Gabon
How Do You Survive Changes? What comes first to your mind when you think about change? For me, I would say it is normality & adaptability. In my childhood I grew up in three different Gabonese cities (Libreville, Oyem and Port-gentil) because I had to move with my parents who were active in the medical sector, changing school every time and leaving friends behind. After my secondary school degree I decided to move to Germany to study petroleum engineering.
- Europe (1.00)
- Africa > Gabon > Woleu-Ntem > Oyem (0.26)
- Africa > Gabon > Ogooue-Maritime > Port-Gentil (0.26)
- Africa > Gabon > Estuaire > Libreville (0.26)
How Do You Survive Changes? What comes first to your mind when you think about change? For me, I would say it is normality & adaptability. In my childhood I grew up in three different Gabonese cities (Libreville, Oyem and Port-gentil) because I had to move with my parents who were active in the medical sector, changing school every time and leaving friends behind. After my secondary school degree I decided to move to Germany to study petroleum engineering.
- Europe (1.00)
- Africa > Gabon > Woleu-Ntem > Oyem (0.26)
- Africa > Gabon > Ogooue-Maritime > Port-Gentil (0.26)
- Africa > Gabon > Estuaire > Libreville (0.26)
BW Energy confirmed that production has started from the third well of the Hibiscus/Ruche Phase 1 development in the Dussafu license offshore Gabon. Well performance is in line with expectations with current production at around 6,000 B/D. The DHIBM-5H well was drilled as a horizontal well from the BW MaBoMo production facility to a total depth of 4245 m into Gamba sandstone reservoir at the Hibiscus field. Following completion, jackup Borr Norve began drilling operations on the fourth production well (DHIBM‑6H). The drilling campaign targets four Hibiscus Gamba and two Ruche Gamba wells, which are expected to bring total oil production to approximately 40,000 B/D when all wells are completed in early 2024.
- Africa > Gabon > South Atlantic Ocean > South Gabon Basin > Dussafu Marin Block > Ruche North East Field > Gamba Formation (0.99)
- Africa > Gabon > South Atlantic Ocean > Gamba Formation (0.98)
Abstract Minimizing risks in offshore oil and gas production facilities is of upmost importance for oil producers to reduce possibilities of liability claims, hydrocarbons production rate loss, and most importantly environmental impacts. In this regard, well integrity parameters such as MAASP and MAWOP become key tools to carefully follow and watch production tubings and annulus pressures behaviors at the surface. AGM043 is an oil producing well which presented a high downgraded situation mainly with abnormal pressure in the annuli A and B and the christmas tree not holding the pressure. The pressure rate observed in the annulus B (104 bars) was considered higher than the limit set as per the MAASP (72 bars) presenting a risk of fracture at the 13-3/8″ casing shoe. To regain full integrity of the well, since purging the annuli did not contribute to pressure stabilization and due to the presence of gas (mainly methane), actions were taken to conduct a well killing job split in four phases: Phase 1: Purging, investigate communication point between tubing and annuli, echometer for fluid level determination. Phase 2: Well killing by bull heading in the tubing and lubricate and bleed in the annuli. Phase 3: Establishment of a double barriers Phase 4: Valves changes and test of Christmas tree integrity. This manuscript discusses the rise of an abnormal pressure behavior in the annular, its management, and the lessons learnt at the end of the integrity regain after the killing job offshore Gabon. The experience gained can be applied to other wells with similar problems.
- Africa > Gabon (0.87)
- North America > Canada > Alberta (0.29)
Vaalco Energy encountered multiple hydrocarbon-bearing sands with its South Tchibala 1HB-ST well drilled from the Avouma platform in the Etame field offshore Gabon. The well struck 18 m of hydrocarbons in the Dentale D1 sand, which is analogous to the Deep Dentale producing field in North Tchibala with similar porosity and permeability. Another 15 m of hydrocarbons was intersected in the Dentale D9. The well will be completed in the D1 sand and was scheduled to be online in June, while the D9 will be cased for future completion. The well also penetrated a thin section of Gamba sand which will not be economically feasible to complete.
