New technologies, keen strategies and a sharpened focus keep offshore operators determined and decisive. Activity is picking up, and these key players are focused on increasing profits and production.
Offshore the U.K., the production forecast is looking more positive. “Development activity in the U.K. offshore sector is expected to improve after historical lows in the past few years,” according to a March 2019 GlobalData report. “There are 16 planned greenfield projects with identified development plans and 29 announced greenfield projects forecast to start production between 2019 and 2025. These are estimated to cost around $6.7 billion and $11.4 billion, respectively.”
In other areas, such as offshore Argentina, exploration is the main focus for operators. “Any big discovery in Argentina’s offshore frontier area will be a great prize for companies looking into building up a portfolio for future development. However, such long-term strategies will compete with a current preference for exploration in offshore areas with more seismic and well information available and where logistics to commercialize production is already known,” GlobalData said in a September 2018 report.
Moreover, E&P activity has heightened drastically in the Gulf of Mexico in the last year. Wood Mackenzie recently reported that 2019 “is shaping up to be a good one in the U.S. Gulf of Mexico, with the first increase in drilling in four years, first-ever production from a Jurassic play, key new project sanctions and an uptick in M&A [mergers and acquisitions] all in the cards.” Wood Mackenzie expects exploration activity to increase 30% this year. “Shell and Chevron will lead the way, but the actual growth in exploration will come from new entrants—Kosmos Energy, Equinor, Total, Murphy and Fieldwood,” the report stated.
The following is a sampling of offshore operators, their recent production updates and strategies moving forward.
Editor’s Note: This article originally appeared in May's print issue of E&P magazine. These profiles were written based on fourth-quarter and year-end 2018 reports as well as 2018 and early 2019 press releases. As of press time in late March/early April, first-quarter 2019 results had not been released. If available, updates have been posted beneath each company profile.
Aker BP ASA
Aker BP is the operator for Valhall, Ula, Ivar Aasen, Alvheim and Skarv offshore field centers. According to the company, it is one of the biggest independent listed oil and gas companies in Europe, measured by production. The company’s net production in 2018 was 155,700 boe/d, and total production volume was 56.8 MMboe. In the fourth quarter of 2018 production volumes increased due to improved efficiency and new wells, according to the company.
According to the company’s fourth-quarter 2018 report released on Feb. 6, “Aker BP continued its positive development and strong growth in 2018. Total income increased by 46% from 2017 and all major field development projects progressed as planned. Reserve replacement was above 100%, and the company continued to grow its resource base through acquisitions and exploration success.”
In the development arena, Aker BP said Phase 1 of the Johan Sverdrup development project is progressing steadily toward planned production start in November 2019. “Johan Sverdrup is a major discovery and ranks among the five largest oil fields on the Norwegian Continental Shelf [NCS],” the company said on its website. “The development of the field will be one of the key industrial projects in Norway over the next 50 years.”
The company is an active explorer on the NCS. “In recent years about two-thirds of Aker BP’s exploration budget has been invested in the mature areas in the North Sea, where the infrastructure is good and the discovery rate is still high. The remaining resources have been invested primarily in the Barents Sea and in the more immature areas in the North Sea,” the company said.
Aker BP reported fourth-quarter 2018 production of 58,400 boe/d for the Alvheim area, 23,300 boe/d for Ivar Aasen, 23,500 boe/d for Skarv, 8,400 boe/d for the Ula area and 39,600 boe/d for the Valhall area, according to the report.
In the Alvheim area, the Skogul project is progressing according to plan and production start is scheduled for the first quarter of 2020, the report stated. In the first quarter of 2018, an oil discovery was made in the Frosk prospect near the Bøyla Field, and a new well was scheduled to be drilled in the first half of 2019. Aker BP will continue its exploration of the Frosk area this year.
In the Valhall area, drilling from the IP platform continued with the G22 well coming onstream during the fourth quarter of 2018. The G11 well was subsequently drilled and completed using the Fishbones technology in one section of the well. Test production began in February.
In the Ula area, development of the field is in its final stages. Drilling operations were completed in the fourth quarter last year. As of Feb. 6, Aker BP is performing the final preparations to start production, which is expected during the first half of the year, the report stated. There is the possibility the company will add a new platform at Ula in mid-2020.
Additionally, “Aker BP considers the resource potential in the Ula area to be significant, both from increased oil recovery in the Ula and Tambar fields, from potential tiebacks of other discoveries including the newly acquired King Lear discovery, and from exploration opportunities,” according to the report.
In the Skarv area, production start for the Ærfugl development is planned for the fourth quarter of 2020.
April 26 update from company: Aker BP releases first-quarter 2019 results
Anadarko Petroleum Co.
Anadarko’s offshore operations are located in the Gulf of Mexico (GoM), offshore Ghana and Mozambique. “Anadarko operates the largest number of floating facilities in the deepwater Gulf of Mexico with additional exploration prospects, discoveries, large-scale developments and hub-and-spoke opportunities,” the company said on its website. “Anadarko is among the largest independent leaseholders and producers in the deepwater Gulf of Mexico, with expansive infrastructure that includes 10 operated deepwater facilities.”
Anadarko’s GoM sales volume averaged 142,000 boe/d in the fourth quarter of 2018, which included 120,000 bbl/d of oil. “The company’s leading infrastructure
position continues to provide highly economic tieback opportunities, including new wells and developments at its 100%-owned Constitution, Horn Mountain, Holstein and Marlin platforms,” the company stated in its fourth-quarter 2018 results report released Feb. 5. “This year Anadarko plans to operate up to two drillships and two platform rigs and bring approximately 10 wells to sales in the areas near its Constellation, Holstein, Horn Mountain, K2, Lucius and North Hadrian producing assets.”
Anadarko also holds interest in deepwater exploration blocks in the GoM, South America and South Africa. It also is working to develop one of the world’s largest natural gas accumulations offshore Mozambique. Anadarko expects to make a final investment decision on the Mozambique LNG project in the first half of this year.
On April 12 Chevron Corp. entered into a definitive agreement with Anadarko Petroleum Corp. to acquire all of the outstanding shares of Anadarko. The total enterprise value of the transaction is $50 billion, according to a press release. The transaction is expected to close in the second half of the year.
April 24 news update: Occidental Petroleum Kicks Off Anadarko Bidding War With Chevron
April 25 update from the company: Anadarko Announces 2019 First-Quarter Results
April 29 update from the company: Anadarko Intends To Resume Negotiations With Occidental
BHP, formerly known as BHP Billiton, has operating assets in the Shenzi, Neptune, Atlantis and Mad Dog fields in the Gulf of Mexico (GoM) as well as in several fields offshore Australia. Other offshore production operations are located in the Greater Angostura Field offshore Trinidad and Tobago. Petroleum exploration expenditure for the second half of 2018 was $316 million, and activity for the period was largely focused in the GoM and Trinidad and Tobago, according to BHP’s second-half 2018 results report released Feb. 19. This year a $750 million exploration and appraisal program is being executed.
In the U.S. GoM, “Samurai-2 and Samurai-2 ST01 drilling has delineated the accumulation of oil,” the report stated. “Further appraisal and development planning at Samurai is in progress. In the southern portion of the Wildling sub-basin, we continue to assess the potential resource, with further appraisal drilling now expected in the 2020 financial year.”
In the Western U.S. GoM, an ocean-bottom node seismic acquisition was completed in early January 2019 and processed data are expected to be delivered during March 2020. “This is the world’s first deepwater exploration ocean-bottom node seismic acquisition,” according to the company.
In addition, BHP spudded the Trion-2DEL appraisal well in the GoM in November 2018 and encountered oil in line with expectations. “This was followed by a planned downdip geologic sidetrack, which encountered oil and water, as predicted, further appraising the field and delineating the resource,” the report stated. “Following the recent encouraging results in the Trion Block, an additional appraisal well (3DEL) to further delineate the scale and characterization of the resource is expected to be drilled in the second half of 2019.”
Looking ahead, other major projects include the development of the Atlantis Phase 3 project in the deepwater GoM.
