Maha Appraisal Hits Gas for Eni in Indonesia Eni encountered natural-gas-bearing sands with its Maha 2 well in the West Ganal Block offshore Indonesia. Drilled to a depth of 2970 m in 1115 m water depth, the well encountered 43 m of gas-bearing net sands in levels of Pliocene Age, according to the operator. A production test, which was limited by surface facilities, recorded a gas deliverability of the reservoir flowing at 34 MMscf/D. The opera-tor collected data and samples during the test, to study in preparation of a field development plan for the Maha field. Two additional appraisal wells are planned for the discovery. Eni, along with partners Neptune West Ganal BV and P.T. Pertamina Hulu West Ganal, expect the field to be developed subsea and tied back to the nearby Jangkrik floating production unit (FPU), about 16 km to the northwest. Eni has been operating off Indonesia since 2001. Its current equity production in the region is around 80,000 BOE/D. Shell Sells Out of Philippines Gas Field Royal Dutch Shell has agreed to sell its stake in the Malampaya offshore gas field in the Philippines for $460 million. The major sold its 45% stake in Service Contract 38 (SC38), a deepwater license which includes the producing gas field, to a subsidiary of the Udenna Group, which already holds a 45% stake in the project. The divestment is part of the company’s strategy to narrow its oil and gas operations. The base consideration for the sale is $380 million, with additional payments of up to $80 million in 2022 and 2024 contingent on asset performance and commodity prices, according to Shell. The deal is due to complete by the end of 2021. The Malampaya gas field, discovered in 1991, currently supplies fuel to power plants that deliver about a fifth of the country’s electricity requirements, based on energy ministry data. Equinor Green Lights First Phase of Bacalhau Development Off Brazil Equinor, along with partners ExxonMobil, Petrogal Brasil, and Pré-Sal Petróleo SA, will move forward with a planned $8-billion Phase 1 development of the Bacalhau field in the Brazilian pre-salt Santos area. The Bacalhau field is situated across two licenses, BM-S-8 and Norte de Carcará. The target resource is a high-quality carbonate reservoir containing light oil. The development will consist of 19 subsea wells tied back to a floating production, storage, and offloading unit (FPSO) located at the field. The vessel will be one of the largest FPSOs in Brazil with a production capacity of 220,000 B/D of oil and 2 million bbl of storage capacity. The stabilized oil will be offloaded to shuttle tankers and the gas from Phase 1 will be re-injected in the reservoir. The FPSO contractor will operate the FPSO for the first year. Thereafter, Equinor plans to operate the facilities until the end of the license period. The development plan was approved by the Brazilian National Agency of Petroleum, Natural Gas, and Biofuels (ANP) in March 2021. First oil from the field is slated for 2024. Wintershall Strikes Gas at Dvalin North An exploration well drilled by Wintershall on its Dvalin North prospect in the Norwegian Sea has encountered a significant gas reservoir. The discovery at Dvalin North is estimated to hold to hold 33–70 million BOE and is just 12 km north of the company’s operated Dvalin field and 65 km north of the operated Maria field. The well also encountered hydrocarbons in two shallower secondary targets, with a combined resource estimate of 38–87 million BOE, making the potential for the field in excess of 150 million BOE. The well, drilled by the Deepsea Aberdeen rig, encountered gas, condensate, and oil columns of 33 m and 114 m in the Cretaceous Lysing and Lange formations, respectively. In the primary target in the Garn Formation, the well found a gas column of 85 m. The license partners, including Petoro and Sval Energi, are evaluating development options for the discovery, which could include a tieback to the Dvalin field. Third Odfjell Rig Tapped by Equinor Odfjell has been awarded a three-well, $40-million drilling contract for its semisubmersible drilling unit Deepsea Stavanger by Equinor. The rig will join sister units Deepsea Atlantic and Deepsea Aberdeen under contract with the Norwegian operator. The rig is scheduled to start drilling the first of three planned exploration wells in the North Sea in February 2022. The wells are expected to take about 4 months to complete. The contract includes continuing options after the initial phase. South Africa Shale Tests Encounter Gas at Karoo Pockets of shale gas were encountered during test drilling in the semi-desert Karoo region of South Africa, according to the nation’s energy ministry. A total of 34 gas samples had been bottled and taken to laboratories after the government’s Council for Geosciences set out to drill a 3500-m stratigraphic hole in the Karoo to establish and test the occurrence of shale gas. “The first pocket of gas was intercepted at 1734 m with a further substantial amount intercepted at 2467 m spanning a depth of 55 m,” said Gwede Mantashe, South African energy minister, during his budget vote in parliament on 18 May. In 2017, geologists at the University of Johannesburg and three other institutions estimated the gas resource in the Karoo was probably 13 Tcf. Earlier, the US Energy and Information Administration estimated the Karoo Basin’s technically recoverable shale-gas resource at 390 Tcf, then making it the eighth largest in the world and second largest in Africa behind Algeria. Seadrill Venture Nets New Drilling Contract Seadrill’s Sonadrill Holding Ltd., the 50/50 joint venture with an affiliate of Sonangol, has secured a 12-well contract with one option for nine wells and 11 one-well options in Angola for drillship Sonangol Quenguela . The $131-million contract before options is inclusive of mobilization revenue and additional services with commencement expected in early 2022 and running through mid-2023. The contract is contingent on National Concessionaire approval. Sonangol Quenguela is the second of two Sonangol-owned drillships to be bareboat-chartered into Sonadrill. The drillship is a seventh-generation, DP3, dual activity, e-smart ultradeepwater drillship delivered in 2019, capable of drilling up to 40,000-ft wells. A further two Seadrill-owned units are expected to be bareboat-chartered into Sonadrill. Seadrill will manage and operate the four units on behalf of Sonadrill. Shell Makes US Gulf Discovery at Leopard An exploration well at the Shell-led Leopard prospect in the deepwater US Gulf of Mexico encountered more than 600 ft net oil pay at multiple levels. Leopard is in Alaminos Canyon Block 691, approximately 20 miles east of the Whale discovery, 20 miles south of the recently appraised Blacktip discovery, and 33 miles from the Perdido spar host facility. Evaluation is ongoing to further define development options. According to Shell, Leopard is an opportunity to increase production in the Perdido Corridor, where its Great White, Silvertip, and Tobago fields are already producing. Meanwhile, the Whale discovery, also in the Perdido Corridor, is progressing toward a final investment decision in 2021. Shell operates Leopard with a 50% working interest. Partner Chevron holds the remaining 50% stake. Shell Could Leave Tunisia in 2022 Shell informed Tunisian authorities in May it will hand back upstream concessions and leave the country next year as it turns its focus to renewable energy, according to a Reuters report sourcing a senior official in the country’s energy ministry. The license in question is the Miskar concession in the southern city of Gabes. The operator has also requested the early hand-back of the Asdrubal permit, which expires in 2035. Recent reports suggest the operator may be looking for the Tunisian government to extend its permit on the field under more favorable terms ahead of its planned departure.

