GENERAL INTEREST Quick Takes
Var Energi to buy ExxonMobil’s Norway upstream assets
ExxonMobil Corp. signed an agreement to sell its non-operated upstream assets in Norway to Var Energi AS for $4.5 billion as part of its plans to divest $15 billion in nonstrategic assets by 2021 (OGJ Online, Sept. 6, 2019).
The transaction includes ownership interests in more than 20 producing fields operated mostly by Equinor, including Grane, Snorre, Ormen Lange, Statfjord, and Fram, with a combined production of 150,000 boe/d this year.
The transaction is expected to close in this year’s fourth quarter, subject to standard conditions including approvals from regulatory authorities. Many of the ExxonMobil employees impacted by the sale will transfer to positions at Var Energi, ExxonMobil said in a press statement.
In 2017 ExxonMobil sold its ownership interests in Balder, Jotun Ringhorne, and Ringhorne East fields to Point Resources.
The ExxonMobil refinery in Slagen and network of 250 independently owned Esso-branded retail sites are unaffected by the sale.
Chrysaor complete purchase of UK E&P units
ConocoPhillips has completed the sale of two of its UK subsidiaries to Chrysaor E&P Ltd. for $2.675 billion, plus interest and customary adjustments (OGJ Online, Apr. 18, 2019).
Privately owned Chrysaor acquired the UK units that, together, indirectly hold the exploration and production assets of ConocoPhillips in the UK, as well as an ongoing decommissioning program in the UK southern North Sea, which Chrysaor expects to have materially completed by 2022.
In this year’s first half, production associated with the UK assets was 72,000 boe/d. There is no impact to third-quarter production guidance as a result of the sale, ConocoPhillips said.
Contango to acquire White Star Petroleum assets
Contango Oil & Gas Co., Houston, has agreed to acquire the assets of White Star Petroleum LLC and certain affiliates as a part of the White Star Chapter 11 bankruptcy, 363 sales process.
Contango will acquire 15,000 boe/d of production, 20 million boe of proved developed producing reserves, and 315,000 net acres in Oklahoma split into three areas for $132.5 million.
Assets include 45,000 net acres in the STACK district with 36 operated wells and 135 non-operated wells; 31,800 net acres in the Anadarko district with 49 operated wells and 110 non-operated wells; and 238,000 net acres in the Cherokee district with 490 operated wells and 73 non-operated wells.
The production is liquids weighted at 63% oil and natural gas liquids, and the acreage is 80% held by production. The assets also include integrated gathering and saltwater disposal systems.
The transaction is expected to close in this year’s fourth quarter, subject to conditions. After adjustments, the total consideration to be paid in cash at closing is estimated to be less than $100 million.
Huntley & Huntley Energy renamed Olympus Energy
Huntley & Huntley Energy Exploration LLC, a privately held independent natural gas company in the Appalachian basin, has changed its name to Olympus Energy LLC.
Headquartered in Canonsburg, Pa., the company specializes in upstream and midstream development of gas resources in the Appalachian basin.
It holds more than 100,000 largely contiguous operated acres in southwestern Pennsylvania in the Marcellus, Utica, and Upper Devonian fairways.
Exploration & Development Quick Takes
Irish exploration ban hits future licensing
The Irish Offshore Operators’ Association welcomed clarification by the government that a ban on offshore oil exploration announced at the United Nations Climate Action Summit in New York does not apply to existing licenses.
Taoiseach (Prime Minister) Leo Varadkar said on Sept. 23 his government would halt exploration for oil but not for natural gas as a response to climate change.
Ireland produces no oil and small amounts of gas offshore.
An IOOA statement said the government’s “clarification is clear” that the proposals relate to future applications and that existing licenses remain valid.
“However, it is important that further clarity is given on how the government’s proposal for future licensing rounds will be implemented,” said Chief Executive Officer Mandy Johnston.
Government officials from France and New Zealand also announced bans on oil and gas exploration, onshore and offshore, at the Climate Summit. France had banned the activity in 2017, and New Zealand ended offshore licensing last year.
ANPG discusses frontier offshore blocks
Representatives of the National Agency of Petroleum, Gas, and Biofuels of Angola (ANPG) discussed details of ANPG’s latest exploration and production bid round covering 10 frontier offshore blocks during a road show stop in Houston on Sept. 10.
The latest bid round involves blocks in the following areas:
- Namibe basin—Blocks 11, 12, 13, 27, 28, 29, 41, 42, and 43.
- Benguela subbasin—Block 10.
The blocks currently have no oil and natural gas production. ANGP representatives said seismic data interpretation has helped petroleum engineers identify horsts and grabens associated with Barremian rifting as well as Albian salt tectonics. Tertiary depocenters and turbiditic channels also have been identified, ANPG representatives said.