- Africa > Gabon > South Atlantic Ocean > Lower Congo Basin > Etame Marin Production Sharing Contract (“PSC”) > Etame Block > Etame Field > Gamba Formation (0.99)
- Africa > Gabon > South Atlantic Ocean > Lower Congo Basin > Etame Block > Etame Field > Dentale Sandstone Formation (0.98)
- Africa > Gabon > South Atlantic Ocean > Lower Congo Basin > Etame Marin Production Sharing Contract (“PSC”) > Etame Block > North Tchibala Field (0.97)
Sinopec Signals Fresh Shale Success With Dongye Deep 2 Sinopec has announced that the Dongye Deep 2 key shale gas well in Dongxi, Chongqing, was drilled to a total depth of 4300 m and tested at 412000 m/d of high-quality natural gas. The operator said the result shows significant progress in ultradeep shale gas exploration in China and will increase Sinopec’s shale gas production capacity in southeast Sichuan by more than 2 trillion m. Following the breakthrough of the Fuling shale gas field in 2012, Sinopec has been expanding its expertise in deep shale gas. In 2018, Sinopec discovered and commercialized the Weirong shale gas field at a depth of 3800 m. The technical requirements of developing deep marine shale gas reservoirs at depths exceeding 4000 m are high due to challenges faced at ultrahigh depths and complex crustal stress. Sinopec plans to increase oil and gas exploration by developing unconventional resources such as shale oil and gas while focusing on growing reserves and production of conventional petroleum. Qatar Energy Farms Into Hampden License off Eastern Canada Qatar Energy has signed an agreement with ExxonMobil Canada to acquire a 40% ownership of exploration license 1165A off Canada’s east coast, marking the state-owned oil company’s first foray into offshore exploration in Canada. The Block EL 1165A is where operator ExxonMobil plans to drill the deepwater Hampden exploration well sometime in 2022. In May 2020, Seadrill semisubmersible rig West Aquarius began drilling for ExxonMobil at the Hampden prospect, but operations were suspended after a week, without explanation. ExxonMobil is said to be nearing a deal for a rig to complete the exploration well. Qatar is the world’s largest supplier of liquefied natural gas, or LNG, and is undertaking a strategy to boost production significantly over the next 5 years to meet the growing market for LNG. ExxonMobil led the way in developing Newfoundland and Labrador’s offshore, and operates both the Hibernia and Hebron oil fields. The oil major has been broadening its attention to the Flemish Pass Basin, a frontier area where other major discoveries have been made, including Equinor’s Bay du Nord find. TGS Plans 3D Shoot Offshore Suriname TGS, in a consortium with CGG and BGP, have signed a multiclient agreement with Staatsolie, the state-owned company leading the development of the energy industry in the Republic of Suriname. The deal allows for the acquisition, promotion, and licensing of multiclient seismic programs, including new 3D acquisition and legacy data reprocessing, in the shallow-water acreage offshore Suriname. Suriname’s acreage includes three blocks recently awarded, and current open acreage slated to be offered, in a competitive bid round for 2023. The new seismic data from the consortium’s programs can be used to delineate the prospectivity and potential of this underexplored area and is on trend with the recent material discoveries announced on the prolific Block 58. Plans are in place to start acquiring the new 3D seismic data in the area prior to year-end, with first products to be made available during the first half of 2022. BGP Offshore will deploy its 3D vessel BGP Prospector in phase 1 of the project. ExxonMobil Increases Stabroek Resource Estimate Again ExxonMobil has increased the estimated overall resource at its Stabroek Block offshore Guyana to around 10 billion bbl, reflecting the recent exploration success at its Cataback prospect. The Cataback-1 well encountered 243 ft of net pay in high-quality hydrocarbon-bearing sandstone reservoirs. The find is located approximately 3.7 miles east of Turbot-1 and was drilled in 5,928 ft of water by the drillship Noble Tom Madden. Success at Cataback brings the total significant discoveries to more than 20 within the Stabroek Block. The Stabroek Block spans 6.6 million acres. ExxonMobil affiliate Esso Exploration and Production Guyana Limited is operator and holds 45% interest in the block. Hess Guyana Exploration holds 30% interest, and CNOOC Petroleum Guyana Limited holds the remaining 25% stake. Shell To Sign PSA on Trindad’s Manatee Discovery Royal Dutch Shell expects to sign a production-sharing contract for the 2.7-Tcf Manatee offshore gas field in Trinidad