Angola Opens Congo, Kwanza Blocks in Ongoing Bid Round Angola’s National Oil, Gas, and Biofuel’s Agency has opened blocks for licensing in the Onshore Lower Congo Basin and the Onshore Kwanza Basin as part of its 2020 oil and gas licensing round. This latest call to tender is part of the agency’s ongoing 2019–2025 hydrocarbons licensing strategy. The Onshore Lower Congo Basin Blocks include CON1, CON5, and CON6; while the Onshore Kwanza Basin Blocks comprise KON5, KON6, KON8, KON9, KON17, and KON20. The round aims to expand research and evaluation activities across sedimentary basins, increase geological knowledge of Angola’s hydrocarbon potential, and invite a new wave of explorers to yield new discoveries. Raven Field Startup for BP in Egypt Natural gas has begun flowing from the BP-operated Raven field, the third stage of the company’s major West Nile Delta (WND) development off the Mediterranean coast in Egypt. The $9-billion WND development includes five gas fields across the North Alexandria and West Mediterranean Deepwater offshore concession blocks in the Mediterranean Sea. Raven is currently producing approximately 600 MMcf/D with a peak potential of 900 MMcf/D and 30,000 B/D of condensate. Raven follows the Taurus/Libra and Giza/Fayoum projects, which started production in 2017 and 2019, respectively. It produces gas to a new onshore processing facility, alongside the existing WND onshore processing plant. In total, the WND development includes 25 wells producing gas to the onshore processing plant via three long-distance subsea tiebacks. The onshore facilities—including the new Raven facility—now have a total gas processing capacity of around 1.4 Bcf/D of gas. All gas produced is fed into Egypt’s national grid. BP is the operator and has an 82.75% stake in the WND development, with Wintershall Dea holding the remaining 17.25% interest. CGX Secures Rig for Kawa-1 Well off Guyana CGX Energy and Frontera Energy, joint venture partners in the Petroleum Prospecting License for the Corentyne block offshore Guyana, have secured semisubmersible Maersk Discoverer to drill the Kawa-1 well. An early third quarter spud for the exploration well is targeting a Santonian age, stratigraphic trap, interpreted to be analogous to the discoveries immediately to the east on Block 58 in Suriname. The well is anticipated to be drilled to a total depth of approximately 6500 m in a water depth of approximately 370 m. The contract has an estimated duration of 75–85 days and has a one-well option attached. If exercised, that probe would spud in the nearby Demerara Block and take an estimated 40 days to reach its target. Talos’ Bulleit Reservoir in US Gulf Smaller Than Expected A technical assessment of the main producing sand performance at Talos Energy’s Green Canyon Block 21 Bulleit field in the US Gulf has indicated a smaller reservoir than originally anticipated. Project partner Otto Energy said the assessment included detailed bottomhole pressure and reservoir performance data collected after hookup and first production. The Block 21 field is flowing via a single subsea well tied back to a platform in nearby Green Canyon Block 18. While additional technical work is ongoing, the currently favored path forward is to move away from the current sand and execute a recompletion of the well in the shallower DTR-10 sand. A DTR-10 recompletion will require the procurement of long-lead items from manufacturers, which are expected to cost $3.5 million with payment expected in mid-2021. The recompletion is expected to begin in mid-2022, with production from the DTR-10 immediately following in mid-to late 2022. Captain Field EOR Stage 2 Project a Go Ithaca Energy, operator of the Captain field, has sanctioned the Captain Enhanced Oil Recovery (EOR) Stage 2 project in the UK Central North Sea after receiving Field Development Plan Addendum consent from the Oil and Gas Authority. EOR Stage 2 is designed to significantly increase hydrocarbon recovery by injecting polymerized water into the reservoir through additional subsea wells, subsea infrastructure, and new topsides facilities. Stage 1 of the project demonstrated that polymer EOR technology can work, with the production response in line with or better than expected across all injection patterns, helping maximize economic recovery. The Captain field was discovered in 1977, in Block 13/22a located on the edge of the outer Moray Firth. The billion-barrel field achieved first production in March 1997—over 24 years ago. Ithaca Energy holds 85% working interest, while partner Dana Petroleum holds the remaining 15%. Equinor Touts new Tyrihans Field Discovery Equinor and partners Total E&P Norge AS and Vår Energi AS have struck oil and gas in a new segment belonging to the Tyrihans field in the Norwegian Sea. Exploration well 6407/1-A-3 BH in production license 073 was drilled from sub-sea template A at Tyrihans North. The well was drilled to a measured depth of 5332 m by semisubmersible drilling rig Transocean Norge and struck a gas column of about 43 m and an oil column of about 15 m in the Ile formation, including about 76 m of moderate to good reservoir quality sandstone. In the Tilje formation, moderate to good quality water-bearing reservoir was struck. The Tyrihans field is in the middle of the Norwegian Sea, some 25 km southeast of the Åsgard field and 220 km northwest of Trondheim. The licensees consider the discovery commercial and intend to start production immediately. Recoverable resources are so far estimated at between 19 and 26 million BOE. Maersk Awarded Intervention Work off Brazil Maersk Drilling has been awarded a contract with Karoon Energy Ltd. for the semisubmersible rig Maersk Developer to perform well intervention on four wells at the Baúna field offshore Brazil. The contract is expected to begin in the first half of 2022, with a firm duration of 110 days. The value of the contract is $34 million, including rig modifications and a mobilization fee. The contract contains options to add up to 150 days of drilling work at the Patola and Neon fields. Carnarvon Completes Farmout of Buffalo Project Carnarvon Petroleum has completed the farmout of 50% of the Buffalo project to Advance Energy PLC. On 17 December 2020, Carnarvon announced that Advance Energy would acquire 50% of the Buffalo project off the west coast of Australia by funding the drilling of the Buffalo-10 well up to $20 million on a free carry basis. Advance met this funding requirement and now has a 50% interest in the project. The well is on track to be drilled in late 2021, subject to securing a drilling rig, where the tendering process is already underway. Following the well, the joint venture will acquire development funding from third-party lenders and any additional funding will be provided by Advance as an interest-free loan. The current plan is to suspend a successful well as a future producer and begin early development studies during 2021. Shell Hires Seadrill Rig for Brazilian Campaign Shell has contracted Seadrill’s drillship West Tellus for a new drilling campaign offshore Brazil this year. The program is expected to start in BC-10 of the Campos Basin, where Shell operates the Parque das Conchas made up of the Abalone, Argonauta, and Ostra fields. BC-10 has produced more than 100 million bbl since oil first started flowing from the block in 2009. The drillship will be used on the third phase of BC-10 activity, which includes five additional production wells and two water-injection wells at the Massa and Argonauta O-Sul fields, with the wells connected to the Espirito Santo FPSO. Shell owns a 50% operating stake in BC-10. India’s ONGC retains a 27% minority share and Qatar Petroleum the remaining 23%. Following the BC-10 work, the operator is expected to drill the first wells in the Campos Basin’s C-M-791 block, which was acquired during the 15th bid round held in 2017. Shell owns a 40% operating stake in the block, with Chevron retaining a 40% interest and Portugal’s Galp Energia the remaining 20%. Panoro Energy Kicks Off 2021 Drilling Campaign Offshore Gabon Panoro Energy has initiated its 2021 Gabon drilling campaign with the spudding of the Hibiscus Extension well on the Dussafu Marin Permit. That well will be followed by drilling at Tortue and Hibiscus North. Hibiscus and Tortue are two out of a total of six discovered fields within the Dussafu Permit offshore Gabon. Panoro currently holds a 7.5% interest in the license and has entered into an agreement to acquire an additional 10% working interest in the Dussafu Permit, bringing its total ownership to 17.5% following completion of the transaction. The Extension well is being drilled with the jackup Borr Norve and is the first well in a three-well campaign planned on Dussafu during 2021. The well is planned as a vertical well to test structure, oil, and reservoir presence in what is believed to be a possible northerly extension of the Gamba reservoir in the Hibiscus field. The well is positioned about 3 km northwest of the Hibiscus discovery well drilled by the joint venture in 2019. The initial well and its appraisal sidetrack established a 2P gross recoverable reserves of just over 46 million bbl at the Hibiscus field. The Extension well is expected to take around 30 days to drill and log to a total depth of 3500 m. Success at the probe could prompt one or two appraisal side-tracks to further delineate the field. Following the Hibiscus Extension, the rig will move to drill a horizontal production well, DTM-7H, at the Tortue field. This will complete the Phase 2 development of Tortue and, along with DTM-6H, will bring the total number of production wells at Tortue up to six. An exploration well at the Hibiscus North prospect, located approximately 6 km north-northeast of the initial Hibiscus well is also scheduled. Hibiscus North is a separate 10–40 million bbl prospect that could be tied into the Hibiscus/Ruche development project. Puma West Strike for BP in the US Gulf An exploration well at the Puma West prospect in the deepwater US Gulf has yielded a significant oil discovery for operator BP. The well, on Green Canyon Block 821, was drilled using Seadrill drillship West Auriga to a total depth of 23,530 ft and encountered oil pay in a high-quality Miocene reservoir with fluid properties like productive Miocene reservoirs in the area. Preliminary data supports the potential for a commercial volume of hydrocarbons. The Puma West partners will begin planning an appraisal program to better define the discovered resource. The discovery well has been suspended as a keeper well to preserve future utility. Puma West is located west of the BP-operated Mad Dog field and is approximately 131 miles off the coast of Louisiana in 4,108 ft of water. The Puma West is operated by BP with a 50% working interest. Partners include Chevron with 25% and Talos Energy with the remaining 25%. Petrobras Pushes First Oil at Mero Into 2022 Petrobras has postponed first oil from its Mero 1 field via the FPSO Guanabara in the Santos Basin offshore Brazil due to delays with the production system. Startup at Mero 1 was originally expected in the fourth quarter of this year and is now expected to begin flowing during the first quarter of 2022 due to COVID-19 pandemic-related delays with the buildout of the production system in China. The FPSO will be installed in the Mero field, which belongs to the Libra Block, in the Santos Basin pre-salt area, with a processing capacity of 180,000 OPD. The field is operated by Petrobras (40%) in partnership with Shell Brasil Petróleo (20%), Total E&P (20%), CNODC Brasil Petróleo e Gás (10%), CNOOC Petroleum Brasil (10%), and Pré-Sal Petróleo, which is the contract manager.

This article, written by JPT Technology Editor Judy Feder, contains highlights of paper SPE 201422, “Successful Mitigation of Fracture Hits in High-Pressure Stimulation Using Bottomhole Gauges and an Optimized Engineering Design, Offshore Black Sea,” by Gabrijel Grubac, SPE, Radu Patrascu, and Peter Janiczek, SPE, OMV, 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. This paper presents a case study of fracture interaction mitigation in a multistage horizontal stimulation of an offshore Black Sea well. The authors discuss a multifaceted approach in applying lessons learned and pre-job geomechanical analysis of depletion-induced stress differential and its effects on fracture interactions. Intrastage fracture interference presents unique challenges that typically are managed on a case-by-case basis. This study aims to present critical analyses that are paramount to planning stimulation treatments in highly depleted segments and reservoirs with close-proximity wells. Project Background The operating company began a field redevelopment project in 2013 for a field in the Black Sea that was already producing from horizontal wells with multi-staged fractured wells. The project comprises three treatment wells (A, B, and C) and seven offset wells (1 through 7). Because of time-critical operations and related costs, the original treatment wells and sidetracks (5,000-m-long measured depth horizontals) were completed with multistage stimulation sleeves and were operated by a ball-drop system from the surface. Infill drilling was implemented with the newly added sidetracks because of the maturity of the field and the desire to optimize the hydrocarbon drainage process. Well C was the first infill well. A multi stage fracturing campaign for Well C began in 2015. The complete paper presents a detailed discussion of issues—including strong fracture communication—identified, and mitigation steps attempted, during the infill project. Various simulation methods and depletion models that were tried and later rejected are also discussed. Several investigations were begun into how to predict, and subsequently avoid, fracture-driven interactions. Industry practice with huge quantities of water injection in the offset wells was not feasible because of the already-low economics of the treatment wells. A half-iterative process between reservoir modeling and fracture modeling was begun, and an actual reservoir pressure-depletion map was created on a sector basis. Similarly, the fractures were simulated using a grid-oriented fracture simulator in full 3D. Using this approach, it was also possible to match previously identified communication between wells and highly nonsymmetric fracture growth. The initial plan for the recent multi-stage fracturing campaign was to drill all wells closer in time to reduce localized depletion and to allow initial fractures from offset wells to act as a stress barrier to mitigate fracture growth in the direction of those wells. A matched reservoir and geomechanical model was used for the fracture simulation, and the actual depletion map for different time regimes was introduced. It was decided to redesign the fracture treatments and to shut in the offset wells 36 hours before the treatment, and to keep them shut in during the entire stimulation operation. At that point, it became clear that reservoir pressure depletion was one of the main causes of communication and also impeded optimal fracture geometries and hydrocarbon recovery.

