranes, or a control room. This is a quick snapshot of Aker Solutions’ latest version of an unmanned floating production, storage, and offloading (FPSO) vessel. The Norwegian offshore engineering firm has been iterating on the idea since at least 2017 when it promoted unmanned FPSOs to drive down offshore development costs. And while it remains today only an idea, there are just a few scalable barriers keeping an unmanned floater from being realized, according to Aker Solutions Senior Manager Anna Frostad. “The unmanned FPSO concept improves both field economy and HSE - and I therefore think this is the design for the future,” Frostad said during an online presentation of a technical paper (OTC 30905) she coauthored for the 2020 Offshore Technology Conference. In terms of savings, the paper suggests that the future owners of an unmanned FPSO will likely be oil companies that are committed to long-term results. To build one might only be 10% cheaper than to build a conventional FPSO. On the back end though, first adopters may see a reduction in typical operating expenses of up to 30%. Frostad emphasized that whoever is first must also adopt a “subsea mindset” and a very large digital tool box. She outlined three key elements to the subsea mindset: design simplicity, high-quality equipment, and a modular layout that enables a “plug-and-play” approach to replacing critical systems. Taking this approach conceptually also meant that the design engineers would need to forego the adaptation of existing FPSO designs. “The starting point was a blank sheet of paper,” with the overriding principle being that every system added to the design needed to be “justified in,” said Frostad. The result is what the company calls a lean design. From the highest level, the lean FPSO she described shares many of the same characteristics of a typical manned FPSO, including a tanker-shaped hull. The planned-for oil storage capacity is 1 million bbl, the maximum operating depth is 1000 m (about 3,280 ft), and its distance to shore is limited to 200 km (about 125 miles). As oil is stabilized on the topside, the natural gas is to be conditioned, compressed, and reinjected into the subsea reservoir.

There is a limit to disruptive innovation in oilfield technology. Blowout preventers (BOP) show how hard it can be. A decade ago on 20 April 2020, the Macondo disaster made a powerful case for change when this last line of defense failed to stop a blowout that caused explosions and a fire that killed 11, destroyed the Deepwater Horizon drilling rig, and set off one of the largest oil spills ever in the Gulf of Mexico. Scathing reports from investigations and staggering payouts from lawsuits against BP and other companies highlighted the shortcomings of machines that failed to serve as the last line of defense when natural gas surged onto the drilling floor, setting off a series of explosions. The investigations highlighted a long string of errors that led to the avoidable crisis. There was a failure to verify the cementing, missed signs of gas building up in the well, and a delayed decision to activate the BOP until the explosions already may have severed the hydraulic lines to the wellhead. But the simple explanation for it all: The shear rams failed to sever the pipe and seal the well. In the aftermath, well-control standards and regulations were rewritten and expanded. The changes required that old recommendations became requirements, and new ones were added, including a strong push toward real-time monitoring. The reports did not propose fundamentally redesigning BOPs. But for engineers with an inventive streak, this looked like a call to rethink the driving force behind these hydraulic devices where the fundamentals have changed little since the first patent was issued nearly 100 years ago. The arguments for rethinking BOPs included a 2003 study by West Engineering Services that found shear rams failed 7.5% of the time based on an estimate of the typical force required to cut pipe at the time. The force needed rises as casing gets tougher, water depths deeper, and well pressures higher, according to the study funded by what is now the US Bureau of Safety and Environmental Enforcement (BSEE). A Det Norske Veritas study for Transocean completed before the Macondo blowout found 11 situations where a BOP was activated in an emergency among the 15,000 wells drilled from 1980 to 2006. The BOPs only worked six times during that period, according to a story in The New York Times published in June 2010 - while the industry was scrambling to find a way to stop the Macondo leak. Different Perspectives The innovators range from startups to major offshore drillers. A Norwegian engineer started a company to sell a design for all-electric BOP stacks and an offshore drilling contractor developed an electric motor to retrofit into a BOP body. Engineers with military and space experience created cutting devices powered by gas generators using solid chemical propellants that send out high-pressure streams of gas when ignited by an electrical signal, similar to the deployment of an airbag or the thrusters on the Space Shuttle (this technology has been around for a long time).