and Tobago. The country’s Energy Minister Stuart Young confirmed the contract has been negotiated and is hoping the operator signs on in the coming weeks. The field is part of the 10-Tcf Loran-Manatee complex that straddles Trinidad and Tobago’s maritime border with Venezuela. Young said it “is going to be the single largest new gas production contract and gas production in TT [Trinidad and Tobago] for decades.” Gas volumes could start flowing as early as 2025, but this depends on the speed at which the parties can install infrastructure. Production rates from the field are expected to range from 270 million to 400 MMcf/D. US sanctions against the regime of Venezuela’s Nicolás Maduro prevented co-development of the complex. Lundin Increases Stake in Wisting Lundin Energy has entered into an agreement with OMV to acquire its entire 25% working interest in the Wisting development in the southern Barents Sea for $320 million. The acquisition takes Lundin Energy’s working interest to 35% in the 500-MMBO development. In addition to the 35% stake in Wisting, Lundin Energy also holds surrounding acreage which is estimated to hold gross unrisked prospective resources of a further 500 MMBO. Wisting will be one of the largest development projects in Norway over the next few years, to become the next Barents Sea production hub, according to Lundin. Concept selection is anticipated shortly, and the submission of the Plan of Development and Operation is targeted by year-end 2022 to qualify for the temporary tax incentives established by the Norwegian government in June 2020. With first oil scheduled for 2028, the acquisition provides a material contribution to sustaining the company’s production in the long term. The Wisting development is also planned to have power supplied from shore, which is aligned with the company’s decarbonization strategy and its commitment to becoming carbon neutral by 2023. The transaction, which has an effective date of 1 January 2021, is subject to the customary Norwegian regulatory approvals, and is expected to complete during Q4 2021. The other partners in Wisting are Equinor, the development-phase operator, with a 35% working interest, Petoro with a 20% working interest, and Idemitsu with a 10% stake. Panoro Energy Awarded Stakes Offshore Gabon Panoro Energy has provisionally been awarded a 25% nonoperated interest in exploration blocks G12-13 and H12-13 offshore shallow-water Gabon following the 12th Offshore Licensing Round. The award remains subject to final agreement of the terms of the production-sharing contracts with the government of Gabon. Partners in the blocks will include BW Energy (37.5% and operator) and VAALCO Energy (37.5%). Blocks G12-13 and H12-13 cover a surface area of 2989 km and 1929 km, respectively, and are adjacent to the producing Dussafu Marin Permit, in which Panoro holds a 17.5% interest and is partnered with BW Energy. The G12-13 block is also adjacent to the producing Etame Marin license operated by VAALCO Energy. Panoro expects the contracts over the two blocks will have an exploration period of 8 years with an option to extend by another 2 years. During the exploration period, the partners intend to carry out a work program which may include reprocessing of existing seismic, new seismic acquisition, and exploration drilling.
- Asia > China (1.00)
- Africa > Gabon (1.00)
- South America > Guyana > North Atlantic Ocean (0.96)
- North America > Canada > Newfoundland and Labrador > Newfoundland > North Atlantic Ocean (0.54)
- Government > Regional Government > Asia Government > China Government (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- South America > Guyana > North Atlantic Ocean > Guyana-Suriname Basin > Stabroek Block (0.99)
- North America > Canada > Newfoundland and Labrador > Newfoundland > North Atlantic Ocean > Atlantic Margin Basin > Grand Banks Basin > Jeanne d'Arc Basin > Hebron Field (0.98)
- North America > United States > Louisiana > China Field (0.95)
Panoro Energy has provisionally been awarded a 25% nonoperated interest in exploration blocks G12-13 and H12-13 offshore shallow-water Gabon following the 12th Offshore Licensing Round. The award remains subject to final agreement of the terms of the production-sharing contracts with the government of Gabon. Partners in the blocks will include BW Energy (37.5% and operator) and VAALCO Energy (37.5%). Blocks G12-13 and H12-13 cover a surface area of 2989 km2 and 1929 km2, respectively, and are adjacent to the producing Dussafu Marin Permit, in which Panoro holds a 17.5% interest and is partnered with BW Energy. The G12-13 block is also adjacent to the producing Etame Marin license operated by VAALCO Energy.