Dugong Reserve Estimate Tightens on New Well Results Neptune Energy redefined the estimated reserves at its Dugong discovery in the Norwegian sector of the North Sea to between 40–108 million BOE based on the results of appraisal well 34/4-16 S. Prior to this appraisal, the operator believed the prospect could hold as much as 120 million BOE. The main objective of the well was achieved by establishing the oil/water contact. Neptune Energy said the new range will be subject to further detailed analysis and review, and a drillstem test on the well is planned at a later stage. The appraisal well was drilled using the Odjfell-operated semisubmersible Deepsea Yantai in about 330 m of water. The Dugong discovery will either be linked to nearby infrastructure or developed as a standalone development. Dugong is located 158 km west of Florø, Norway, and is close to the existing production facilities of the Snorre and Statfjord fields. The Dugong license partners are Neptune Energy (operator and 45%), Petrolia NOCO (20%), Idemitsu Petroleum Norge (20%), and Concedo (15%). Oselvar P&A Work Underway Decommissioning of the DNO Norge-operated Oselvar field has kicked off with the operator contracting semisubmersible Borgland Dolphin for plug-and-abandonment work. Oselvar is in the southern part of the Norwegian sector in the North Sea, 20 km southwest of the Ula field. The water depth is 70 m. Oselvar was discovered in 1991, and the plan for development and operation was approved in 2009. The field was developed via a trio of subsea wells tied to Ula. Production started in 2012 and ended in 2018. The Borgland Dolphin was moved to the field on 20 March. The rig recently went through a series of upgrades including the installation of new shale shakers, new standpipe manifold, an upgraded drilling control system, and an upgraded helideck. Decommissioning must be completed by the end of 2022. Equinor Green Lights FPSO for Brazil’s BM-C-33 Development Equinor, together with license partners Repsol Sinopec Brasil and Petrobras, have approved an FPSO-based development concept for BM-C-33, a gas/condensate field located in the Campos Basin pre-salt in Brazil. Subsea wells will be tied back to the FPSO located at the field. Gas and oil/condensate will be processed at the floater to sales specifications and exported. Crude will be offloaded by shuttle tankers and shipped to the international market after ship-to-ship transfer. A newbuild hull has been selected to accommodate the field’s planned 30-year lifetime. “BM-C-33 holds substantial volumes of gas,” said Veronica Coelho, Equinor’s country manager in Brazil. “A completion of the ongoing liberalization of the natural gas market in Brazil in line with the current plan, is key for the further development of the project. BM-C-33 is an asset that can generate value for the society, both through the creation of direct and indirect jobs, ripple effects, and through a gas supply that can induce industrial growth, as has happened in other countries.” Gas export capacity is planned for 16 million cubic meters per day with average exports expected to be 14 million cubic meters per day. Daily oil processing capacity is of 20,000 cubic meters per day. The gas-export solution is based on an integrated offshore gas pipe-line from the FPSO to a new dedicated onshore gas-receiving facility inside the Petrobras TECAB site at Cabiúnas, before connecting to the domestic gas-transmission network. Lundin Makes Small Discovery Near Edvard Grieg Lundin Energy Norway encountered a 10-m oil column with its wildcat well 16/4-13 S about 15 km south of the Edvard Grieg field in the central part of the North Sea. The operator added that about 7 m of the encountered column was of moderate to poor reservoir quality. The oil/water contact was encountered 1950 m below the sea surface. The entire reservoir, including the water zone, comprises conglomeratic sandstones in a thickness of about 380 m. Preliminary estimates place the size of the discovery between 0.5 and 1.4 million cubic meters of recoverable oil equivalent. The licensees will assess the discovery regarding a possible tie-in to the Solveig field. The well was drilled by Seadrill semisubmersible West Bollsta and will be permanently plugged and abandoned. The rig will now move to drill the 16/4-BA-1H production well on the Solveig field. Wintershall Gets Permit for Bergknapp Appraisal The Norwegian Petroleum Directorate granted Wintershall Dea Norge a drilling permit for well 6406/3-10 A to spud a follow-up probe to a discovery made in April 2020. The Bergknapp appraisal will be drilled from the Odjfell semisubmersible Deepsea Aberdeen once the rig has concluded the drilling of wildcat well 6507/4-2 S for Wintershall in production license 211. The Bergknapp appraisal will be drilled about 8 km west of the Maria field in the Norwegian Sea. The discovery well 6406/3-10 intersected an oil column of at least 60 m in the Garn formation and an oil column of at least 120 m in the Tilje formation. Preliminary estimates of the Bergknapp discovery indicate it could hold between 26–97 million BOE. The find is in production license 836 S where Wintershall is the operator and holds a 40% stake. The other licensees are DNO Norge (30%) and Spirit Energy Norway AS (30%). The area in this license comprises parts of Blocks 6406/2 and 6406/3. Guyana Says Liza Hits First-Phase Capacity Guyana’s President Irfaan Ali announced that the first phase of the Liza offshore crude project had achieved its intended full-production capacity of around 130,000 B/D. Ali told virtual attendees at the Guyana Basin Summit that he expected an additional 10 exploration and appraisal wells to be drilled off Guyana this year. He said the second phase of the Liza project, operated by ExxonMobil, would begin in 2022. The consortium led by Exxon, which includes partners Hess and CNOOC Ltd., has made 18 discoveries containing more than 8 billion bbl of recoverable oil and gas in Guyana’s Stabroek block. Equinor and Partners in Barents Bounty Equinor and partners Vår Energi and Petoro have struck oil in exploration well 7220/7-4 in production license 532 in the Barents Sea. Recoverable resources are so far estimated at between 31–50 million BOE. The well was drilled about 10 km southwest from the well 7220/8-1 on the Johan Castberg field. “Succeeding in the Barents Sea requires perseverance and a long-term perspective,” says Nick Ashton, Equinor’s senior vice president for exploration in Norway. “This discovery strengthens our belief in the opportunities that exist, not least around the Castberg, Wisting, Snøhvit, and Goliat areas.” The well, drilled by semisubmersible Transocean Enabler, struck 109 m of oil in the Stø and Nordmela formations. The top reservoir was encountered at a vertical depth of 1788 m below sea level. The expected gas cap was not encountered in the well. The well was not formation tested, but extensive data acquisition and sampling took place. Equinor said further development of the discovery toward the planned infrastructure for the Johan Castberg field will be considered at a later stage. Exploration well 7220/7-4 is the first of four planned exploration wells for Equinor in the Barents Sea this year. Eni Strikes Light Oil at Cuica Eni has made a new light-oil discovery in Block 15/06 at its Cuica prospect in the deep waters offshore Angola. The prospect is located inside the Cabaça Development Area and close to the Armada Olombendo FPSO (East Hub). Eni estimates Cuica could hold between 200 and 250 million bbl of oil in place. The Cuica-1 NFW was drilled as a deviated well by Seadrill-operated drillship Sonagol Libongos in 500 m of water and reached a total vertical depth of 4100 m, encountering an 80-m total column of reservoir of light oil (38 °API) in sandstones of Miocene age with good petrophysical properties. The discovery well is going to be sidetracked up-dip to be placed in an optimal position as a producer well. According to Eni, data collection from the well indicates an expected production capacity of around 10,000 BOPD. Cuica is the second significant oil discovery inside the existing Cabaça Development Area. The well location, intentionally placed close to East Hub’s subsea network, will allow a fast-track tie-in of the exploration well and relevant production. Eni expects the well could be on line within 6 months. Following the discoveries of Kalimba, Afoxé, Ndungu, Agidigbo, Agogo and appraisals achieved between 2018 and 2020, Cuica represents the first commercial discovery in Block 15/06 after the relaunch of the exploration campaign post-2020 COVID-19 pandemic. The discovery confirms the exploration potential of the block. A 3-year extension of the exploration period of Block 15/06 was recently granted until November 2023. The Block 15/06 joint venture comprises Eni (operator, 36.8421%), Sonangol P&P (36.8421%), and SSI Fifteen Ltd. (26.3158%). No Injuries Reported in West Mira Incident An equipment failure onboard Northern Ocean semisubmersible West Mira resulted in production equipment descending to the seabed. The rig owner said no one was injured and the well at the location was secured “with three barriers in place.” The unit was in the process of lowering the equipment on the Wintershall-operated Nova field. “While lowering a x-mas tree from West Mira, the winch wire snapped when the tree was five meters below the sea surface. The x-mas tree sunk to the seafloor 368 meters below water level. Eight people were working in the area of the rig where the incident occurred in safe distance from moving equipment,” said Wintershall. The rig manager, Seadrill Europe Management AS, and Wintershall are conducting investigations into the incident and have agreed to a plan to secure the production equipment. “A remote operated vehicle (ROV) was sent to the seafloor to assess the situation,” added the oil company. “The ROV survey showed no risk of discharge of well fluids or hydrocarbons and the x-mas tree has been localized on the template.”