Contracts cover 5 years for exploration periods and 25 years for production periods.
IHS Markit assisted ANPG in the bid round after having last hosted round promotions for Angola in 2005, and 2007-08, which led to the largest signing bonuses on record for individual blocks.
GeoPark strikes oil on Llanos 34 block in Colombia
GeoPark Ltd. made an oil discovery along the third and most western major fault trend on Colombia’s Llanos 34 block, potentially opening a new play, it said. Additional production history is required to determine the stabilized flow rates of the well and further appraisal and development drilling will be necessary to determine the extent of the field.
The Guaco 1 well was drilled to 11,936 ft TD. Like other Llanos 34 fields, it appears to be both a structural and stratigraphic trap. Oil shows during drilling and petrophysical analysis indicated the potential for hydrocarbons in both the Guadalupe and Mirador formations. A production test conducted with an electric submersible pump in the Guadalupe formation resulted in a production rate of 960 b/d of oil, 24.6° API, 0.3% water cut, through a 35/64-in. choke at 50 psi wellhead pressure.
Surface facilities are in place and the well is in production. The Guaco discovery marks the 14th oil field discovered and put into production by GeoPark since acquiring Llanos 34.
GeoPark is operator of the 82,000-acre Llanos 34 block and holds 45% interest.
Independent confirms Harvey gas strike
The Maersk Resilient jack up rig has moved off location after drilling an appraisal well that operator Independent Oil & Gas PLC said confirms a 1984 Arco gas discovery in the southern UK North Sea.
London-based Independent will assess development of the Harvey structure after coring and logging the 48/24b-6 well, which went to 7,537 ft MD in the Permian Leman sandstone on License P2085. The firm also shot a vertical seismic profile.
Initial analysis of wireline data demonstrates the presence of a 49-ft gas column at the top of the reservoir, which the well encountered at 7,088 ft MD.
Under a July farm-out agreement, CalEnergy Resources Ltd., a London subsidiary of Berkshire Hathaway Energy Co., has an option to acquire a 50% interest in the Harvey development within 3 months of completion of the appraisal well.
Drilling & Production Quick Takes
Alberta lifts allowable oil output rate
Alberta is raising allowable oil production in the province by 10,000 b/d in November and December from the October level.
The government imposed output cuts totaling 325,000 b/d at the start of the year in response to pipeline congestion lowering oil values at points of production (OGJ Online, Dec. 3, 2018). New production caps will be 3.8 million b/d in November and 3.81 million b/d in December.
The October limit was 3.79 million b/d.
January’s production limit was 3.56 million b/d.
The government updated the curtailment policy in August to raise the production rate exempt from limits to 20,000 b/d from 10,000 b/d. The move dropped to 15 from 29 the number of producers affected by curtailment.
Also in August, the government extended the curtailment, initially to have ended at yearend, through 2020 (OGJ Online, Aug. 21, 2019).
Matador to drill new Delaware basin leases
Matador Resources Co., Dallas, will drill six wells with 2-mile laterals in the Antelope Ridge area of Lea County, NM, under permits newly received from the US Bureau of Land Management.
It will use two of six operated rigs in the Delaware basin to drill the wells from two three-well pads on acreage acquired in a BLM lease sale last September. It calls the area, covering 1,200 gross and net acres, the Rodney Robinson tract.
On other Antelope Ridge acreage, Matador produces 8,900 b/d of oil and 13.2 MMcfd of gas from six geologic intervals.
It expects to start production from the Rodney Robinson wells in the first quarter of 2020.
The company awaits approval and permits for drilling of eight wells on 2,800 gross and net acres acquired during the September BLM lease sale in its Stateline area.
It plans to move two of its Delaware basin rigs there to drill four wells each on the eastern and western sides of the tract with 2-mile laterals in the east and 2.5-mile laterals in the west.
Drilling will be from two four-well pads.
Matador hopes to start sales from the Stateline wells in the third quarter of 2020 when expansion is complete of a cryogenic gas processing plant in Eddy County, NM, operated by San Mateo Midstream, of which Matador owns 51%.
Plant capacity is to increase to 460 MMcfd from 260 MMcfd.
Timor Resources to drill five wells onshore East Timor
Private Queensland company Timor Resources plans to drill five onshore wells in East Timor in 2020, the first such program in the country in nearly 50 years. The last program was in 1972.
Timor Resources secured the rights to explore and develop about 2,000 sq km of underexplored onshore acreage on the country’s south coast in 2017.
The company is in joint venture with East Timor national oil company Timor Gap EP and holds two production-sharing contracts structured to maximize early cash flows.
Timor Resources has contracted Eastern Drilling Services to drill the wells after a competitive tender process.
The first well in the program, Karau-1, will be drilled to a depth of 1,080 m and target the Viqueque formation.