Offshore Trinidad and Tobago, the company encountered hydrocarbons at the Bongos-2 exploration well in the first half of 2019, and Phase 3 of BHP’s deepwater exploration drilling campaign will start in the second half of the year, according to the report. Phase 3 will test three wells on three prospects in the northern license area.
Offshore Eastern Canada, BHP was the successful bidder in October 2018 for licenses in the Orphan Basin, and the company has begun working with the Canada-Newfoundland and Labrador Offshore Petroleum Board to meet all regulatory requirements for the exploration phase. The licenses became effective in January.
April 17 update from company: BHP Operational Review for the nine months ended 31 March 2019
BP has offshore operations and development projects in the Gulf of Mexico (GoM) and offshore Trinidad and Tobago, the U.K., Egypt and Australia.
As of February, BP had already completed three major upstream project startups this year: Constellation in the U.S. GoM, the second stage of the West Nile Delta development offshore Egypt and gas production at Angelin offshore Trinidad.
In the last few years, BP has been very active in West Africa, accessing about 80,000 sq km (30,888 sq miles) of acreage with resource potential of 8 Bboe.
“In drilling, over 70% of our offshore wells are now top quartile—from 25% just five years ago. And during the same period, our percentage of nonproductive time for completions has reduced by around 30%,” Bernard Looney, BP’s Upstream chief executive, said during an investor day presentation in December 2018. “Mad Dog 2 [in the GoM] is a great example of our drilling performance. …Three of our last four wells are the best ever drilled.”
Over the next few years, the company plans on wrapping up construction projects for Angelin offshore Trinidad, Constellation in the GoM, Culzean in the North Sea and West Nile Delta-Raven offshore Egypt this year; the KG D6 R-Series in the Bay of Bengal, Alligin and Vorlich in the North Sea, and Zinia 2 offshore Angola in 2020; and Mad Dog Phase 2 in the GoM, KG D6 Satellites and Manuel in the GoM in 2021.
In addition, the company has had a strong focus on improving efficiencies via new technology developments and upgrades. “In Trinidad we are using the latest digital modeling technology—think 3-D visualization of our offshore facilities. This allows us to complete detailed activity planning on our normally unmanned installations without having to go offshore, improving safety through reduced visits and saving $450,000 so far,” Looney said.
“In the Gulf of Mexico, our project teams have been using our latest agile ways of working and challenging themselves to bring our new subsea tiebacks online quicker. They are making good progress with seven tiebacks either in execute or operate with an average 10-month improvement in cycle time.”
He also noted that the application of seismic techniques, like ocean-bottom nodes, full waveform inversion and new ways of working at Thunder Horse, has unlocked an additional 1 Bbbl of oil in place (gross). “We now see the potential for the GoM to run at around 400,000 barrels of oil equivalent per day through the middle of the next decade,” he said.
April 16 news update: BP Hands $700 Million Caspian Deal To Turan
April 18 news update: Turan Drilling Wins $500 Million BP Contract In Caspian Sea
April 19 news update: BP, Partners Sanction $6 Billion Azeri Central East Development Offshore Azerbaijan
April 30 update from the company: First-quarter 2019 Results
Chevron, through its subsidiaries and affiliates, has offshore projects located in the deepwater U.S. Gulf of Mexico (GoM) as well as offshore Western Australia, New Zealand, South America, the U.K., West Africa and in the Gulf of Thailand.
During 2018, net daily production in the GoM averaged 186,000 bbl of crude oil, 3.3 MMcm (117 MMcf) of natural gas and 13,000 bbl of NGL, according to the company’s 2018 annual report supplement. As of early 2019, Chevron has an interest in 218 leases in the GoM. At year-end 2018, the company was the second largest leaseholder in the GoM.
Chevron’s signature deepwater project in the GoM is Jack/St. Malo, which is located about 451 km (280 miles) south of New Orleans. The project’s development phases progressed in 2018; Stage 2 was accomplished with all four wells on production and Stage 3 advanced, as two of the three planned wells were completed. Stage 4 includes water injection at the St. Malo Field and is expected to reach a final investment decision in the third quarter of 2019. Total daily production from the Jack and St. Malo fields averaged 139,000 bbl of liquids (71,000 net) and 594,654 cu. m (21 MMcf) of natural gas (11 million net) last year, according to the 2018 annual report supplement.
Also in the GoM, the Chevron-operated Big Foot deepwater project, located 362 km (225 miles) south of New Orleans, achieved first oil in November 2018 with ramp-up expected to continue during 2019. The field is estimated to contain total recoverable resources in excess of 200 MMboe, according to the company.
At the Tahiti Field, 2018 net daily production averaged 51,000 bbl of crude oil, 622,971 cu. m (22 MMcf) of natural gas and 3,000 bbl of NGL. The Tahiti Vertical Expansion Project is developing shallower reservoirs and achieved first oil from three wells in June 2018, and the fourth well was scheduled to come online in the second quarter of 2019.
Chevron also operates the Anchor Field located in the Green Canyon area off the coast of Louisiana. FEED activities commenced in 2018. The planned facility has a design capacity of 75,000 bbl/d of crude oil and 792,872 cu. m/d (28 MMcf/d) of natural gas, according to the 2018 annual report supplement. The total potentially recoverable oil-equivalent resources for Anchor are estimated to exceed 450 MMbbl.
In January 2018, Chevron announced a significant oil discovery at the Ballymore prospect in the Mississippi Canyon area in the deepwater GoM. The initial Ballymore well reached total measured depth of 8,898 m (29,194 ft) and encountered more than 204 m (670 ft) net oil pay with excellent reservoir and fluid characteristics, according to the company.
Offshore Western Australia, the Jansz-Io gas field is part of the Chevron-operated Gorgon project. In March 2019, Chevron contracted Aker Solutions to support delivery of a subsea compression system for the Jansz-Io with the aim of recovering gas more cost-effectively and with a smaller environmental footprint, according to news reports.
Jeff Schmoll, Chevron Australia’s general manager for major capital projects, said in March that “the Jansz-Io compression project will prolong the life of Gorgon’s Jansz-Io fields and was part of the original development plan for the project,” according to a miningweekly.com report.
Offshore Brazil, Chevron won six deepwater blocks in the presalt trend within the Campos and Santos basins in 2018. The six new blocks in the Brazil presalt cover 470,000 net acres.
On April 12 Chevron Corp. entered into a definitive agreement with Anadarko Petroleum Corp. to acquire all of the outstanding shares of Anadarko. The total enterprise value of the transaction is $50 billion, according to a press release. The transaction is expected to close in the second half of the year.
April 24 news update: Occidental Petroleum Kicks Off Anadarko Bidding War With Chevron
April 26 update from company: Chevron first-quarter 2019 results
May 9 news update: Chevron Bows Out Of Anadarko Takeover Battle With Occidental Petroleum
CNOOC Ltd. has offshore operations worldwide. The company holds a 100% interest in two exploration blocks offshore Newfoundland, Canada.
The company also owns interests in two major deepwater development projects, Stampede and Appomattox, and a number of other exploration blocks in the U.S. Gulf of Mexico (GoM) through its wholly owned subsidiary, Nexen Energy ULC, according to CNOOC Ltd.’s website. Among these, Stampede commenced production in February 2018.
Offshore Mexico, the company owns a 100% interest in deepwater exploration Block 1 and Block 4 of the Cinturón Plegado Perdido.
In addition, CNOOC Ltd. holds a 25% interest in the Stabroek Block offshore Guyana. Twelve exploration discoveries have been made in the block. The Liza oilfield Phase 1 construction was in good progress and is scheduled to commence production in 2020, the company reported in early April. The field development proposal design of Liza oilfield Phase 2 was completed and pending government approval as of early April. The final investment decision is planned to be made this year. In 2018 the Liza reservoir in the block was further successfully appraised. Five new successful discoveries, Ranger, Pacora, Longtail, Hammerhead and Pluma, were made and have further expanded the scale of reserve, according to the company’s 2018 annual report.