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 200466, “Proxy-Based Assisted History Matching and Well-Spacing Optimization in Shale Gas Development of a Real Field Case,” by Chuxi Liu, The University of Texas at Austin; Wei Yu, Sim Tech and The University of Texas at Austin; and Cheng Chang, PetroChina, et al., prepared for the 2020 SPE Improved Oil Recovery Conference, originally scheduled to be held in Tulsa, 18–22 April. The paper has not been peer reviewed. A robust, reliable work flow for well-spacing optimization in a shale reservoir development incorporating various types of uncertainties and detailed economics analysis is necessary for achieving sustainable unconventional production. In the complete paper, the authors describe a novel well-spacing-optimization work flow based on the results of assisted history matching and apply it to a real shale gas well, incorporating uncertainty parameters such as matrix permeability, matrix porosity, fracture half-length, fracture height, fracture width, fracture conductivity, and fracture water saturation. Introduction The work of well-spacing optimization is significant because it will subsequently dominate the planning of the drilling job and completion job and ultimately will affect recovery efficiency. The purpose of well-spacing optimization serves to maximize either capital revenue or ultimate recovery. The greatest challenge for well-spacing optimization is how to interpret the uncertainties associated with unconventional reservoirs. Stimulated reservoir volume and external reservoir volume, effective fracture half-length vs. propped half-length, matrix permeability, and complex structural geology are examples of such challenges. Therefore, developing an efficient and trustworthy work flow for optimizing well spacing in any shale reservoir is critical. Previous work on unconventional shale well-spacing optimization includes operator data analysis and numerical and analytical simulation. However, almost all previous studies ignored the effects of uncertainties. In addition, most studies require input information regarding the reservoir of interest. One method to obtain such information is to history match the production data, and a few history-matching methods have been explored and analyzed. Nevertheless, traditional history-matching methods could not overcome the problem of high-dimensional uncertainty space, as is commonly seen in unconventional development. Because of this, more- stochastic approaches have been developed and applied. These methods use the concept of proxy to minimize simulation runs and are also able to obtain as many, or more, history-matching realizations. Furthermore, Markov-chain Monte Carlo (MCMC) algorithms usually are coupled with the proxy model in assisted history matching. This method could be helpful in finding the complex posterior distributions of multiple uncertainty variables with ease.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 201346, “Are We Overstimulating Our Laterals? Evaluating Completion Design Practices Based on Field Offset Well-Pressure Measurements,” by Puneet Seth, SPE, The University of Texas at Austin, and Brendan Elliott, SPE, and Trevor Ingle, SPE, Devon Energy, 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. Increased injection volumes coupled with a suboptimal completion design can lead to overstimulation at current well-spacing densities. In the complete paper, the authors analyze offset well-pressure measurements in the Permian Basin to evaluate if a fracturing job is overstimulated. Additionally, numerical modeling studies are performed to evaluate the extent of overstimulation in different scenarios and provide recommendations to maximize the capital efficiency of a fracturing job. In their analysis, the authors focus on the scenario in which fracturing hits occur when child-well fractures intersect with the parent well. Field Data Analysis Pumping for the full designed volume and time (typically 90 minutes) according to well-stimulation procedures is currently common in the industry. Often, the observation of hydraulic interactions is not coupled with a decision to alter or change the stimulation. The authors analyzed the offset well-pressure response monitored with a surface pressure gauge in multiple parent wells in the Permian Basin during stimulation in nearby child wells. The child wells were stimulated after roughly 1 year of production from the parent wells. The focus of this study was to identify fracture-driven interactions—specifically the timing of intersection of the child-well fractures with the offset parent wells, which are recorded as massive hydraulic pressure responses. The results of this analysis for different well pairs are presented in the complete paper. To better understand the factors that affect fracture propagation from the child wells toward the parent wells, fracture arrival times, and capital efficiency of a fracturing job, a series of numerical simulations was performed with a fully coupled hydraulic fracturing simulator. Simulation Results Numerical simulations were performed using an integrated hydraulic fracturing and reservoir simulator developed at The University of Texas at Austin. This simulator solves for flow and geomechanics in the reservoir, fracture, and wellbore domains in a tightly coupled manner. Hydraulic fractures are modeled as compliant discontinuities in the reservoir rather than high-permeability gridblocks. This is important in order to capture the stress alterations around a propagating fracture accurately. Effect of Parent-Well Production (Depleted Region). For this study, two scenarios were analyzed. In the first case, fracture propagation from a child well stimulated near a recently fractured unproduced parent well (no depletion) was considered. In this case, the fracture from the child well propagates away from the parent well because of elevated stresses near the parent well. In the second case, a child well is stimulated near a parent well that has been producing for 300 days before child-well stimulation. In this scenario, the child-well fracture propagates toward the parent well because of a depleted region that develops near the parent well (because of production) and relaxes the reservoir stresses around the parent well. This causes the child-well fracture to grow preferentially toward the parent well (toward the low-stress region). In fact, in this scenario, as the fracture reaches the depleted reservoir region, its growth accelerates toward the parent well and intersects with the parent well. Even minor depletion can induce asymmetric growth of infill child-well fractures toward the parent well.

Shell Selling Onshore Egypt Assets Shell Egypt and one of its affiliates have signed an agreement with a consortium made up of subsidiaries of Cheiron Petroleum Corporation and Cairn Energy PLC to sell its upstream assets in Egypt’s Western Desert for a base consideration of $646 million. Additional payments of up to $280 million between 2021 and 2024 will be made contingent on the oil price and the results of further exploration. The transaction is subject to government and regulatory approvals and is expected to complete in the second half of 2021. The package of assets comprises Shell Egypt’s interest in 13 onshore concessions and the company’s share in Badr El-Din Petroleum Company. Shell will shift its exploration focus in Egypt offshore, which includes seven new blocks in the Nile Delta, West Mediterranean, and Red Sea. Chevron Begins Production From Sarta-2 Well in Iraq Chevron has started production from the Sarta-2 well at the Sarta field in the Kurdistan region of Iraq, partner Genel Energy said. Gross field production now stands at more than 10,000 B/D. Sarta production is expected to increase from the existing two producing wells as facility optimization continues after production startup. A fresh appraisal drilling campaign is scheduled to begin soon, with the Sarta-5 and Sarta-6 wells set to be drilled back-to-back. Chevron is operator of the Sarta production-sharing contract (50%) with partners Genel Energy (30%) and the Kurdistan Regional Government (20%). Colombia Eyes Licensing Round Results in November Colombia is expected to soon reveal the schedule for its 2021 licensing round offering 32 blocks for oil and gas exploration, with results expected in November. In 2020, the nation awarded three areas to Canada-based companies Parex Resources and Canocol Energy despite the double-whammy of crashing crude demand and a global pandemic. With oil prices on the mend and an aggressive vaccine dissemination program, Colombia is hopeful that interest in its oil and gas acreage returns to pre-pandemic levels. The National Hydrocarbon Agency (ANH) expects to award at least half of the available tracts, which are part of more than 500 areas identified by the ANH in the country and include mature fields, emerging basins, and bordering areas. Exploration in Colombia fell dramatically in 2020 with only 18 wildcats drilled vs. the 45 planned, with most of the expected investment deferred to 2021-2022. While the country has allowed pilot projects testing for unconventional oil, there currently is a ban on fracking operations in the country. Israel Begins Prep Work for Fourth Offshore Round Israel’s Ministry of Energy has announced plans to launch the fourth offshore bidding round (OBR 4) for exploration licenses in the country’s exclusive economic zone soon. OBR 4 is part of a multiyear program to encourage the exploration and development of Israel’s natural resources to provide low-cost, environmentally friendly energy to Israel’s consumers and businesses and to develop markets for Israeli natural gas beyond its borders. As in OBR 2, the Ministry is planning to offer several zones to qualified companies, with each zone comprising approximately four licenses having a total area of up to 1600 sq km. Around 25 exploration licenses (blocks) have been mapped and will be grouped into six clusters. The exact dates of the stages of the bid round and grouping of the licenses in clusters will be determined later. No decision has yet been made on the winner of the license for natural gas and oil exploration in Block 72 in the third competitive bid round carried out in 2020. The Ministry will announce the formal commencement of OBR 4 and its delineation in the near future and provide detailed information on its website www.energy-sea.energy.gov.il at that time. Exxon Drills Dud at Bulletwood Offshore Guyana Exxon encountered noncommercial hydrocarbons with a test of its Bulletwood prospect in the Canje Block in the Guyana-Suriname basin. The well, located in 2846 m of water, was drilled to its planned target depth of 6690 m using drillship Stena Carron . Data collection from the Bulletwood-1 well confirms the presence of the Guyana-Suriname petroleum system and the potential prospectivity of the Canje Block, said partner Westmount Energy. Bulletwood-1 was the first of three scheduled wells to be drilled on the block in 2021. Wells Jabillo-1 and Sapote-1 are expected to spud over the coming months. Exxon operates the Canje Block via its Esso Exploration and Production Guyana unit, which has a 35% stake. Total has 35%, JHI 17.5%, and Mid-Atlantic Oil & Gas 12.5. Westmount holds a 7.7% stake in JHI. While the well results were disappointing, Exxon’s success rate in the area is still around 80% from 18 wells and expects its production from the region to reach 750,000 B/D by 2026. Neptune Earmarks $150 Million for Exploration and Appraisal in 2021 UK-based independent Neptune Energy said its exploration and appraisal spend for 2021 will remain flat at around $150 million. The company said it had up to 11 wells planned for the year including followup wells at the Dugong and Maha discoveries as well as a wild-cat at Dugong Tail. Dugong was discovered in the Norwegian portion of the North Sea in 2020. Neptune believes the prospect holds between 40–120 million BOE. Dugong is located 158 km west of Florø, Norway, at a water depth of 330 m, and is close to existing production facilities. The Dugong prospect comprises two reservoirs that lies at a depth between 3250–3500 m. The Maha discovery offshore East Kalimantan is estimated to hold gas resources in excess of 600 Bcf. In 2019, Neptune and its partners, Eni (operator) and Pertamina, were awarded the West Ganal production-sharing contract that holds the Maya find. An exploration well targeting the Dugong Tail prospect, adjacent to the south of the Dugong find, is slated for the third quarter of this year and will be drilled using Odjfell semisubmersible Deepsea Yantai. Interest Wanes in Norway’s Arctic Frontier Seven companies applied for new acreage in the Barents Sea in Norway’s latest licensing round, down from 26 in a similar round in 2013. The government had offered 125 new blocks in eight frontier regions of the Barents. More than 60% of the undiscovered hydrocarbons offshore Norway are in the Barents frontier, according to the nation’s petroleum directorate. However, appetites for frontier drilling have diminished as oil prices weakened and recent results from the region have disappointed. Companies that applied for the new acreage round were Norske Shell, Equinor, Idemitsu Petroleum Norge, Ineos E&P Norge, Lundin Norway, OMV Norge, and Var Energi. Oman Transfers Ownership of Massive Block 6 The government of Oman has transferred its stake in one of the Middle East’s largest oil blocks to a newly established firm. By royal decree, the new, state-controlled Energy Development Oman (EDO) will hold the country’s 60% stake in Block 6. The stake was moved from Petroleum Development Oman (PDO), another government-run company. Oman, which is struggling under a soaring budget deficit, is looking to finance its spending by leveraging its energy assets. Block 6 has a production capacity of 650,000 BOED. Shell holds 34% in the block, while Total holds the remaining 4%. The government appointed Haifa Al Khaifi as head of EDO in January. She joined from PDO and is also chairwoman of the Saudi Arabian unit of State Street Corp., the Boston-based custodian and money manager. EDO will also be able to invest abroad and deal in renewable-energy products.