General Manager Jan Hulse expects the well will encounter 430 m of gross reservoir interval that is known to be oil-bearing in the near surface from evidence of oil seeps at the surface.
The play type has been likened to Bula field on the Indonesian island of Seram where 20 million bbl of oil have been recovered.
Hulse said the Timor Resources drilling campaign will target four different play types to maximize the chance of commercial success. The deepest well will be 2,740 m and target the Triassic and Jurassic formations.
The rig, which will be the only one in the country, is an 1,100-hp Loadcraft currently being commissioned in the US before being shipped across to East Timor for the January 2020 spud date.
Valeura confirms gas flow from third zone in Inanli-1
Valeura Energy Inc., Calgary, said the third stimulated zone in the Inanli-1 appraisal well flowed natural gas as the company works to develop an unconventional gas accumulation play in the Thrace basin of Turkey in partnership with Equinor.
The zone was accessed via two intervals of 3,899-3,925 m and 3,855-3,876 m, which were stimulated in two separate operations with placement of 50 tonnes and 80 tonnes of proppant, respectively.
The net porous sand (above 3% porosity) within the gross section was interpreted to be 26 m, Valeura said. Once gas flow was confirmed post-stimulation by flowing gas up the casing for several hours, production tubing and artificial lift were installed to assist in cleaning up the well.
The well then flowed for 10 days. Average net gas rate over the flowing period was 442 Mcfd and stabilized at 247 Mcfd during the final 24 hr.
Gas from this zone is richer in condensate than the deeper zones previously tested in Inanli-1, with an average condensate-gas ratio of 30 bbl/MMcf. Water production declined over the duration of the test, to a rate of 130 b/d during the final 24 hr of flow.
Flaring has been minimized with almost all produced gas sold. This third test has concluded, and Valeura is preparing the well for the stimulation and testing of the fourth zone of interest.
PROCESSING Quick Takes
ExxonMobil plans upgrades at UK ethylene plant
ExxonMobil Corp. is launching a £140-million additional investment program over the next 2 years at its 800,000-tonne/year ethylene plant in Fife, Scotland, to upgrade key infrastructure and introduce technologies that will improve operational reliability and performance.
A portion of the investment will go toward technologies that reduce the impact of flaring, including a state-of-the-art flare tip, which will reduce noise and vibration, ExxonMobil said, without discussing additional details of the proposed project.
The upgrades are scheduled to be completed by yearend 2022.
Jacob McAlister, plant manager at the Fife ethylene plant, said, “While already one of the most modern plants of its kind in Europe, we are always looking for ways to improve reliability and efficiency through continued maintenance and investment in new technologies.”
Announcement of this latest investment by ExxonMobil’s UK operations follows the company’s April confirmation that it reached a final investment decision to proceed with an £800-million expansion to increase production of ultralow-sulfur diesel by nearly 45% at subsidiary Esso Petroleum Co.’s 270,000-b/d Fawley refining and petrochemical complex near Southampton, UK (OGJ Online, Apr. 24, 2019; Sept. 20, 2018).
ExxonMobil also confirmed in May that it completed a £75-million project to double capacity of the advanced elastomers production plant in Newport, Wales.
Chinese operator lets contract for Fujian propylene unit
Fujian Meide Petrochemical Co. Ltd., a subsidiary of China Soft Packaging Group Co. Ltd., has let a contract to Honeywell UOP LLC to deliver technology services for monitoring of its Honeywell UOP-licensed C3 Oleflex unit, which converts propane into 660,000 tonnes/year of propylene.
As part of the contract, Honeywell UOP will deliver its Honeywell Process Reliability Advisor service, which continuously feeds plant data through Honeywell UOP process and fault models with specialized software to provide key performance information and process recommendations to help the plant run more smoothly and detect problems before they can affect production and plant profitability, Honeywell UOP said.
The software-enabled service combines the plant’s data with Honeywell UOP proprietary process knowledge and troubleshooting experience to accurately and swiftly recommend operational adjustments by continually tying plant data to the right domain knowledge, providing new and plant-specific insights to help plants run consistently at the top of their capability.
Fujian Meide first began using UOP’s C3 Oleflex process in 2011, licensing a second unit in 2013, to help meet growing Chinese market demand for propylene, which is used for production of plastic resins, films and fibers, according to a Mar. 19, 2013, release from Honeywell UOP.
TRANSPORTATION Quick Takes
Russian LNG transshipment complexes eyed
Novatek, Mitsui OSK Lines Ltd., and Japan Bank for International Cooperation have signed a cooperation agreement confirming the companies’ interest in building LNG transshipment complexes in Russia’s Kamchatka and Murmansk regions.
The Russian company said cooperation might include participation interests in projects and financing.