Often located hundreds of miles away from land, offshore oil and gas platforms pose challenges with their unsheltered maritime environment, heavy weather, and risk of explosive, toxic, and corrosive atmospheres - with limited resources. Sounds like conditions are ripe for robots on rigs. In 14 years at Equinor, robotics researcher Anders Røyrøy has explored the application of robots in jobs that he describes as “dangerous, dirty, distant, or dull,” where use of a robot can serve to mitigate or eliminate safety risks for humans. One of the highest priorities for robotic development and deployment, in view of their impact on inspection and maintenance routines, are remote operators for onshore and offshore platforms. Failures in such harsh environments could jeopardize the lives of human operators, the environment, and process equipment. Semi- or unmanned operations can yield significant reductions in the risk of personnel exposure to dangerous chemicals. And in this age of social distancing, robots can be essential in providing contactless support. Traditionally, bases of design have been focused on improving the safety of existing manned installations sites (brownfield) - those not designed with robots in mind - during potentially dangerous operations. Although it is possible to enhance safety, efficiency, and production availability on a brownfield site, French supermajor Total E&P is challenging that approach by developing remote or unmanned robotic solutions for specific functions on greenfield sites - that is, on automated, unmanned platforms designed to accommodate newly developed technology. Generally unattended/unmanned installations are those that are visited only every 2 to 3 months. However, if the duration is pushed to one visit per year to perform annual maintenance tasks, it is possible to reduce the complexity of the platforms by removing equipment meant for human presence on site. There are several safety and cost advantages for operating remote production sites using robotics in place of crews. For example, without the presence of personnel on site, an operator can often remove human-related systems such as living quarters, catering, evacuation boats, and staff transportation to and from its installation, along with inherent risks and high costs. Fewer boats, helicopters, and less road transportation leads to reduced operating costs and CO 2 emissions. On such unmanned sites, Total is considering mobile, multipurpose, and ground robots that are ATEX-compliant (safe to operate in potentially explosive environments) and suitable for harsh and dangerous conditions. A fully autonomous robot can gain information about the environment, move around and work for an extended period without human intervention, avoid harmful situations (unless those are part of its design specifications), and learn new ways to execute its tasks while adapting to changing surroundings.

The offshore oil and gas sector has over the decades come to be defined by megaprojects with 30-to-40-year project horizons. But the future of offshore development will depend on the industry’s ability to find innovative ways to cut costs and slim the capital requirements. Many examples were to be shared with oil and gas professionals at the 2020 Offshore Technology Conference (OTC) in Houston. However, due to the COVID-19 pandemic, this year marked the first time that OTC was cancelled since its inauguration in 1969. Despite the global disruption, the flow of ideas continues. As proof, what follows is a curated summary of some of the papers that were to be presented at OTC. They were selected for their focus on emerging technologies and unique concepts that aim to reduce the cost burden long associated with offshore exploration and development. Their state of maturity ranges from proof of concept to fully deployed. Offshore Adoption of Predictive Analytics Among the most dominant technology arenas in the oil and gas industry’s digital transformation are fast-emerging machine-learning programs that enable predictive analytics. This paper (OTC 30782), produced by software developer Spark Cognition, offers two case studies that show how machine learning is being adopted in the offshore sector.

This article, written by JPT Technology Editor Judy Feder, contains highlights of paper OTC 29222, “Aasta Hansteen Spar FPSO—A Pioneer in Norwegian Deepwater,” by Torolf Christensen, Stig Arne Witsøe, and Helge Hagen, Equinor, et al., prepared for the 2019 Offshore Technology Conference, Houston, 6–9 May. The paper has not been peer reviewed. Copyright 2019 Offshore Technology Conference. Reproduced by permission. The complete paper describes the overall project execution of the Aasta Hansteen field development on the Norwegian Continental Shelf (NCS) north of the Arctic Circle. It is the deepest field yet developed on the NCS in 1300 m of water. In a harsh environment, with no other offshore installations in the area, the field is being developed with a spar floating, production, storage, and offloading (FPSO) structure using steel catenary risers and polyester mooring lines. Business Case The field is 300 km off the coast of northern Norway and 140 km from the nearest offshore installation. The field was discovered in 1997, with investment decision taken in December 2012 and production begun in December 2018. Total investment in facilities and infrastructure (including pipeline and modifications at Nyhamna) is approximately $7 billion. Equinor operates the field on behalf of its partners, Wintershall (24%), OMV (15%), and ConocoPhillips (10%). The field’s rich gas is exported through a 482-km-long, 36-in. pipeline to an on-shore processing plant at Nyhamna for further processing to sales gas. From there, the gas is exported to the European market. Stabilized condensate is stored in the spar FPSO and offloaded to shuttle tankers. The development of the field with the platform facilities and the Polarled pipeline was a strategic decision to open a new gas region in the Norwegian Sea and connect it to Europe by the NCS gas infrastructure. The development solution will serve as a gas hub enabling tie-in of future production from discoveries and prospects in the area. The objective of the Aasta Hansteen development is to maximize the recovery of the Aasta Hansteen reserves and to achieve maximum value creation in the value chain. Estimated recoverable reserves are 51 billion scm rich gas and 0.6 million scm condensate. The reserves consist of three separate discoveries—Luva, Haklang, and Snefrid Sør—all in the Nise formation and within the same production license. The development of Aasta Hansteen has been executed as a parallel development of the Polarled pipeline project to establish a new gas transport pipeline from Aasta Hansteen to Nyhamna. The pipeline has several tie-in points from Aasta Hansteen to the Nyhamna gas-processing plant. Snefrid Nord, the first subsea tieback development, is already being developed. The complete paper provides a brief description of the Polarled project.