KrisEnergy Pumps Cambodia’s First Crude in 17 Years A Cambodian concession has commenced production after years of delays in a venture between Singapore’s KrisEnergy and the government. The crude comes from oil fields in Block A, comprising 3083 km 2 of the Khmer basin in the oil-rich Gulf of Thailand, off the southwestern coast of Sihanoukville. The concession will progress in phases once new wells are commissioned and completed. Kelvin Tang, chief executive of KrisEnergy’s Cambodian operations, called the 29 December event “an important strategic milestone” for the company, while Prime Minister Hun Sen hailed the first extraction as “a new achievement for Cambodia’s economy” and “a huge gift for our nation.” Ironbark Australian Exploration Well Declared Dry; Co-Owner Stocks Plummet BP has come up dry at its Ironbark-1 exploration well, the anticipated multi-trillion-scf prospect off the west Australian Pilbara coast. The disappointing prospect was once seen as a potential gas supplier to the emptying North West Shelf (NWS) LNG plant, where BP is a co-owner, within 5 to 10 years. After 2 months of drilling to a total depth of 5618 m, “no significant hydrocarbon shows were encountered in any of the target sands,” according to co-owner New Zealand Oil and Gas (NZOG). Petrorecôncavo Buys Petrobras’ Onshore Bahian Stake for $30 Million Brazilian operator Petrobras on 23 December signed a contract with independent producer Petrorecôncavo to sell its entire stake in 12 onshore E&P fields, the Remanso Cluster, in the state of Bahia. The sale value for the fields was $30 million; $4 million was paid on signing, $21 million at the closing of the transaction, and $5 million will be paid 1 year after that. The Remanso Cluster comprises the onshore fields of Brejinho, Canabrava, Cassarongongo, Fazenda Belém, Gomo, Mata de São João, Norte Fazenda Caruaçu, Remanso, Rio dos Ovos, Rio Subaúma, São Pedro, and Sesmaria. Zion Spuds the Israeli Megiddo-Jezreel #2 Well On 6 January, Zion Oil and Gas officially spudded the Megiddo­Jezreel #2 on its 99,000­acre Megiddo­Jezreel license area in Israel. “With unique operating conditions in the COVID­19 environment, our crews have performed an amazing task,” Zion CEO Robert Dunn said. “Mobilizing a rig into a new coun­try during a pandemic and rigging up is the most challenging part of the drilling operation,” Zion’s vice president of operations, Monty Kness, added. Exxon Declares a Dud at Second Guyana Well Exxon Mobil said on 15 January that its exploration well in the prolific Stabroek Block off Guyana’s coast did not find oil in its target area. Exxon, which operates the Stabroek Block in a consortium with Hess and China’s CNOOC, has made 18 discoveries in the area in 5 years, totaling more than 8 billion BOE, for a combined potential for producing up to 750,000 B/D of crude. The Hassa­1 exploration well was the giant’s second setback to its drilling campaign in recent months. Heirs Holdings Buys 45% of Shell Nigeria’s OML 17 Field Shell Nigeria announced on 15 January it had completed a $533 million sale of its stakes in an onshore OML 17 oil field in Nigeria to African strategic investor Heirs Holdings, Nigeria’s largest publicly listed conglomerate. The deal is one of the largest oil and gas financings in Africa in more than a decade, with a financing component of $1.1 billion provided by a consortium of global and regional banks and investors. Heirs Holdings, in partnership with Transcorp, one of the largest power producers in Nigeria with 2000 MW of installed capacity, purchased 45% stake in the field. It acquired the stakes of Shell, Total, and Eni to further its expansion into the oil and gas industry. Apex Discovers Oil in Egypt’s Western Desert Privately held independent E&P firm Apex International Energy, backed in part by UK energy investment firm Blue Water Energy, on 18 January announced a discovery in the Southeast Meleiha Concession (SEM) in the western desert of Egypt. The discovery was made at the SEMZ-11X well located 10 km west of Zarif field, the nearest producing field. The well was drilled to a total depth of 5,700 ft and encountered 65 ft of oil pay in the Cretaceous sandstones of the Bahariya and Abu Roash G formations. Testing of the Bahariya resulted in a peak rate of 2,100 B/D with no water. Additional uphole pay exists in the Bahariya and Abu Roash G formations that can be added to the production stream in the future. Kosmos Announces Oil at Winterfell Well Dallas-based E&P independent Kosmos Energy announced on 19 January an oil discovery in deepwater US Gulf of Mexico. The Winterfell discovery well, the product of infrastructure-led exploration (ILX), was drilled to a total depth of approximately 23,000 ft and is located in approximately 5,300 ft of water. This subsalt Upper Miocene prospect in off-shore Louisiana encountered approximately 85 ft of net oil pay in two intervals. ILX exploration, which has featured prominently in upstream operators’ portfolios in recent years of relatively low oil prices, is exploration around producing hubs that can be hooked up to those facilities easily and cheaply. The development sidesteps the need for costly and time-consuming individual hub construction. Equinor Gets Permit To Drill North Sea Wildcat Well The Norwegian Petroleum Directorate has granted Equinor a drilling permit for wildcat well 31/11-1 S in the North Sea offshore Norway, 62 km south of the Troll field. The drilling program is the first exploration well to be drilled in production license 785 S, awarded on 6 February 2015 (APA 2014). Operator Equinor and Total E&P Norge are 50/50 partners in the license, which consists of parts of Blocks 26/2 and 31/11. Petrobras, ExxonMobil Hit Hydrocarbons at Urissanê Well, Offshore Brazil Brazilian state-owned Petrobras announced on 29 January it had discovered hydrocarbons in a well located in the Campos Basin presalt off Brazil’s coast of Campos dos Gotyacaze in the State of Rio de Janeiro. Well 1-BRSA-1377-RJS (informally called Urissanê) is located in Block C-M-411, at a depth of 2950 m approximately 200 km offshore. Petrobras, which operates the block in a 50/50 partnership with Exxon Mobil, said it would analyze the well data to better target exploratory activities and assess the potential of the discovery. BP Offloads 20% Share of Oman’s Block 61 To PTTEP Marking another significant step in its divestment program, BP will sell a 20% participating interest in Oman’s 3950 km 2 Block 61 in central Oman to Thailand’s national PTT Exploration and Production (PTTEP) for $2.59 billion. BP will remain operator of the block, holding a 40% interest.‎ The sale comprises $2.45 billion payable on completion and $140 million payable contingent on preagreed conditions.‎ After the sale, BP will hold 40% interest in Block 61, while OQ holds 30%, PTTEP ‎20%, and ‎Petronas 10%.‎ Block 61 contains the largest tight gas development in the Middle East.