Novatek Chairman Leonid Mikhelson said the complexes “will help to optimize logistics and maximize the efficiency of LNG deliveries from Yamal and Gydan to LNG key markets of the Asia-Pacific region, including Japan.”
Novatek operates a 16.5-million-tonne/year liquefaction plant on the Yamal Peninsula in the Russian Arctic and is building a 19.8 million-tonne/year plant across the Gulf of Ob on the Gydan Peninsula. It has discussed a third LNG facility in the region (OGJ Online, Sept. 3, 2019).
Mikhelson expects final arrangements for the transshipment projects by yearend.
Excelerate advances Bay of Batangas FLNG project
Excelerate Energy LP, The Woodlands, Tex. will seek necessary permits and raise financing to develop a floating LNG import terminal in the Bay of Batangas after having received the notice to proceed from the Philippine Department of Energy Sept. 20.
Luzon LNG will supply natural gas, sourced from LNG, to existing and new gas-fired power plants in the region that provide electricity to Luzon including the area of Metro Manila. The gas supply will augment existing gas production from Malampaya fields as their reserves begin to deplete.
The proposed project will lie offshore Batangas to minimize impact on existing shipping traffic and will utilize technology designed to perform in extreme weather conditions proven at Excelerate’s Gulf of Mexico, North Atlantic, Israel, and the Bay of Bengal operations. Excelerate will develop, design, permit, construct, finance, and operate the terminal.
Total closes deal to operate Mozambique LNG
Total SA has closed on the deal to acquire Anadarko Petroleum Corp.’s 26.5% operated interest in the Mozambique LNG project for $3.9 billion. Closing comes after Total reached a binding agreement with Occidental Petroleum Corp. on May 3 to acquire Anadarko’s assets in Africa (Mozambique, Algeria, Ghana, and South Africa) and signed the subsequent purchase and sale agreement on Aug. 3 (OGJ Online, May 6, 2019).
This first transaction follows receipt of all requisite approvals by the relevant authorities and partners.
Mozambique LNG is the country’s first onshore LNG development. The project includes the development of Golfinho and Atum fields within Offshore Area 1 and the construction of a two-train liquefaction plant with a capacity of 12.9 million tonnes/year. Area 1 contains more than 60 tcf of gas resources, of which 18 tcf will be developed with the first two trains. Final investment decision on Mozambique LNG was made on June 18 and the project is expected to come into production by 2024.
Close to 90% of the production is sold through long-term contracts with key LNG buyers in Asia and in Europe. The project is expected to have a domestic gas component for in-country consumption to help fuel future economic development.
Total operates Mozambique LNG with a 26.5% participating interest alongside ENH Rovuma Área Um SA 15%, Mitsui E&P Mozambique Area1 Ltd. 20%, ONGC Videsh Ltd. 10%, Beas Rovuma Energy Mozambique Ltd. 10%, BPRL Ventures Mozambique BV 10%, and PTTEP Mozambique Area 1 Ltd. 8.5%.
Closing operations are still ongoing in relation to Anadarko’s assets in the other countries (Algeria, Ghana, and South Africa).
FERC prepares Magnolia LNG amendment draft SEIS
The US Federal Energy Regulatory Commission’s staff has prepared a draft supplemental environmental impact statement for Magnolia LNG LLC’s request to increase LNG production capacity at its previously authorized project in Calcasieu Parish, La. Magnolia LNG now requests an authorized capacity of 8.8 million tonnes/year vs. the initial capacity of 8 million tpy. Comments on the draft SEIS will be accepted through Nov. 18.
The increased production capacity would be achieved through the optimization of Magnolia LNG’s final design, including additional and modified process equipment. All new or reconfigured facilities would be within the footprint of the authorized Magnolia LNG terminal site, FERC’s staff said.
FERC’s staff said the US Pipeline and Hazardous Materials Safety Administration still must issue a letter of determination regarding the proposed facilities’ compliance with federal siting requirements for LNG operations.
Gulf Coast Express pipeline starts gas flow
The Gulf Coast Express (GCX) pipeline project has started full commercial operation on Sept. 25, says Kinder Morgan Inc. (KMI), the natural gas system’s builder and operator. Construction on the line began in early 2018 (OGJ Online, Jan. 3, 2018).
The pipeline will carry gas from the Waha Hub near Coyanosa, Tex., in the Permian basin to Agua Dulce, Tex. The $1.7-billion project was originally expected to be online in October.
The GCX project mainline portion consists of 82 miles of 36-in. pipe and 365 miles of 42-in. pipe. The system’s 2-bcfd capacity is fully subscribed under long-term contracts.
KMI unit Kinder Morgan Texas Pipeline LLC holds 34% in the project. Equity holders include Altus Midstream, DCP Midstream LLC, and an affiliate of Targa Resources Corp.
