GENERAL INTEREST Quick Takes
Devon amends Barnett shale agreement with BKV
Devon Energy Corp., Oklahoma City, has amended its agreement to sell its Barnett shale assets to Banpu Kalnin Ventures (BKV) (OGJ Online, Dec. 18, 2019).
Under the amended terms, Devon will sell the assets to BKV for up to $830 million of total proceeds, consisting of $570 million in cash at closing and contingent payments of up to $260 million. The previous sale price was $770 million without contingent payments.
With the amended terms, Devon will receive an increased deposit of $170 million from BKV, and the scheduled closing date for the transaction is extended to Dec. 31 from Apr. 15. The closing payment is subject to customary purchase price adjustments that, among other things, allocate revenues and expenses based on a Sept. 1, 2019, effective date.
In December, with initial report of the Barnett sale, Devon announced a $1 billion share-repurchase program set to expire Dec. 31, 2020. Of the $1 billion, $800 million is conditioned upon the closing of the Barnett transaction.
The agreement provides for contingent cash payments of up to $260 million based upon future commodity prices, with upside participation beginning at either a $2.75 Henry Hub natural gas price or a $50 West Texas Intermediate oil price. The contingent payment period begins Jan. 1, 2021, and has a term of 4 years. The contingent payments are earned and paid on an annual basis.
NZ High Court rules Tui field FPSO must stay
The floating production, storage, and offtake vessel Umuroa must stay connected to Tui oil field in the offshore Taranaki basin, the High Court of New Zealand has ruled.
The ruling comes after an Environmental Protection Authority plea to prevent the vessel contractor BW Offshore from removing the vessel from the field infrastructure and sailing it away.
BW Offshore had been contracted by Malaysian-owned field operator Tamarind Resources Pte Ltd.’s New Zealand subsidiary Tamarind Taranaki to supply the FPSO for production from Tui field. Umuroa had been on station for several years.
The problem arose when Tamarind Taranaki went into liquidation in December 2019 owing hundreds of millions of dollars to contractors and creditors.
BW Offshore responded in March by saying it would demobilize the FPSO from New Zealand at a cost around NZ$20 million.
The company said at the time that Umuroa is a versatile turret-moored FPSO and an attractive redeployment candidate for field developments.
When BW Offshore began the demobilization process in March, the NZ EPA served the company six abatement notices, ordering the company to stop because the demobilization would leave oil pipelines and Tui subsea infrastructure on the seabed.
The notices have been upheld by the High Court with the Hon. Justice Robin Cooke stating that “Parties engaged in significant oil mining activities need to ensure that those activities are appropriately brought to an end from an environmental point of view before departing the scene. That is saying no more than people must tidy up an activity before they leave,” he added.
The decommissioning of Tui oil field with Tamarind Taranaki in liquidation presents a number of legal, contractual, and constitutional challenges. With Tamarind Taranaki insolvent, the responsibility of Tui decommissioning activities is yet to be determined.
Equinor to farm out Norwegian Sea licenses interest
Equinor ASA has agreed to transfer 20% interest in two Norwegian Sea licenses to Lime Petroleum AS (LPA), a 90% subsidiary of Rex International Holding Ltd., pending regulatory approval, LPA said Apr. 9.
The licenses, PL263D and PL263E, lie on the Halten Terrace between Asgard and Midgard fields, some 25 km southwest of the newly issued PL1062 license. Exploration drilling on the licenses is expected to begin late this year with a well targeting the Apollonia prospect with a reservoir in the traditional Jurassic section.
Equinor is operator of the licenses with 80%. Pandion Energy AS holds the remaining 20%.
Tengiz maintenance, expansion delayed by COVID-19
Tengizchevroil (TCO) has postponed annual maintenance of Tengiz field to 2021 due to the COVID-19 pandemic. The delay slows work on TCO’s Tengiz expansion project after multiple positive tests for coronavirus at a workers’ camp near the field.