Working with clients who are looking to buy upstream oil and gas wells, I almost always hear, “We don’t want stripper wells.” Now that the recent heyday of US unconventional wells is also waning, this often goes along with, “We want conventional production.” With gas prices having been relatively low the past couple of years, it is often, “We want oil-weighted production.” I am used to unicorn hunts and impossible asks, so I thought this was something reasonably doable. After a long year in a terribly gridlocked acquisitions-and-divestitures (A&D) market, I started thinking about it a little more. Most of the conventional packages that were coming to market had low-rate wells with many inactive wells tagging along. We were evaluating a lot of deals but were seeing several fail due to plugging and abandonment (P&A) liability and the inability of low-rate wells to handle the General and Administrative (G&A) structure of clients. One client group was competent and ready to deploy capital, and we had gone on the hunt for off-market deals adjacent to their current production. Our team initially found 19 interesting assets, based on size and proximity, and was pleased to find that nine of the 19 had operators who engaged as seriously interested in selling. Our client turned down all nine assets. Every one of the nine assets was cash flow positive (surprisingly in 2020), in the right region, conventional, and the right size. Every one of the nine was turned down because of the large number of inactive and low-rate wells. In a depressed A&D market with the lowest deal counts in over a decade, having nine assets rejected immediately was frustrating. We decided to screen out assets with low-rate wells and high inactive well counts before making calls and engaging sellers. I downloaded data from all the wells in a Rockies state, screened for current production to get a flowing barrel comp range representing the right deal size, looked for oil-weighted properties, took out unconventional wells, added a rate cutoff around 20 BOED per well, and applied a cutoff where reported inactive wells made up less than 50% of the total well count. Out of about 400 to start with, there were three assets left - only three. At first, I thought that had to be wrong. I knew that US onshore conventional production probably had a large number of low-rate wells, but it seemed reasonable that there would be several assets that had wells doing 20–30 BOED. Thinking about it more, I sent a text to a colleague: “I bet US onshore conventional production is actually dominated by low-rate wells.” I then pulled data for the Texas Gulf Coast because I had another group looking there. The results were shocking: 97% of the wells were 15 BOPD or below. All these clients want conventional assets without stripper wells - but they are all stripper wells.

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.

GOM Lease Sale Generates $121 Million in High Bids; Shell Offshore Takes Top Spot Regionwide US Gulf of Mexico (GOM) Lease Sale 256 generated $120,868,274 in high bids for 93 tracts in federal waters. The sale on 18 November featured 14,862 unleased blocks covering 121,875 square miles. With $27,877,809 spanning 21 high bids, Shell Offshore Inc. took the top spot among 23 competing companies. A total of $135,558,336 was offered in 105 bids. Among the majors, Shell, Equinor, BP, and Chevron submitted some of the highest bids. Each company claimed high bids of over $17 million, signaling the GOM remains a priority in their portfolios. Last year was a record year for American offshore oil production at 596.9 million bbl, or 15% of domestic oil production, and $5.7 billion in direct revenues to the government. Offshore oil and gas supported 275,000 total domestic jobs and $60 billion total economic contributions in the US. “The sustained presence of large deposits of hydrocarbons in these waters will continue to draw the interest of industry for decades to come,” Deputy Secretary of the Interior Kate MacGregor said. Still, as Mfon Usoro, senior research analyst at Wood Mackenzie, noted, “Although bidding activity increased by 30% from the March 2020 sale, the high bid amount of $121 million still trends below the average high bid amount seen in previous regionwide lease sales, proving that companies are still being conservative with exploration spend.” Although the Bureau of Ocean Energy Management has proposed another regionwide GOM lease sale in March 2021, Usoro predicted that Lease Sale 256 “could potentially be one of the last lease sales.” “With the Biden administration set to inaugurate next year and possibly ban future lease sales, a massive land grab might have ensued,” he continued. “But companies are constrained by tight budgets due to the prevailing low oil price. Additionally, companies in the region have existing drilling inventory to sustain them in the near term. The best blocks with the highest potential reserves are likely already leased. As a result, we do not expect a potential ban on leasing to materially impact production in the region until the end of the decade.” This was the seventh offshore sale held under the 2017–2022 National Outer Continental Shelf Oil and Gas Leasing Program; two sales a year for 10 total regionwide lease sales are scheduled for the gulf. Nine Areas on Norwegian Continental Shelf Open for Bids The 25th licensing round on the Norwegian Continental Shelf, comprising eight areas in the Barents Sea and one in the Norwegian Sea, has been announced by the Norwegian Ministry of Petroleum and Energy. Known for being a country with some of the greenest credentials and policies in the world, Norway surprised observers in June by announcing plans for a licensing round that signaled further oil exploration in the Norwegian sector of the Arctic Sea. In this round, 136 blocks/parts of blocks will be available: 11 in the Norwegian Sea and 125 in the Barents Sea. The application deadline for companies is 23 February 2021. New production licenses will be awarded in Q2 2021. Johan Sverdrup Capacity Increased to Half Million B/D Following positive results in a November capacity test, the Johan Sverdrup field is set to increase daily production capacity. Capacity will rise from today’s 470,000 to around 500,000 B/D in the second increase since the field came on stream just over a year ago. The move will increase the field’s total production capacity by around 60,000 bbl more than the original basis when the field came on line. Overall, the field is estimated to have resources of 2.7 billion BOE. “The field has low operating costs, providing revenue for the companies and Norwegian society, even in periods with low prices,” said Jez Averty, Equinor’s senior vice president for operations south in development and production, Norway. The Johan Sverdrup field uses water injection to secure high recovery of reserves and maintain production at a high level. An increase in the water-injection capacity should further increase production capacity by mid-2021, according to Rune Nedregaard, vice president for Johan Sverdrup operations. Phase 2 production starting in Q4 2022 will raise the Johan Sverdrup full-field plateau production capacity from 690,000 to around 720,000 B/D. Equinor operates the field with 42.6% stake; other partners include Lundin Norway (20%), Petoro (17.36%), Aker BP (11.57%), and Total (8.44%). ConocoPhillips Makes Significant Gas Discovery Offshore Norway ConocoPhillips announced a new natural-gas condensate discovery in production license 1009, located 22 miles northwest of the Heidrun oil and gas field and 150 miles offshore Norway in the Norwegian Sea. The wildcat well 6507/4-1 (Warka) was drilled in 1,312 ft of water to a total depth of 16,355 ft. Preliminary estimates place the size of the discovery between 50 and 190 million BOE. Further appraisals will determine potential flow rates, the reservoir’s ultimate resource recovery, and plans for development. “The Warka discovery and potential future opportunities represent very low cost-of-supply resource additions that can extend our multi-decade success on the Norwegian Continental Shelf,” said Matt Fox, executive vice president and chief operating officer. The drilling operation, which was permitted to ConocoPhillips in August 2020, was performed by the Transocean-managed Leiv Eiriksson semisubmersible rig. ConocoPhillips Skandinavia AS is the main operator of the license with a 65% working interest; PGNiG Upstream Norway AS holds the remaining stake. Lundin Energy Completes Barents Sea Exploration Well, Comes Up Dry Lundin Energy has completed exploration well 7221/4-1, targeting the Polmak prospect in licenses PL609 and PL1027, in the southern Barents Sea. The well was meant to prove hydrocarbons in Triassic-aged sandstones within the Kobbe formation of the Polmak prospect. After finding indications of hydrocarbons in a 9-m interval in poor-quality reservoir in the targeted formation, the well was classified as dry. The well was drilled 30 km east of the Johan Castberg discovery, by the Seadrill-operated West Bollsta semisubmersible rig. Lundin Energy, operator of Polmak, holds a 47.51% working interest. Partners are Wintershall DEA Norge AS (25%), Inpex Norge AS (10%), DNO Norge AS (10%), and Idemitsu Petroleum Norge AS (7.5%). Polmak is the first of Lundin’s three high-impact exploration prospects drilled this quarter in the Barents Sea; the wells target gross unrisked prospective resources of over 800 million bbl of oil. The West Bollsta rig will now proceed to drill the Lundin Energy-operated Bask prospect in PL533B. Well 7219/11-1 will target Paleocene-aged sandstones, estimated to hold gross unrisked prospective resources of 250 million bbl of oil. Tullow Sells Remaining Stake in Ugandan Oil Field Tullow Oil has completed the 10 November sale of its assets in Uganda to French giant Total for $500 million. Tullow will also receive $75 million when a final investment decision is taken on the development project, calculated to hold 1.7 billion bbl of crude oil. Contingent payments are payable after production begins if Brent crude prices rise above $62/bbl. The completion of this transaction marks Tullow’s exit from its licenses in Uganda after 16 years of operations in the Lake Albert basin. The deal is designed to strengthen Tullow’s balance sheet, as tumbling crude prices combined with exploration setbacks have created problems for the company. In September, the company reported that it had lost $1.3 billion in the first 6 months of 2020 as falling oil prices forced it to write down the value of its assets. The deal cut Tullow’s net debt to $2.4 billion; it has $1 billion in cash.