Abstract The combination of well conditions such as high levels of carbon dioxide (CO2, an average of 15%), 85% water cuts (WC), sand production, and heavy viscous oil is one of the biggest challenges for any artificial lift system (ALS). Progressing cavity pumping (PCP) is the preferred method for sand and heavy oil production; however, CO2 presence in the form of carbonic acid, generates corrosion and pitting on the carbon-steel section of the Progressing Cavity stators. This condition results in short run life for PC pumps with standard materials historically installed. Taking advantage of the corrosion strength properties that Stainless Steel (SS) material has, a new SS PC pumps were manufactured to be installed in highly corrosive application and then determine the increase on run life for those wells previously affected by corrosion. This paper describes a section of the results from the flow assurance improvement plan obtained by the installation of PC pumps with SS technology in terms of workover (WO) intervention savings and extended run life in nine wells operating in Gabon, West Africa. This paper describes the methodology applied in the selection of the PCP models to be manufactured with Stainless Steel technology considering the dimensional restrictions the PCP would have due the casing size of the well completions where the PC pump would be installed, as well as the pump design requirements related to the expected flow rate in the wells historically affected by corrosion. In addition, the paper shows the screening done on the well candidates for the installation of SS PCP, based on historical well intervention data specifically associated to corrosion. Since the installation of the SS PCP technology, the client has performed several acid stimulations that have required pulling the PC pumps out of hole and re-running them multiple times. Throughout these operations, the PCPs have had no failures requiring intervention. The installation of SS technology has improved well run life across all nine candidates by 584% on average. The SS PCP technology continue to run in all nine wells with no corrosion-associated interventions. For an average of 326 days across all nine wells, there have been no WOs performed on the PCPs. The reduction in WOs has helped to avoid production losses, downtime, and associated costs. SS PCP has shown great results extending PC pump run life over 6 times compared to previous applications and has proven to be a good option for larger flow rates in 5.5 in casing completions.
- Africa > Gabon (0.71)
- North America > United States > Texas (0.28)
- Geology > Mineral > Sulfide (0.69)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (0.35)
- Energy > Oil & Gas > Upstream (1.00)
- Materials > Chemicals > Commodity Chemicals > Petrochemicals (0.68)
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.
- South America > Guyana > North Atlantic Ocean (1.00)
- Europe > Norway > Norwegian Sea (1.00)
- Africa > Gabon > South Atlantic Ocean (1.00)
- (3 more...)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > South America Government > Brazil Government (0.65)
- South America > Guyana > North Atlantic Ocean > Guyana-Suriname Basin > Demerara Block (0.99)
- South America > Guyana > North Atlantic Ocean > Guyana-Suriname Basin > Corentyne Block > Kawa-1 Well (0.99)
- South America > Brazil > Rio de Janeiro > South Atlantic Ocean > Santos Basin > Libra Block > Mero Field (0.99)
- (69 more...)
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.
- Africa > Gabon > South Atlantic Ocean > South Gabon Basin > Dussafu Marin Block > Tortue Field > Gamba Formation (0.99)
- Africa > Gabon > South Atlantic Ocean > South Gabon Basin > Dussafu Marin Block > Tortue Field > Dentale Sandstone Formation (0.99)
- Africa > Gabon > South Atlantic Ocean > South Gabon Basin > Dussafu Marin Block > Ruche North East Field > Gamba Formation (0.99)
- Africa > Gabon > South Atlantic Ocean > Gamba Formation (0.99)