Offshore Brazil, the company also holds a 10% interest in the Libra deepwater presalt project, a 100% interest in Block 592 and a 20% interest in the Alto de Cabo Frio Oeste Block. Additionally, a 30% interest in the Pau Brasil Block was obtained by the company in 2018.
Near West Africa, CNOOC Ltd. owns a 45% interest in the OML130 Block offshore Nigeria, and in 2017 the company obtained a 65% operating interest in the AGC Profond Block offshore Senegal and Guinea-Bissau.
In the Norwegian Sea, the company holds a license issued by the government of Iceland for undertaking oil exploration operations northeast of the country.
CNOOC Ltd. also holds several frontier exploration licenses offshore Ireland.
In the North Sea, the company’s asset portfolio includes projects under production, development and exploration, mainly including a 43.2% interest in the Buzzard oil field and a 36.5% interest in the Golden Eagle oil field. These make the company the largest crude oil operator in the North Sea, according to CNOOC Ltd.’s 2018 annual report. The U.K. is one of CNOOC Ltd.’s key overseas development areas, with projects such as Buzzard and Golden Eagle substantially contributing to the company’s production.
Earlier this year, CNOOC Ltd. announced a new discovery on the Glengorm prospect offshore the U.K. Central North Sea, a January press release stated.
The Eastern South China Sea is the company’s other important crude oil producing area. As of year-end 2018, reserves and daily production volume in the Eastern South China Sea reached 599.2 MMboe and 216,877 boe/d, respectively, representing approximately 13.1% of the company’s total reserves and 17.4% of its daily production, according to the company’s 2018 annual report.
The Western South China Sea is one of the company’s most important natural gas production areas. As of year-end 2018, the reserves and daily production volume in the Western South China Sea reached 845.8 MMboe and 154,248 boe/d, respectively, representing about 18.4% of the company’s total reserves and 12.4% of its daily production. The Weizhou 6-13 oil field commenced production during 2018. In addition, the Wenchang 13-2 oilfield comprehensive adjustment project is expected to start production this year.
Looking ahead, six new projects are expected to come onstream in 2019. The Egina Field offshore Nigeria; the Huizhou 32-5 Field comprehensive adjustment and Huizhou 33-1 Field joint development project offshore China; the Appomattox project in the U.S. GoM; and the Bozhong 34-9 Field, the Caofeidian 11-1/11-6 comprehensive adjustment project and the Wenchang 13-2 comprehensive adjustment project offshore China are all scheduled to begin production this year, according to CNOOC Ltd.’s “2019 Business Strategy and Development Plan” press release. CNOOC Ltd. also plans to drill 173 exploration wells and acquire approximately 28,000 sq km (10,811 sq miles) of 3-D seismic data this year.
April 12 news update: CNOOC Signs PSC With Smart Oil For Bohai Bay Basin Block
April 24 news update: CNOOC, PetroChina Team Up In South China Sea
April 24 news update: CNOOC Extends North Sea Platform Deal With KCA Deutag
April 25 update from company: CNOOC 2019 First Quarter Review (presentation)
Upstream company ConocoPhillips has offshore operations located in the North Sea and offshore China, Indonesia and Malaysia as well as nonoperated assets in several offshore areas worldwide.
ConocoPhillips has significant developments offshore the U.K. in the North Sea and Norwegian Sea. Operated assets in Europe include the Greater Britannia and J-Area fields in the U.K. and the Greater Ekofisk Area in Norway.
“The company has leveraged its existing operations, infrastructure and basin expertise to create incremental growth projects in recent years, and development opportunities still exist in ConocoPhillips’ legacy areas in the North Sea,” according to the company’s website. “Production from the Southern North Sea in the U.K. ceased in 2018, and the focus of activity has now changed to decommissioning.”
During the fourth quarter of 2018, the company achieved first production from the Aasta Hansteen project in the Norwegian Sea and the Clair Ridge project west of the Shetland Islands, according to the company’s fourth-quarter and full-year 2018 results report.
ConocoPhillips also produces from fields in Bohai Bay offshore China. Block 11/05 in the Bohai Sea contains the Penglai 19-3, 19-9 and 25-6 oil fields, in which ConocoPhillips has 49% interest and CNOOC (the operator) has 51% interest. The project had 36 wells completed and online as of year-end 2018. According to a March 2019 company fact sheet, the Penglai 25-6 Phase 4A project was sanctioned by ConocoPhillips in 2018, and this project consists of one new wellhead platform that could add up to 62 wells. First production from Phase 4A is expected in 2021. Additional appraisal drilling and development studies are underway to assess further Penglai development opportunities. A full-field 3-D seismic program at Penglai continued in 2018 and is expected to be completed in 2019. The production periods for Penglai 19-9, 19-3 and 25-6 end in 2027, 2037 and 2045, respectively. ConocoPhillips reported 2018 average net production of 30,000 bbl/d of crude oil and 30,000 boe/d in Penglai.
In the South China Sea, one ILX well in the CNOOC-operated Panyu 4-1 area will be drilled prior to April 2020. The production period for the Panyu 4-1 area is 15 years upon commencement of commercial production, the fact sheet stated. ConocoPhillips has 49% interest in Panyu 4-1.
In Malaysia, ConocoPhillips holds 2.2 million net acres across six blocks in varying stages of exploration, development and production. Three of these blocks are located off the eastern Malaysian state of Sabah: Block G, Block J and the Kebabangan Cluster (KBBC). Three other blocks, Block SK304, Block SK313 and Block WL4-00, are operated by ConocoPhillips and are located off the eastern Malaysian state of Sarawak. Production growth continues from several fields in Block G, Block J and the KBBC.
Offshore Australia, ConocoPhillips is the operator (with 56.9% interest) of the Bayu-Undan Field in the Timor Sea. Last year the final development phase at Bayu-Undan was completed. ConocoPhillips reported 2018 average net production of 4,000 bbl/d of crude oil, 3,000 bbl/d of NGL, 6.7 MMcm/d (240 MMcf/d) of natural gas and 47,000 boe/d in Bayu-Undan, according to the company fact sheet.
ConocoPhillips also has E&P activities offshore Indonesia.
April 18 news update: ConocoPhillips Unloads Legacy British North Sea Assets For More Than $2 Billion
April 23 news update: TechnipFMC Bags EPCI Contract For ConocoPhillips TOR II Development
April 30 update from the company: ConocoPhillips Reports First-Quarter 2019 Results; Operating Plan Continues to Deliver Strong Free Cash Flow and Returns to Shareholders
Eni’s primary offshore operations are located off the coast of Africa, Indonesia, Mexico and Norway, though the company has interests in other offshore areas.
Offshore Algeria, Eni, Sonatrach and Total signed two agreements that include an exclusive partnership for offshore exploration in Algeria in a virtually unexplored geological province.
In Egypt, Eni operates through its subsidiary leoc. In March the company announced a new gas discovery in the Nour prospect in the Eastern Egyptian Mediterranean offshore Egypt, a press release stated. Eni is the operator (40% stake), with BP (25%), Mubadala Petroleum (20%) and Tharwa Petroleum Co. (15%).
Throughout 2018 and again in March of this year, Eni announced several new oil discoveries offshore Angola. “Agogo is the third discovery of commercial nature since the Block 15/06 Consortium decided to launch a new exploration campaign in 2018, leading to the discoveries of Kalimba and Afoxé,” according to a March 2019 press release. “The [latest] discovery opens new opportunities for oil exploration below salt diapirs in the northwest part of the prolific Block 15/06, thus creating new chances for unlocking additional potential value.”
Eni is the operator of Block 15/06 (36.8% interest), along with partners Sonangol P&P (36.8%) and SSI Fifteen Ltd. (26.3%). According to the release, the companies plan on appraising the discovery and starting the studies to fast track the block’s development.
Offshore Ghana, Eni started gas production in July 2018 from the Sankofa Field in the Offshore Cape Three Points Integrated Oil and Gas Project. “The field will provide 180 million standard cubic feet per day [5.1 MMcm/d] for at least 15 years, enough to convert to gas half of Ghana’s power generation capacity,” a press release stated.