“This, too, shall pass.” The exceptional year that has been 2020 highlights the fact that the world can change quickly, and a challenging macroenvironment brings into focus the need to maximize the use of our natural resources and the value that can be derived from them. Even without the black swan event of COVID-19, the industry must critically examine the technical, commercial, and operational bases of the projects it pro-poses and executes. A logical, reasonable, ethical, and philosophical approach is critical to underpin good decision making and value creation. Paper SPE 196252 delivers a comprehensive discussion of the issues to consider in the management of mature oil fields that are becoming increasingly important as older fields decline and approach abandonment. The discussion makes direct reference to assessing the late-life economic limit within the context of the Petroleum Resources Management System. Mitigations such as infield drilling, workovers, and facility management can extend production, improve the economics of the project, and increase reserves. Other considerations around minimizing the cost and optimal planning in respect to abandonment and decommissioning will be required to ensure environmental safeguards and minimize cost liabilities. Paper URTeC 198318 considers a timely look back on the delivery of unconventional projects, the failure of many to meet expectations, and likely causation. A disciplined and systematic approach is proposed to mature the project through four stages of success in discovery, deliverability, demonstration, and development. It is important to obtain sufficient information to underpin each decision point and provide confidence in the commercial evaluation. The paper also stresses the importance of clear guidelines and work flows, independent assurance, and thorough post-appraisal of activities and projects to ensure accountability and improve delivery of value. Paper SPE 196362 describes a philosophical approach to enhanced oil recovery (EOR) and provides an extensive review of the topic and projects, supported by a comprehensive reference list. As with the previous paper, a logical, reasoned, and systematic analysis is recom-mended when confirming the technical and commercial viability of EOR. A creative and innovative approach coupled with experience and expertise is critical to success. 2020 will be remembered as a particularly challenging year in many respects, but, as Tom Hanks’ character Chuck Nolan observes in the movie Cast Away, “I gotta keep breathing. Because tomorrow the sun will rise. Who knows what the tide could bring?” Recommended additional reading at OnePetro: www.onepetro.org. SPE 199522 A Global Push for Circular Economy Projects by Dawson Lindauere, Repsol, et al. SPE 201556 Appropriately Characterizing Uncertainty in Estimated Ultimate Recovery for Unconventional Type Wells by Patrick Miller, Petronas, et al.

For most of the past 160 years, the exploration and production (E&P) sector earned outsized economic rent for finding new oil and gas (O&G) resources and making them economically viable for production. This was possible because of the perceived scarcity of such resources; demand expectations for hydrocarbon products far exceeded their likely supply. During that period, E&P companies focused on building functional expertise to enable growth and operate assets safely. Exploration and appraisal capabilities were particularly revered as key drivers of value. Other areas of the value chain such as field production management, logistics, or even marketing were not seen as critically differentiating. Understandably, building expertise in those areas was never made the primary focus. What a difference a decade makes. Perpetual Disruption Is the New Normal Today, we live in a completely different world. The challenges facing upstream companies simply did not exist 10 years ago. Six compressive forces, in particular, are bringing about a sea change in the industry. Earlier this year, COVID-19 brought with it a sharp and palpable drop in demand for transportation-related crude. With the dramatic structural changes we have made to the ways we live and work in response to the pandemic, low crude demand is expected to continue. This will only exacerbate resource holders’ concerns about supply overabundance. E&P companies that hold hydrocarbon resources were already worried that the resources they own could go unmonetized. Now, that threat is stronger than ever. So is the incentive to monetize their resources as quickly as possible. Ironically, their actions to do so will make the oversupply situation worse. Beyond the issues of supply and demand, the industry’s general economic climate is wreaking havoc. O&G companies typically focus on half-cycle economics or lifting costs when making production decisions. That is because land acquisition and development costs are considered sunk. If oil prices stay in the $40-50/bbl range, many asset classes will simply be uneconomical from a full-cycle standpoint.

This article, written by JPT Technology Editor Judy Feder, contains highlights of paper URTEC 198318, “How Not to Squander Billions on Your Next Unconventional Venture,” by Creties Jenkins, SPE, and Mark McLane, SPE, Rose and Associates, prepared for the 2019 SPE/AAPG/SEG Asia Pacific Unconventional Resources Technology Conference, Brisbane, Australia, 18-19 November. The paper has not been peer reviewed. During the past decade, hundreds of unconventional oil and gas projects have failed to deliver the value sought by shareholders. Two common mistakes have been focusing on production attainment instead of value creation, and incorrectly thinking that enough was understood about a given reservoir to proceed with development. Companies must implement a staged approach that exposes capital incrementally in a responsible fashion and an assurance process that provides a framework for conducting and reviewing work so that mistakes may be analyzed to influence future decisions. The complete paper provides a work flow for making better decisions about investing in unconventional projects. Introduction In 2019, an analysis of 16,000 unconventional wells operated by 29 of the largest producers in Texas and North Dakota revealed that these companies spent $112 billion more in cash over the past 10 years than they generated from operations. A primary contributor to this shortfall was optimistic production forecasts based on a small number of early wells. These types of projections lead companies to commit to development projects before they understand the true variability in well performance and, most importantly, whether the average well will be commercial (i.e., able to pay for the cost to drill, complete, and tie in). Commercial is defined here as attaining a present value greater than zero at the corporate discount rate. If this is 10%, a net present value (NPV) of zero equates to a 10% rate of return. The Challenge More than 50 shale plays across North America have been tested for their production potential. Of these, only a dozen or so (approximately 25%) have been commercially developed. Thus, the first order of business is to focus on the right play in the right basin. But even within a productive basin, operators need to be in the commercial fairway, which is commonly a fraction of the total basin area regardless of play type. The probability of commercializing a new unconventional play in a frontier basin is low. Although a well can be drilled practically anywhere in the basin and encounter mobile hydrocarbons, this does not reduce the commercial risk relative to conventional plays. Instead, it transfers the risk (threat of fiscal loss) to later stages, in which it must be shown that unconventional wells can produce at sufficient rates, costs can be reduced to make these wells commercially viable, and results are repeatable.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 196252, “Management of Reserves in Mature Oil and Gas Fields,” by Douglas Peacock, SPE, and Andrew Duncan, SPE, Gaffney, Cline, and Associates, prepared for the 2019 SPE/IATMI Asia Pacific Oil and Gas Conference and Exhibition, Bali, Indonesia, 29-31 October. The paper has not been peer reviewed. As production of fields declines, revenues will eventually no longer cover costs. As defined by the Petroleum Resources Management System (PRMS), the Reserves class of resources is limited by the earliest truncation of either technical, license, or economic limit. If no technical or license restrictions exist, the economic limit, defined as the time when the maximum cumulative net cash flow occurs for a project, defines the date up to which Reserves may be booked. The complete paper outlines some of the challenges involved in late-life field management and how Reserves assessment may be affected. Extending Field Life Oil and gas fields can have lives much longer than initially envisioned. Fields may be relinquished or proposed for abandonment when the operator’s perspective does not allow the full potential of the field to be exploited. Organizational barriers, regulatory or commercial issues, capital- or manpower-allocation constraints, technology limitations, cost structures, and other factors may exist that, if resolved, can extend the productive life of a field or production area. Several classes of activity can be considered to extend field life while maintaining safe and profitable operations. These include the following: Cost management Incremental or alternative production Operational improvements Fiscal and commercial improvements Cost Management. A detailed understanding of operating costs, and where and why they are incurred in a production system, allows uneconomic elements of the production system to be abandoned, improving the economics of the remaining system. This can take place at the well level (high-water-cut wells) or the satellite-production-system level by consolidating production streams into a single processing facility. The overall objective is to reduce costs by ceasing uneconomic activities. This approach also may require decommissioning activities to be carried out to remove redundant infrastructure (e.g., wellhead platforms) where the continued existence of these facilities would incur costs to maintain a minimum level of structural integrity and safety. The unit costs of essential activities or services can be reduced by contract renegotiation; furthermore, alternative and lower-cost approaches to deliver the same production service may exist.