Tengiz’s estimated recoverable crude reserves measure 6-9 billion bbl. Current production capacity is 540,000 b/d of crude oil, 750 MMcfd of natural gas, and more than 40,000 b/d of NGL. TCO’s expansion, the integrated Future Growth Project-Wellhead Pressure Management Project (FGP-WPMP), is designed to increase crude oil production from Tengiz by 260,000 b/d.
Chevron Corp. in 2019 increased FGP-WPMP’s cost estimate to $45.2 billion from $36.8 billion. The FGP will use sour gas injection technology, developed during TCO’s previous expansion in 2008, to increase daily crude oil production while the WPMP will extend the field’s production plateau and keep existing plants producing at full capacity (OGJ Online, Nov. 4, 2019).
Chevron owns 50% of TCO, with Exxon Mobil Corp. (25%), Russia’s Lukoil (5%), and Kazakh-state KazMunayGaz (20%).
Exploration & Development Quick Takes
Gazprom to develop Meretoyakhaneftegaz project without Shell
In accordance with the previously approved work plan, Gazprom Neft will independently develop oil and gas fields in the Yamalo-Nenets Autonomous Okrug of northwestern Russia formerly intended for joint development with Royal Dutch Shell PLC.
Shell, citing the challenging external environment, advised Gazprom that it will not complete the previously agreed upon deal to purchase a 50% stake in Gazprom Neft subsidiary Meretoyakhaneftegaz, which holds license rights to Meretoyakhinskoye oil field (OGJ Online, June 6, 2019). At closing, the JV holders were to receive Tazovsky and Severo-Sambrugsky blocks and two Zapadno-Yubileiny blocks, which are in varying stages of development.
Gazprom expects development and commercial production at Tazovsky to begin by yearend.
Shell’s decision to withdraw from the JV does not impact its cooperation with Gazprom on current and potential new opportunities, Gazprom said.
In March, Salym Petroleum Development (SPD)—a Gazprom Neft-Shell JV—closed on a deal to expand development in the Salym group of fields in the Khanty-Mansi Autonomous Okrug.
The SPD asset portfolio expanded to include Gazprom Neft’s license to rights for geological prospecting, exploration, and production of traditional hydrocarbon reserves at Salymsky-2 Block in Khanty Mansiysk Autonomous Okrug.
Lukoil advances north Caspian Sea fields development
Lukoil has launched the jacket of a living quarters platform from the yard to the Caspian Sea, advancing facilities construction for Valery Grayfer field. The facility is designed to accommodate 155 people. Installation of the topside of the living quarters platform is scheduled for 2021. Commercial oil production from Valery Grayfer field is planned for 2022 at a design rate of 1.2 million tonnes/year.
Valery Grayfer (former Rakushechnoye) field, discovered in 2001, lies 160 km from the port of Astrakhan, 100 km from the western cost, and 8.5 km from V. Filanovsky field.
Development of V. Filanovsky and Yury Korchagin fields continues with accumulated production from the projects nearing 30 million tonnes. Production on V. Filanovsky field involves three phases of facilities, including a wellhead platform with minimal personnel involvement.
Drilling of single-bore horizontal gas injection well #102 has been completed on the ice-resistant fixed platform.
The field was discovered in 2005 and became the largest discovery made in Russia over the past 25 years. Commercial production began in 2016.
Drilling is in progress on Phase 2 facilities of Yury Korchagin field to unlock reserves in the eastern part of the field as well as additional drilling on Phase 1 facilities. The first producing well reached Callovian deposits.
Yury Korchagin field was discovered in 2000 and put in operation in 2010 to become Lukoil’s first producing project in the Caspian Sea.
Chevron lets subsea services contract for Anchor field
Chevron USA Inc. has let a contract to Subsea 7 for subsea installation services related to Anchor field in the Green Canyon area of the Gulf of Mexico some 140 miles off the coast of Louisiana.