In December 2018, Eni announced a Merakes East gas discovery in the East Sepinggan Block offshore Indonesia, a press release stated. Eni is the operator of the East Sepinggan contract area through its subsidiary Eni East Sepinggan Ltd. (85% interest) with PT Pertamina Hulu Energi East Sepinggan (15%).
Offshore Mexico, Eni’s wholly owned subsidiary Eni Mexico S. de R. L. de C. V. holds rights in six E&P blocks in the Sureste Basin, all as the operator. In October 2018, Eni signed a participating interest swap with Lukoil whereby Eni gave Lukoil a 20% stake in both the production-sharing contracts (PSC) for blocks 10 and 14, and at the same time acquired a 40% stake in Lukoil’s PSC for Block 12.
In October 2018, Eni announced a new oil discovery in the western Barents Sea offshore Norway. Equinor is the operator in the Skruis Prospect in PL 532 (50% interest), along with Eni (30%) and Petoro (20%). “The well will be permanently plugged and abandoned after an extensive data collection and sampling program,” a press release stated. “The Skruis discovery is part of Eni’s near-field exploration strategy that, in case of success, allows the exploitation of these thanks to the synergies with future infrastructures.”
April 22 news update: Eni Signs E&P Deal With Ras Al Khaimah Emirate
April 24 update from company: First-quarter 2019 results
In addition to its name change of Statoil to Equinor in May 2018, the Norwegian multinational energy company has had quite an eventful 2018 and 2019.
In April 2018, in partnership with Total, the company acquired Cobalt International Energy’s 60% operated interest in the North Platte discovery in the U.S. Gulf of Mexico for $339 million.
In Brazil, Equinor has interests in the BM-S-8 and Carcará North in the presalt area of the Santos Basin as well as in the BM-C-33 in the Campos Basin, containing the Pão de Açúcar discovery. In June 2018, Equinor deepened its position in Brazil’s presalt area with 28% interest in the Uirapuru production-sharing contract in the Santos Basin.
In March 2018, the company acquired 50% interest in two offshore wind development projects offshore Poland.
On the Norwegian Continental Shelf (NCS), Equinor was awarded 31 new exploration licenses early last year.
In November 2018, Equinor began construction of the Johan Castberg vessel at Kværner’s yard at Stord. “Johan Castberg is the next major development on the Norwegian Continental Shelf and will open a new area in the Barents Sea for Equinor. Johan Castberg’s development will have ripple effects equivalent to 47,000 man-years in Norway during the development phase,” said Anders Opedal, Equinor’s executive vice president for technology, projects and drilling, in a press release.
In December 2018, Equinor (operator) and partners began production at the deepwater Aasta Hansteen Field on the NCS. The Aasta Hansteen is the first deepwater development on the NCS and the world’s largest single-point articulated riser platform, according to a press release.
Earlier this year, Equinor and its partners, Petoro, Exxon Mobil and Total, have proven gas and condensate in the Norwegian Sea Ragnfrid North (6406/2-9 S) exploration well. Recoverable resources are estimated at 6 MMboe to 25 MMboe, a January press release stated.
In March Equinor received approval for extending the life of eight installations on the NCS: Gullfaks A, B and C (2036), Oseberg East (2031), Snorre A and B (2040), Norne (2036) and Åsgard A (2030), a press release stated. Equinor plans to extend the life of more than 20 NCS installations in total and expects to apply for extending the life of all older and relevant installations by 2031.
The company also has been busy offshore the U.K. In March 2018, the company became the operator of the Martin Linge Field and Garatiana discovery in the North Sea. Then in the second half of 2018, Equinor acquired a 40% operator share in the Rosebank project on the U.K. Continental Shelf from Chevron. Other partners in the field are Suncor Energy (40%) and Siccar Point Energy (20%). This “agreement allows [Equinor] to buy back into an asset in which we previously had a participating interest, demonstrating our strategy of creating value through oil price cycles,” said Al Cook, Equinor’s executive vice president for global strategy and business development and U.K. country manager, in a press release.
In October 2018, the company started production at the Oseberg Vestflanken 2 Field in the North Sea. “Remote-operated from the Oseberg field center, the new Oseberg H platform is the first unmanned platform on the Norwegian Continental Shelf,” according to a press release.
In addition, in March of this year, Equinor (operator) and its partners, Petoro, ConocoPhillips and Repsol, made an oil discovery from the Visund A platform in the Telesto exploration well in the North Sea. The resources are estimated at 12 MMbbl to 28 MMbbl of recoverable oil, a press release stated.
April 17 update from the company: Equinor wins seven exploration blocks offshore Argentina
April 19 update from the company: Equinor invests in new platform in Azerbaijan
April 24 update from the company: Oil discovery in the deepwater US Gulf of Mexico
April 30 update from the company: Equinor completes transactions with Faroe on NCS assets
May 1 update from the company: Situation normalized at Snorre B
May 2 update from the company: Statfjord A home to Stord
Exxon Mobil explores and operates in offshore areas worldwide.
In February Exxon Mobil made two additional discoveries offshore Guyana at the Tilapia-1 and Haimara-1 wells, bringing the total number of discoveries on the Stabroek Block to 12, a company press release stated. The estimated gross recoverable resource from the Stabroek Block is about 5.5 Bboe. Exxon Mobil affiliate Esso Exploration and Production Guyana Ltd. is the operator (45% interest) in the Stabroek Block with Hess Guyana Exploration Ltd. (30%) and CNOOC Petroleum Guyana Ltd. (25%). According to the release, there is potential for at least five FPSO vessels on the Stabroek Block to produce more than 750,000 bbl/d of oil by 2025.
Additionally, the Liza Phase 1 development offshore Guyana is progressing on schedule and is expected to begin producing up to 120,000 bbl/d of oil in early 2020, utilizing the Liza Destiny FPSO. Liza Phase 2 is expected to start up by mid-2022.
Last year Exxon Mobil increased its holdings in Brazil’s presalt basins after it won the Uirapuru exploration block with co-venturers Equinor and Petrogal Brasil during Brazil’s fourth presalt bid round, the Titã exploration block with co-venturer Qatar Petroleum during Brazil’s fifth presalt bid round, and eight additional exploration blocks during Brazil’s 15th bid round, according to company press releases.
In addition, in June 2018, Exxon Mobil completed the purchase of half of Equinor’s interest in the BM-S-8 Block offshore Brazil, which contains part of the 2-Bbbl presalt Carcara oil field.
Last year Exxon Mobil added 1.3 Bboe to its resource base, which included additions from new discoveries and strategic acquisitions, mainly in Guyana and Brazil, according to a March 2019 press release.
In addition, in February of this year, Exxon Mobil Exploration and Production Cyprus (Offshore) Ltd. made a natural gas discovery offshore Cyprus in the Eastern Mediterranean at the Glaucus-1 well. Further evaluation of Block 10 potential continues. Exxon Mobil is the operator (60% interest) in the block with Qatar Petroleum International Upstream O.P.C. (40%).
April 16 news update: Exxon Mobil Wins Three Exploration Blocks Offshore Argentina
April 18 news update: Exxon Mobil Tacks On Another Discovery Offshore Guyana
April 25 news update: Exxon Mobil Boosts Exploration Acreage Offshore Namibia
April 26 update from the company: Exxon Mobil Earns $2.4 Billion in First Quarter 2019
Hess is the sixth largest gross operated deepwater producer in the Gulf of Mexico (GoM). The company also has offshore assets in Europe, the Asia-Pacific and South America.
In the Stampede Field in the GoM, production started and first oil was achieved in January 2018. Production was scheduled to ramp up over the following 18 months. Hess is the operator (25% interest) in the field with co-venture owners Union Oil Co. (25%), CNOOC (25%) and Equinor (25%).
According to the company’s fourth-quarter 2018 results report, net production from the GoM was 68,000 boe/d, compared to 40,000 boe/d in the prior-year quarter.