China Shale-Gas Field Sets Production Record Sinopec recorded China’s highest daily output of shale gas at 20.62 million cubic meters (Mcm) at its Fuling shale-gas field in Chongqing, China, a key gas source for the Sichuan-East gas pipeline. The first major commercial shale-gas project in China, Fuling has continuously broken records for the shortest gasfield drilling cycle while significantly increasing the drilling of high-quality reservoirs covering more than 3 million m, according to Sinopec. Gasfield production construction was also expanded to raise production capacity. The company said the field maintains a daily output of 20 Mcm, producing an estimated 6.7 Bcm per year. Apache and Total Plan Suriname Appraisals Apache filed appraisal plans for its Maka and Sapakara oil discoveries in block 58 offshore Suriname. The company said another submission is expected for Kwaskwasi, the largest find in the block, by the end of the year. Operations continue for Keskesi, the fourth exploration target. There are plans to drill a fifth prospect at Bonboni in the North-Central portion of the concession. Partner company Total is assuming operatorship of the block ahead of next year’s campaigns. BP Emerges as Sole Bid for Offshore Canada Parcels BP was the only operator to place a bid in the Canada-Newfoundland and Labrador Offshore Petroleum Board (C-NLOPB) Call for Bids NL20-CFB01, which offered 17 parcels (4,170,509 hectares) in the eastern Newfoundland region. The successful bid was for Parcel 9 (covering 264,500 hectares) for $27 million in work commitments from BP Canada Energy Group. Subject to BP satisfying specified requirements and receiving government approval, the exploration license will be issued in January 2021. No bids were received for the remaining 16 parcels, which may be reposted in a future Call for Bids. Criteria for selecting a winning bid is the total amount the bidder commits to spend on exploration of the parcel during the first period of a 9-year license, with a minimum acceptable bid of $10 million in work commitments for each parcel. Beach Energy To Drill Otway Basin Well Beach Energy plans to drill at its Artisan-1 well about 32 km offshore Victoria, Australia, in the Otway basin, before the end of 2021. The well, located on Block Vic/P43, was to be spudded in 1H 2020 but was delayed due to COVID-19. The timeframe for drilling was confirmed by the National Offshore Petroleum Safety and Environmental Management Authority, which also said Beach is keeping open the option to suspend the well and develop it, pending reservoir analysis. Anchors, mooring chains, and surface buoys have already been laid for the well, which is in a water depth of approximately 71 m. The well is expected to take approximately 35–55 days to drill, depending on the final work program and potential operational delays. Diamond Offshore’s semisubmersible Ocean Onyx was contracted for the drilling program. Artisan is the first of Beach’s planned multiwell campaigns, which also include development wells at the Geographe and Thylacine fields. Hess Completes Sale of Interest in Gulf of Mexico Field Hess completed the sale of its 28% working interest in the Shenzi Field in the deepwater Gulf of Mexico (GOM) to BHP, the field’s operator, for $505 million. Shenzi is a six-lease development structured as a joint ownership: BHP (operator, 44%), Hess (28%), and Repsol (28%). The acquisition would bring BHP’s working interest to 72%, adding approximately 11,000 BOE/D of production (90% oil). The sale is expected to close by December 2020. Hess CEO John Hess said proceeds from the sale will help fund the company’s investment in Guyana. Greenland Opens New Offshore Areas Greenland opened three new offshore areas for application of oil and gas exploitation licenses off West Greenland. The areas are Baffin Bay, Disko West, and Davis Strait. The country also said it is working on an oil strategy to reduce geological uncertainty by offering an investment package to companies that engage in its Open Door Procedures. The procedures are a first-mover advantage to remove national oil company Nunaoil, as a carried partner, reducing turnover and surplus royalties. It is estimated to reduce the government take by 51.3% to 40.6%. Shell and Impact Oil & Gas Agree to South Africa Farmout Africa Oil announced Impact Oil & Gas entered into two agreements for exploration areas offshore South Africa. The company has a 31.10% share-holding in Impact, a privately owned exploration company. Impact entered into an agreement with BG International, a Shell subsidiary, for the farm-out of a 50% working interest and operatorship in the Transkei and Algoa exploration rights. Shell was also granted the option to acquire an additional 5% working interest should the joint venture (JV) elect to move into the third renewal period, expected in 2024. Algoa is located in the South Outeniqua Basin, east of Block 11B/12B, containing the Brulpadda gas condensate discovery and where Total recently discovered gas condensate. The Transkei block is northeast of Algoa in the Natal Trough Basin where Impact has identified highly material prospectivity associated with several large submarine fan bodies, which the JV will explore with 3D seismic data and then potential exploratory drilling. Impact and Shell plan to acquire over 6,000 km² of 3D seismic data during the first available seismic window following completion of the transaction. This window is expected to be in the Q1 2022. After the closing of the deal, Shell will hold a 50% interest as the operator and Impact will hold 50%. Impact also entered into an agreement with Silver Wave Energy for the farm-in of a 90% working interest and operatorship of Area 2, offshore South Africa. East and adjacent to Impact’s Transkei and Algoa blocks, Area 2 complements Impact’s existing position by extending the entire length of the ultradeepwater part of the Transkei margin. Together, the Transkei and Algoa Blocks and Area 2 cover over 124,000 km 2 . Area 2 has been opened by the Brulpadda and Luiperd discoveries in the Outeniqua Basin and will be further tested during 2021 by the well on the giant Venus prospect in ultradeepwater Namibia, where Impact is a partner. Impact believes there is good evidence for this Southern African Aptian play to have a common world-class Lower Cretaceous source rock, similar excellent-quality Apto-Albian reservoir sands, and a geological setting suitable for the formation of large stratigraphic traps. Following completion of the farm-in, Impact will hold 90% interest and serve as the operator; Silver Wave will hold 10%. Petronas Awards Sarawak Contract to Seismic Consortium The seismic consortium comprising PGS, TGS, and WesternGeco was awarded a multiyear contract by Petronas to acquire and process up to 105,000 km 2 of multisensor, multiclient 3D data in the Sarawak Basin, offshore Malaysia. The contract award follows an ongoing campaign by the consortium in the Sabah offshore region, awarded in 2016, in which over 50,000 km 2 of high-quality 3D seismic data have been acquired and licensed to the oil and gas industry to support Malaysia license round and exploration activity. The Sarawak award will allow for a multiphase program to promote exploration efforts in the prolific Sarawak East Natuna Basin (Deepwater North Luconia and West Luconia Province). The consortium is planning the initial phases and is engaging with the oil and gas industry to secure prefunding ahead of planned acquisition, covering both open blocks and areas of existing farm-in opportunities. Total Discovers Second Gas Condensate in South Africa Total made a significant second gas condensate discovery on the Luiperd prospect, located on Block 11B/12B in the Outeniqua Basin, 175 km off the southern coast of South Africa. The discovery follows the adjacent play-opening Brulpadda discovery in 2019. The Luiperd-1X well was drilled to a total depth of about 3,400 m and encountered 73 m of net gas condensate pay in well-developed, good-quality Lower Cretaceous reservoirs. Following a coring and logging program, the well will be tested to assess the dynamic reservoir characteristics and deliverability. The Block 11B/12B covers an area of 19,000 km2, with water depths ranging from 200 to 1800 m. It is operated by Total with a 45% working interest, alongside Qatar Petroleum (25%), CNR International (20%), and Main Street, a South African consortium (10%). The Luiperd prospect is the second to be drilled in a series of five large submarine fan prospects with direct hydrocarbon indicators defined utilizing 2D and 3D seismic data. BP Gas Field Offshore Egypt Begins Production BP started gas production from its Qattameya gasfield development ‎offshore Egypt in the North Damietta offshore concession. Through BP’s joint venture Pharaonic Petroleum Company working with state-owned Egyptian Natural Gas Holding Co., the field, which is ‎expected to produce up to 50 MMcf/D, was developed through a one-well subsea development and tieback to existing infrastructure.‎ Qattameya, whose discovery was announced in 2017, is located approximately 45 km west ‎of the Ha’py platform, in 108 m of water. It is tied back to the Ha’py and Tuart field ‎development via a new 50-km pipeline and connected to existing subsea ‎utilities via a 50-km umbilical. ‎BP holds 100% equity in the North Damietta offshore concession in the East Nile Delta. ‎Gas production from the field is directed to Egypt’s national grid.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper URTeC 2584, “A New Methodology To Determine Well Spacing in Unconventional Reservoirs: Delaware Basin Study,” by Dicman Alfred and Andrew Lundy, Scala Energy, prepared for the 2020 Unconventional Resources Technology Conference, originally scheduled to be held in Austin, Texas, 20-22 July. The paper has not been peer reviewed. Present industry solutions to the challenge of well spacing involve expensive geomechanical Earth modeling or fracture-geometry monitoring that is time-consuming, data-intensive, and geography-specific. The authors of the complete paper write that their developed methodology is quicker and pad-specific and requires no additional data collection than those routinely gathered. Other significant outcomes of this work flow include the ability to rank well performance and predict changes in geology and pressure regimes relative to an existing similarly landed producer.

This article, written by JPT Technology Editor Judy Feder, contains highlights of paper SPE 197123, “Technologies and Practices to Push the Extended-Reach-Drilling Envelope Within Existing Constraints,” by Phalgun Paila, SPE, Baker Hughes; Rudra Pratap Singh, ADNOC; and Kashif Abid, SPE, Baker Hughes, prepared for the 2019 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, 11-14 November. The paper has not been peer reviewed. Optimizing resources and pushing drilling limits to tap into deeper reservoirs at minimal cost is a primary objective of operators worldwide. The complete paper describes an offshore artificial island project northwest of Abu Dhabi in which drilling limits were extended continually by adopting new technologies and practices in an extended-reach-drilling (ERD) campaign. The project drilled longer wells at lower cost. The approach has resulted in drilling and completion of wells comfortably within the equipment-rating envelope and is considered a benchmark for nearby fields in the region.

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 196440, “Giving a Boost to a Low-Pressure Gas Well by Installing a Gas Ejector,” by Ping Wei and Brian Macdonald, SPE, KUFPEC, prepared for the 2019 SPE Asia Pacific Oil and Gas Conference and Exhibition, 29-31 October, Bali, Indonesia. The paper has not been peer reviewed. To further reduce backpressure on low-pressure gas wells and increase reserves in a mature gas field, a gas-ejector project was evaluated and proposed. Following on-site tests on several gas wells, the gas ejector was put into service successfully. Reservoir simulation estimates that 6.4 Bcf of incremental reserves will be achieved through gas-ejector installation by decreasing inlet pressure to 50 from 100 psi. The application of the gas ejector during a 2-year period to reduce backpressure has helped to improve economics in a mature gas field.

The success of any digital oilfield project is predicated on the quality of the data structure, acquisition, communication, validation, storage, retrieval, and provenance of the data. Therefore, the mission of the digital oilfield architect is clear: Deliver the right data to the right users at the right time. This task is becoming more difficult because of the sheer variety of sensors, the multitude of data formats, challenges with data communication and synchronization, and the potentially large volume of data produced. While the advent of data analytics has increased the importance of designing fast and efficient data management systems, it is a multifaceted minefield to gather and process data to ensure production is optimized and risk is minimized in both conventional and unconventional operating environments.