In Nova Scotia, where BP Canada is the operator, Hess has 50% interest. The operator completed drilling of the Aspy exploration well in 2018 and is currently evaluating the data from the well, according to the fourth-quarter 2018 report.
In addition, Hess has a 50% working interest and is operator of the North Malay Basin natural gas asset, which includes nine discovered natural gas fields adjacent to the company’s existing interest in the Joint Development Area (JDA) between Malaysia and Thailand, operated by a joint venture called Carigali Hess. Petronas Carigali holds the remaining 50% of the North Malay Basin and also is Hess’ partner in the JDA.
Earlier this year, Hess announced positive results from the Tilapia-1 and Haimara-1 wells offshore Guyana, bringing the total number of discoveries on the Stabroek Block to 12, a Feb. 6 press release stated. Esso Exploration and Production Guyana Ltd. is the operator (45% interest) in the Stabroek Block with Hess Guyana Exploration Ltd. (30%) and CNOOC Petroleum Guyana Ltd. (25%).
Hess reported year-end 2018 offshore net production of 41,000 bbl of crude oil, 5,000 bbl of NGL and 1,897 cu. m (67,000 cf) of natural gas, according to the company’s report.
April 18 update from the company: Hess Announces 13th Discovery Offshore Guyana
April 25 update from the company: Hess Reports Estimated Results for the First Quarter of 2019
Husky Energy has operations and exploration prospects offshore China and Indonesia as well as offshore Newfoundland and Labrador. Husky reported offshore average production of 64,200 boe/d in its 2018 fourth-quarter and annual results report.
According to the company, the Liwan Gas Project was the first deepwater gas project offshore China. The Liwan 3-1 and Liuhua 34-2 fields share a subsea production system, subsea pipeline transportation and onshore gas-processing infrastructure. Husky holds 49% interest and operates the deepwater infrastructure while partner CNOOC Ltd. operates the shallow-water facilities. In addition, construction is underway at the third deepwater field, Liuhua 29-1, in which Husky holds 75% interest. A gas sales agreement is in place, with first production expected around year-end 2020, the company stated on its website.
Moreover, in the northern part of the South China Sea, Husky has production-sharing contracts in place for two exploration blocks, 15/33 and 16/25, in the Pearl River Mouth Basin.
Offshore Indonesia, Husky is advancing gas projects in the Madura Strait. These projects include the liquids-rich BD Project as well as the shallow-water MDA-MBH and MDK fields, which are being developed in tandem, with first gas anticipated in 2020, the company stated on its website. Husky holds 40% interest in these fields, which are being developed in partnership with operator CNOOC and an affiliate of Samudra Energy Ltd. Additional natural gas discoveries in the Madura Strait are being evaluated for commercial development.
Offshore Newfoundland and Labrador, Husky’s focus is in the Jeanne d’Arc Basin and Flemish Pass Basin, where the company and its partner have made recent discoveries.
First oil at the West White Rose Project is expected in 2022. Two additional infill wells at the White Rose Field are expected to be brought online before mid-year 2019.
Production at the SeaRose FPSO was suspended in November 2018 following an oil release from a flowline connector in the South White Rose Extension Drill Centre. Production at the SeaRose FPSO resumed operations at the end of January 2019 and will continue to ramp up through the second quarter as additional subsea drill centers are brought online, according to Husky’s 2018 fourth-quarter and annual results report.
In the Flemish Pass Basin, Husky and its partner have made discoveries at Mizzen, Harpoon, Bay du Nord and Baccalieu. Husky holds a 35% working interest.
April 26 update from the company: Husky Energy Reports First Quarter 2019 Results
LLOG Exploration Offshore LLC
LLOG Exploration’s activity is focused in the Gulf of Mexico (GoM). From January 2017 to January 2019, the privately owned E&P company boasts it made six of the 15 exploration discoveries in the deepwater GoM.
The majority of the company’s activity is located in the Mississippi Canyon. LLOG operates two floating production systems in this area—Who Dat and Delta House. Production activity where LLOG is the operator with 100% interest takes place in Block 705. In addition, the company has production activity in Block 707 (100% interest), Block 751 (100%), Block 503 (50.25%), Block 547 (50.25%), Block 199 (50%), Block 208 (52.3%), Block 252 (52.3%), Block 209 (52.3%), Block 253 (52.3%), Block 301 (69.62%) and Block 79 (70%), among others.
LLOG also has leasehold interests in additional blocks across the Mississippi Canyon as well as development activity in Block 816 (operator with 100% interest), Block 74 (18%) and Block 609 (28.5%). Seadrill’s West Neptune drillship is currently completing exploration and development operations for LLOG in the Mississippi Canyon.
In a January operational update, the company announced it drilled a successful discovery on its exploratory prospect, Nearly Headless Nick, in Mississippi Canyon Block 387, and it is expected to be tied back to the nearby LLOG-operated Delta House facility in Mississippi Canyon Block 254.
Five of LLOG’s GoM deepwater discoveries (eight wells) were placed on production in 2018, according to the January 2019 update. Nine wells, which include four development wells at Who Dat, Mandy and Red Zinger and five wells from three new fields, Stonefly, Buckskin and Nearly Headless Nick, are expected to be brought online this year.
The company also is operator with 100% interest in blocks 644, 687, 688 and 731 in the Alaminos Canyon. LLOG also has production activity in the South Timbalier area in blocks 231 and 232 with 75% interest each.
In the Keathley Canyon area, the company has development activity with 51.15% interest in Block 736 and 33.8% interest in blocks 785, 828, 829, 830, 871 and 872.
LLOG’s production activity in the Green Canyon is located in Block 141 with 45% interest and blocks 157 and 201 with 85% interest each. The company has development activity in Green Canyon blocks 345, 389, 390, 434 and 478 with 34% interest each. LLOG also has leasehold interests in Green Canyon Block 154 (46.2% interest), Block 242 (47.5%), Block 472 (70%), Block 516 (70%), Block 728 (70%), Block 816 (70%), Block 987 (53.8%) and Block 955 (50%), among others.
In the Walker Ridge area of the GoM, LLOG has development activity in Block 95 with 27.1% interest as well as leasehold interests in Block 149 (70% interest), Block 21 (23.1%), Block 23 (90%), Block 28 (47.5%) and Block 72 (47.5%).
April 29 update from the company: LLOG Exploration & Repsol Sign an Asset Exchange and Joint Participation Agreement in the Deepwater GoM
Lundin Petroleum AB
Lundin Petroleum’s operations are focused offshore Norway. The independent E&P company has interests in the Alvheim and Utsira High areas and in the Southern Barents Sea, Norwegian Sea and North Sea.
Lundin Petroleum’s 2019 production guidance is between 75,000 boe/d and 95,000 boe/d, according to the company’s website. Production for 2018 amounted to 81,100 boe/d, and the production from Edvard Grieg represented about 75% of that production.
President and CEO Alex Schneiter said in the company’s year-end 2018 report, “The 2018 exploration and appraisal campaign was one of our busiest, and we enjoyed significant success with new discoveries made near our core areas on the Utsira High and the Alvheim area. We matured our appraisal opportunities further toward development and now have seven potential new projects in the pipeline.”
Lundin Petroleum recently completed several development projects in Norway, but the company said development of the Johan Sverdrup project is its main focus in the near term. Phase 1 is scheduled to come onstream in November of this year and expected to reach a gross production rate of up to 440,000 bbl/d of oil. Phase 2 is expected to begin production in the fourth quarter of 2022.
“Our production is set to double when the large Johan Sverdrup Field in the North Sea starts production in late 2019,” according to the company’s website.
In January Lundin Petroleum’s wholly owned subsidiary, Lundin Norway AS, entered into an agreement with Lime Petroleum AS to acquire its entire Utsira High acreage position covering the Rolvsnes and Goddo basement area, a press release stated. The acquisition takes Lundin Norway’s working interest in the Rolvsnes oil discovery in PL338C and in the recently awarded, adjacent PL338E1 from 50% to 80% and the Goddo prospect in PL815 from 40% to 60%. An extended well test will be conducted at Rolvsnes in 2021, and an exploration well will be drilled in the Goddo area this year. The combined gross resource potential of the Rolvsnes and Goddo area is more than 250 MMboe, according to the release.
April 4 news update: Lundin Sanctions Rolvsnes Extended Well Test Project
May 2 update from the company: Report for the three months ended 31 March 2019 (regulatory)
Murphy Oil Corp.
Murphy Oil’s offshore operations are located offshore Southeast Asia, Eastern Canada and in the Gulf of Mexico (GoM). The company’s offshore business produced 83,000 boe/d in the fourth quarter last year, according to Murphy’s fourth-quarter and full-year 2018 results report.
Offshore Malaysia and Brunei, production in the fourth quarter last year averaged 46,000 boe/d. Block K and Sarawak averaged 28,000 bbl/d of liquids, while Sarawak natural gas production averaged more than 2.8 MMcm/d (99 MMcf/d), according to the report.
Offshore Vietnam, Murphy received the Declaration of Commerciality for the LDV Field in early 2019 and expects to move forward with sanction later this year.
In the GoM, production in the fourth quarter last year averaged 32,000 boe/d. During the quarter, the Dalmatian subsea pump was installed, and it is delivering gross incremental production of more than 10,000 boe/d, an increase of 250% from prior quarter production, with 96% uptime, according to the report.
Offshore Canada, production in the fourth quarter last year averaged 5,100 boe/d.
In March of this year, the company announced the sale of its Malaysian portfolio for $2.127 billion. The sale is expected to close by the end of the second quarter, according to the company.
Looking ahead, Murphy is allocating about $287 million of its 2019 capex to its global offshore assets of which 75% will be spent in the GoM, 10% offshore Vietnam and Brunei, and the remainder offshore Canada.
The capex in the GoM is primarily related to field development projects, including the Dalmatian subsea pump and the Samurai Field development activities. Murphy also will be investing capital for a pre-FEED waterflood study for the St. Malo Field.
March 21 news update: Murphy Oil Cashes Out Of Malaysia In Over $2 Billion Sale
April 23 news update: Murphy Oil To Buy LLOG Deepwater Gulf Of Mexico Assets For Up To $1.6 Billion
May 2 update from the company: First-quarter 2019 Financial and Operating Results
Noble Energy’s offshore operations are located off the coast of Arica and in the Eastern Mediterranean.
In the Eastern Mediterranean, the company has 564,000 gross acres (as of year-end 2016) and reported year-end 2016 results of 8 MMcm/d (283 MMcfe/d) net sales volumes and 991 Bcm (35 Tcf) discovered gross resources, according to data provided on Noble’s website.
In the Levant Basin, the company said it discovered two of the world’s largest offshore natural gas fields offshore Israel and the first natural gas resources offshore the Republic of Cyprus. Noble’s Tamar Platform supplies 60% of the country’s power generation, and the Leviathan Field is on track for first production by the end of 2019.
“Our operations in the region stand to achieve more milestones in the coming years. The Tamar Field produced sales volumes of approximately 25.4 MMcm/d (900 MMcf/d) gross in 2016,” the company said on its website. “The Leviathan Field is expected to provide a second source of supply to Israel while also delivering exports to meet the growing demand of neighboring countries, and finalizing the Aphrodite Field development plan is in progress.”
According to the company’s 2019 guidance report, first gas sales from Leviathan are expected by the end of the year, “delivering substantial production and cash flow growth in 2020.”
Offshore Equatorial Guinea and Cameroon, the company has 296,000 net acres (as of year-end 2016) and reported year-end 2017 results of 65,000 boe/d sales volumes, 108 MMboe total proved reserves and 28 gross productive wells, according to Noble’s website.
The company also holds 60% operated working interest in the 671,000-acre Doukou Dak Block in the South Gabon Basin, where it acquired and is processing a 2,500-sq-km (965-sq-mile) 3-D seismic survey.
Fourth-quarter 2018 net sales volumes from the company’s assets offshore Israel totaled 6.3 MMcm (224 MMcf/d) of natural gas equivalent, and gross production from those assets averaged about 28.3 MMcm (1 Bcf/d) of natural gas equivalent, according to Noble’s fourth-quarter and full-year 2018 results report. Sales volumes offshore West Africa were 60,000 boe/d, including 20,000 bbl/d of crude oil.
Oil and Natural Gas Corp. Ltd.
Oil and Natural Gas Corp. (ONGC) is the largest E&P company in India and has discovered six out of the seven oil and gas producing basins in and around the country. It has cumulatively produced 998 million metric tonnes of crude and 645 Bcm (22.7 Tcf) of natural gas, according to ONGC’s website. The company has 14 seismic crews and 268 offshore installations.
“Overall, fiscal year 2018 was a solid year for ONGC,” said Shashi Shanker, the company’s chief managing director. “Our standalone hydrocarbon production increased year on year. The uptick in gas output was particularly impressive. Crude oil output increased marginally from fiscal year 2017 levels, and gas output increased by over 6% to 23.5 Bcm [about 830 Bcf] from 22 Bcm [about 777 Bcf] in fiscal year 2017.”
In March 2019, ONGC won five out of 23 contract areas (all with 100% participating interest) in the Discovered Small Fields Bid Round-II, a press release stated. Of the five areas, one was onshore and four were offshore Mumbai. ONGC will undertake E&P activities, and the nearby existing facilities of the company will be used for processing/evacuation of oil and gas to be produced from these fields.
ONGC also is working on its mega deepwater development initiative for integrated development of the KG-DWN-98/2 (Cluster-2) Project off the east coast of India. “Cluster-2 development will have water depths ranging from 350 m to 1,400 m [1,148 ft to 4,593 ft] and is one of the most capital-intensive and technologically challenging projects off the east coast of India,” the company said in an October 2018 press release. “Total peak gas production rate from Cluster-2 is envisaged to be about 16 MMscm/d [million metric standard cubic meter per day] and have a peak oil production rate of 80,000 bbl/d.”
The company expects first gas production by December 2019, first oil by March 2021 and overall project completion by August 2021, according to the release.
In addition, ONGC has set up four 3-D virtual reality centers known as “Third Eye” for real-time dissemination and information of onshore and offshore applications. These centers are used for E&P activities including real-time surveillance of producing oil and gas fields.
Mexican state oil company Pemex reported that 82% of its crude oil production and 55% of its natural gas production is based offshore, according to its fourth-quarter 2018 results report. The company also reported that 54% of its development rigs and 54% of its exploration rigs were designated for offshore operations.
In 2018, 143 development wells were completed. Production from these fields amounted to 52,000 bbl/d of crude oil and 1.2 MMcm/d (43 MMcf/d) of gas, according to the report. Out of these 143 wells, 21 were offshore.
In deep waters, delineation well Doctus-1DL was successfully concluded, providing information leading to a new development area of light crude oil in the Perdido Area, the company stated in the report.
Additionally, Pemex expects to add 210,000 bbl/d and 9.9 MMcm (350 MMcf/d) of new production by year-end 2020 from the development of six shallow-water fields in the Gulf of Campeche, according to an October 2018 S&P Global Platts article. In the article, CEO Carlos Trevino said the six fields are at different phases: Xikin and Esah are in development, Koban and Kinbe are being assessed, and Mulach and Manik are in the early stages of exploration.
In October 2018, Pemex discovered seven reservoirs in two new wells in Mexico’s Southeast Basin, named Manik-101A and Mulach-1, according to a company press release. The two wells are estimated to produce more than 180 MMboe in 3P reserves.
Pemex also is assessing its Kinbe and Koban fields. The Kinbe Field, located 28 km (17 miles) from Tabasco, Mexico, is expected to produce light crude. The Kinbe-1 well produced more than 5,000 bbl/d during production trials, and Kinbe holds 3P reserves estimated at more than 120 MMboe, according to a press release. Pemex also is delineating its Koban Field. The Koban well holds gas and condensate with estimated 3P reserves of 205 MMboe.
In an October 2018 press release, Pemex said it would soon begin developing its Xikin and Esah shallow-water fields. Both fields hold a combined 360 MMboe of 3P reserves. Xikin is in shallow waters 24 km (15 miles) from the coast of Tabasco, Mexico. The total depth of the field is located between 6,400 m and 7,050 m and will produce light oil. It has 3P reserves estimated to be about 230 MMboe. Esah is located 94 km (58 miles) from Ciudad del Carmen, Campeche. The field will primarily produce crude with 3P reserves of 130 MMboe.
March 19 news update: Pemex Plans To Triple Oil Well Drilling This Year To Boost Output
April 13 news update: No Further Cut To Pemex Credit Rating Expected: Mexican Minister
April 30 update from the company: First-quarter 2019 Results
Brazilian company Petrobras’ oil and gas E&P activities are the largest components of its investment portfolio and are focused on research, discovery, identification, production and acquisition of oil and gas reserves, both offshore and onshore.
Petrobras is the world leader in production in deep water and ultradeep water, according to the company’s 2018 annual report. The company’s activities focus on oil reservoirs in deep and ultradeep waters in Brazil, which in 2018 accounted for 85% of its entire production and were responsible for 92% of its proven reserves on Dec. 31, 2018. Petrobras also operates in mature fields in shallow waters and onshore fields. Outside of Brazil, the company operates in South America, the Gulf of Mexico and West Africa.
In 2018 the annual average production of oil and gas, considering Brazil and abroad together, was 2.63 MMboe/d, the company stated. Production in the presalt layer accounted for 45% of total oil and gas, post-salt deep water and ultradeep water accounted for 39%, shallow water accounted for 5% and land fields accounted for 11%, according to the company’s 2018 financial results report released Feb. 27.
Four new production systems started production in 2018, three in the presalt in the Santos Basin (P-74, P-75 and P-69) and one in the Campos Basin (FPSO Cidade de Campos dos Goytacazes). This year Petrobras began to produce in the presalt in the Santos Basin with the P-67, P-76 and P-77 production systems.
April 22 news update: Petrobras Details Offshore Find In Sergipe Basin
Petrobras will release its first-quarter 2019 results on May 7.
Established in 1974, Petroliam Nasional Berhad (PETRONAS) is Malaysia’s fully integrated oil and gas multinational company. As the custodian of Malaysia’s national oil and gas resources, the company explores, produces and delivers energy.
In 2018 PETRONAS made 10 exploration discoveries (nine Malaysia and one international), signed 16 new production-sharing contracts (five Malaysia and 11 international) and 27 of its projects achieved first hydrocarbon (eight greenfield and 19 brownfield), according to PETRONAS’ fourth-quarter and year-end 2018 financial results announcement.
As of October 2018, PETRONAS has an average of nine to 10 jackup rigs, two to three tender-assisted drilling rigs, two to three hydraulic workover units, 10 wellhead platforms, one central processing platform and three heavy-lift campaigns, according to the PETRONAS Activity Outlook 2019-2021.
The company expects about 180 total metric tonnes for three subsea trees and one floating storage and offloading (FSO) unit this year, and it expects about 460 total metric tonnes for two subsea trees, one FSO and two vent platforms in 2020, according to the report. From 2019 through 2021, PETRONAS’ plans for its offshore development will be about 20 greenfield projects (all with new facilities development; about 30% are oil projects) and about 30 brownfield projects (about 75% are oil projects; 10% involve new facilities development).
According to the report, the company’s 2019 upstream activity outlook includes offshore fabrications (five to six wellhead platforms and one to two central processing platforms), offshore installations (eight to nine projects for heavy-lift barge and three to four projects for pipelay barge), floaters (one aframax),
underwater services (DP2 support vessels), marine vessels and decommissioning (one wellhead platform, three subsea trees, one FSO and 50 wells).
Santos Ltd.’s upstream offshore assets are located off the coasts of northern and western Australia.
In November 2018, Santos enhanced its position in western Australia through the acquisition of Quadrant Energy.
Offshore the North West Cape, the Van Gogh and Coniston/Novara oil fields are serviced by the Ningaloo Vision FPSO vessel and the Pyrenees oil project includes oil from the Crosby, Ravensworth and Stickle fields and the Pyrenees Venture FPSO vessel.
In addition, the company has had exploration success in the Carnarvon’s Bedout sub-basin with the Dorado and Roc discoveries and in the Crown and Lasseter discoveries in the Browse Basin.
The company’s offshore resource positions across northern Australia include the Crown-Lasseter discoveries in the Browse Basin (Santos 30%) and the Petrel-Tern discoveries in the Bonaparte Basin (Santos 35% to 40%).
In February 2018, Santos reached an agreement with Beach Energy to become 50:50 joint venture partners across NT/P82, NT/P85, NT/P84 and WA-454-P in the Bonaparte Basin offshore Northern Australia. Santos will operate all four permits.
April 16 news update: Santos Makes Find With Corvus Probe
April 17 update from the company: 2019 First Quarter Activities Report
May 2 update from the company: 2019 Annual General Meeting (Speeches Transcription)
One of Saudi Aramco’s recent developments is the offshore Manifa oilfield megaproject located in the Arabian Gulf. Instead of building 30 offshore platforms, the company converted more than 70% of the field into an onshore field to avoid damaging the ecosystem. The design involved the creation of 27 man-made islands, all made from 45 MMcm (1.5 Bcf) of sand reclaimed from the seabed. The islands act as onshore drill sites above the offshore oil field, and they support equipment while elevated bridges allow normal flows of currents and sea life to continue. The development includes 14 bridges, 13 offshore platforms, 15 onshore drill sites, 350 new wells, injection facilities, multiple pipelines and a 420-MW heat and electricity plant. In 2017 the company reached its target of 900,000 bbl/d of oil.
“The result of the collaborative effort was an innovative plan to reach Manifa Field—primarily located in shallow water—through building a world-class causeway, bridges and laterals to connect the man-made islands,” the company stated in a 2017 media release. “The computerized modeling of the 27 drilling islands, connected by a 42-kilometer [26-mile] causeway and 14 bridges to allow natural water circulation at Manifa Bay, has significantly contributed to enhance the natural flow of water, maintaining the bay as a perfect environment for shrimp and fish populations to grow.”
Saudi Aramco said Manifa is one of the world’s largest engineering projects, noting that the construction phase alone required more than 4 million man-hours to complete, according to news reports.
In December 2017, Saudi Aramco released a new AUV that can conduct offshore platform debris surveys to identify seabed clearance and potential debris, a press release stated.
April 1 news update: Saudi Aramco Eclipses Top Earner Apple Ahead Of Debut Bond Sale
Check out Hart Energy's interview "Autonomous Technology Push In Oil Fields" with Huseyin Seren, a scientist at Saudi Aramco’s Houston Research Center. He showed us a type of autonomous wireless device that drops down into wells allowing for significant data retrieval. The sensor ball can acquire a range of downhole data, including fluid density, viscosity and fluorescence.
Shell operates in more than 70 countries and has offshore operations across the world.
In the Gulf of Mexico (GoM), Shell’s operations produce about 355,000 boe/d, more than 50% of the company’s U.S. oil and gas production. The company has an interest in about 400 federal offshore production leases.
Shell’s largest operated deepwater assets in the GoM include Auger, Mars, Olympus, Perdido, Ursa, Appomattox and Stones.
Last year Shell announced one of its largest U.S. GoM exploration finds in the last 10 years from the Whale deepwater well, in which Shell is the operator with 60% interest, according to the company’s 2018 annual report. It was discovered in the Alaminos Canyon Block 772.
In April 2018, Shell announced the final investment decision to develop the deepwater Vito Field (Shell has 63.1% interest). The field is expected to reach an average peak production of 100,000 boe/d, the report stated. The company also has continued with the development of the Appomattox project, with first oil expected this year.
In May 2018, Shell announced a large exploration discovery in the Norphlet geologic play from the Dover deepwater well. The Shell-operated Dover is the company’s sixth discovery in the Norphlet and is located about 20 km (12 miles) from the Appomattox platform.
Also in May 2018, production started from the Kaikias deepwater project (80% interest). Kaikias is a subsea tieback to the Shell-operated Ursa platform. The Kaikias estimated peak production is 40,000 boe/d, the report stated.
The Stones project began production in 2016 and is the deepest offshore oil and gas producing project in the world (2,896-m [9,500-ft] water depth), according to the company. It is estimated to have a peak annual production of 50,000 boe/d.
Offshore Brazil, Shell operates several producing fields in the Campos Basin: the Bijupirá and Salema fields (80% interest) and the BC10 Field (50% interest). The company’s operations portfolio also includes the Gato do Mato Field in the Santos Basin and the adjacent Sul de Gato do Mato area (80% interest). Additionally, Shell has 10 offshore exploration concessions in the Barreirinhas Basin (Shell’s interest ranges from 50% to 100%) and a presalt production-sharing contract (PSC) for the Shell-operated Alto Cabo Frio Oeste (55% interest).
Offshore Nigeria, Shell’s main deepwater activities are carried out by Shell Nigeria Exploration and Production Co. Ltd. (SNEPCO), which has interests in four deepwater blocks. SNEPCO operates oil mining licenses (OMLs) 118 and 135 and also has a 43.8% nonoperating interest in OML 133 and a 50% nonoperating interest in oil prospecting license 245.
Gumusut-Kakap, with a production capacity of 150,000 boe/d, was Shell’s first deepwater development in Malaysia, which started production in 2014. A Phase 2 development is in the execution phase, with first oil targeted for the third quarter of this year. Malika, which was Malaysia’s first tension-leg platform (TLP) and Shell’s first TLP outside of the GoM, began production in December 2016.
Offshore Mauritania, Shell signed two PSCs with the government for the exploration and potential future production of hydrocarbons in blocks C-10 and C-19 (Shell has 90% interest as operator) in July 2018, according to the report. The blocks are located in the West African Atlantic Margin exploration basin.
Shell also won nine deepwater exploration blocks offshore Mexico last year and will be the operator of all nine blocks.
March 29 news update: Shell Awards Offshore UK Contract To Subsea 7
April 11 news update: Shell Divests Gulf Of Mexico Stake To Israel’s Delek Group For Nearly $1 Billion
April 11 news update: Shell Awards North Sea, Western Australia Seismic Survey Deal To Shearwater
April 17 news update: Halliburton Wins Shell Offshore Exploration Contract In Brazil
April 24 news update: Shell Makes Deepwater Discovery In Gulf Of Mexico
April 24 news update: Shell Reportedly In Talks To Buy BP Stake In North Sea Gas Field
May 2 update from the company: First-quarter 2019 Results
Talos Energy Inc.
Talos Energy operates off the Gulf of Mexico (GoM), acquiring, exploiting and exploring the region. The company reported year-end 2018 proved reserves of 151.7 MMboe, of which 76% is proved developed, according to the company’s fourth-quarter and full-year 2018 financial and operational results report. Talos also reported production of 53,400 boe/d, or 4.9 MMboe, in the fourth quarter last year.
In May 2018, Talos Energy LLC and Stone Energy Corp. merged to form a new public company, Talos Energy Inc. The two companies completed a strategic transaction pursuant to which both became wholly owned subsidiaries of the company.
In the report, Talos CEO Timothy Duncan said, “The benefits of the combination have shown results immediately, as we are a stronger, free cash flow positive company with ample liquidity and a significant inventory of drilling locations in both the U.S. Gulf of Mexico and offshore Mexico. Our strategy of executing asset management and drilling projects around existing infrastructure in the U.S. Gulf of Mexico complements our high-impact exploration and development projects in offshore Mexico.”
The Helix Producer 1 drydock project was executed in the first quarter of this year by Talos and partner Helix Energy Solutions. Production subsequently restarted at the Phoenix complex in March. In addition, Talos is executing a series of deepwater subsea tieback projects, namely the Mt. Providence, Tornado 3 and Boris 3 wells. Talos expects to bring the Tornado 3 and Boris 3 wells online in April and May of this year, respectively, “which will put Talos in a position to grow production year over year while continuing to generate free cash flow in the current price environment for 2019,” the report stated.
In shallow water, the company’s asset management and drilling activities have allowed assets, such as Ewing Bank 305/306, to achieve production levels not seen in the last 15 years, according to Talos.
In January of this year, Talos acquired the Antrim stranded discovery from Exxon Mobil and entered into partnerships to drill two deepwater projects this year, the Bulleit and Orlov prospects.
On the Zama project, the company’s historic discovery offshore Mexico, Talos confirmed the oil-water contact per its geological model and encountered more sand than expected in the first downdip location, the report stated.
In addition, Talos will start to execute on the inventory it acquired as part of the cross-assignment of interest between Block 2 and Block 31, which includes the low-risk but high-impact Olmeca project on Block 31, according to the report.
Talos Energy announced on April 23 that it plans to release its first-quarter 2019 results report on May 8.
Total is the world’s fourth largest energy major and an integrated operator working across the entire oil and gas value chain in more than 130 countries.
In 2018 Total’s production grew more than 8% to a record level of 2,800 boe/d and led to a 71% increase in the company’s E&P net operated income. The year was highlighted by the startup of Ichthys in Australia, Yamal LNG in Russia, deepwater projects Kaombo North in Angola and Egina in Nigeria, as well as the counter-cyclical acquisitions of Maersk Oil and new offshore licenses in the United Arab Emirates.
This year the company has two startups planned in the North Sea, where Total became the second largest operator: Culzean (operator) with 100,000 boe/d and Johan Sverdrup with 440,000 boe/d (expansion to 660,000 boe/d). In addition, an investment decision is expected on the Glendronach discovery. “The [North Sea] region will contribute in a major way to the growth of Total’s production in the coming years,” a press release stated.
Total’s production in sub-Saharan Africa is led by the Gulf of Guinea comprising Angola, Nigeria, Congo and Gabon. The region, where Total operates 11 FPSOs, accounts for 25% of the company’s production.
In 2018 Total delivered positive news on exploration. It first announced a new discovery in the Gulf of Mexico (Ballymore, Chevron-operated). “This major discovery gives us access to large oil resources and follow-on potential in the emerging Norphlet play,” said Arnaud Breuillac, president of Exploration & Production at Total, in a company press release. “We will work together with Chevron on the appraisal of this discovery and a cost-effective scheme to ensure a rapid, low breakeven development.”
Total also successfully appraised the A6 Block (Shwe Yee Htun-2 discovery) offshore Myanmar and later announced two new gas finds in the North Sea (Glendronach and Glengorm in the U.K.).
Earlier this year, Total also discovered a new gas province offshore South Africa with the discovery on the Brulpadda prospect. “With this discovery, Total has opened a new world-class gas and oil play and is well positioned to test several follow-on prospects on the same block,” a company press release stated.
In addition, Total has set a number of objectives to integrate climate into its strategy, which includes reducing 15% greenhouse gas emission (scopes 1 and 2) by 15% on operated oil and gas facilities as well as reducing the intensity of methane emissions of the E&P segment’s operated facilities to less than 0.2% of the commercial gas produced by 2025, the company stated in its 2018 Registration Document released in March 2019.
April 2 news update: Total Cranks Up Second FPSO At Kaombo Offshore Angola
April 26 update from the company: First-Quarter 2019 Results
This story first appeared in E&P magazine's "2019 Offshore Technology Yearbook" issue, which published in May. Read the other "2019 Offshore Technology Yearbook" articles:
Operators Foresee Vast Potential (story above)
Americas and Middle East Put Offshore Back on the Map
The new recoverable resource estimate, which jumped by 2 Bboe, excludes the Uaru discovery.
Eni has made a gas and condensate discovery in the Mahani exploration prospect located onshore in the Area B Concession of Sharjah (UAE) on Jan. 27, which was awarded to Eni in the first International Competitive Exploration Licensing Round conducted by the Petroleum Council of Sharjah.
Companies added three oil rigs in the week to Jan. 24, bringing the total count to 676, energy services firm Baker Hughes Co. said in its weekly report.