Chevron sanctioned the Anchor project in December 2019, marking the industry’s first deepwater high-pressure development to achieve a final investment decision (OGJ Online, Dec. 12, 2019). Stage 1 of Anchor development consists of a seven-well subsea development and semi-submersible floating production unit. First oil is anticipated in 2024.
Subsea 7’s scope of work includes project management, engineering, procurement, construction, and installation of the SURF components including, but not limited to, the production flowlines, risers, umbilicals, flying leads, jumpers, and associated appurtenances.
Project management and engineering will begin immediately at Subsea 7’s offices in Houston, Tex. Fabrication of the flowlines and risers will take place at Subsea 7’s spool-base in Ingleside, Tex., with offshore operations anticipated to occur in 2022 and 2023.
Drilling & Production Quick Takes
Shell shuts in Perdido production following HOOPS leak
Royal Dutch Shell has temporarily halted production from its 100,000-b/d Perdido platform in the Gulf of Mexico following a leak in Exxon Mobil’s 153-mile Hoover offshore oil pipeline system (HOOPS).
Perdido operates in Alaminos Canyon Block 857 about 200 miles south of Galveston, Tex., in 2,450 m of water and produces from Great White, Tobago, and Silvertip fields. HOOPS delivers to the Quintana terminal near Freeport, Tex.
Shell operates Perdido with partners Chevron (37.5%) and BP (27.5%).
Qatar Petroleum spuds first well of NFE development
Qatar Petroleum has commenced development drilling for the North Field East project, or NFE (previously the North Field Expansion project), as the first of 80 development wells from eight wellhead platform locations was spudded Mar. 29.
Drilled by the GulfDrill’s Lovanda offshore jack up drilling rig, the well begins the first phase of the expansion project set to increase Qatar’s LNG production capacity to 110 million tonnes/year (tpy) from 77 million tpy by 2024.
The second phase of the expansion project—the North Field South Project (NFS)—will further increase Qatar’s LNG production capacity to 126 million tpy from 110 million tpy.
Qatar Petroleum had earlier awarded a number of contracts for jack-up drilling rigs to be utilized for the drilling of 80 development wells for the NFE (OGJ Online, May 2, 2019). Contracts for six of the eight rigs were let to Gulf Drilling International. Contracts for the remaining two rigs were let to Northern Offshore Drilling Operations Ltd.
The installation of the first four offshore jackets in Qatari waters is underway and is expected to be completed by the end of April (OGJ Online, Nov. 27, 2019).
Valeura increases appraisal activity in deep Thrace basin, Turkey
Valeura Energy Inc. will appraise the deep unconventional gas play in the Thrace basin and has increased working interest in Banarli and West Thrace exploration licenses in northwestern Turkey.
The deep play is at an early phase and will require more drilling and testing. Of 11 wells to date, only the most recent three have been stimulated and tested. All flowed gas to surface. Deep zones have been identified with drier gas where hydrocarbon maturity, reservoir quality, saturation and natural fracturing are all improved. Short-term production tests from these zones suggest potential for economic development.
Production from Devepinar-1 is expected to restart with a longer-term test than previously conducted. All produced gas will be sold to Valeura’s customers. The ongoing COVID-19 pandemic makes timing of the restart uncertain, Valeura said.
Valeura will apply for the first extension to the Banarli and West Thrace exploration licenses. Exploration licenses in Turkey have an initial 5-year phase followed by up to three 2-year phases, for a maximum of 11 years, prior to being converted to production leases. The first 5-year phase ends June 26, with first extension to June 26, 2022.
On Apr. 2, the Government of Turkey approved transfer of Equinor’s working interests and rights to Valeura and PTI, doubling Valeura’s working interest in the deep play. Valeura will hold 100% in the Banarli exploration licenses and will increase holdings to 63% of the deep rights in the West Thrace exploration license and production leases. Ownership in shallow rights is unchanged at 100% in Banarli and 81.5% in West Thrace. Valeura remains operator in all blocks.
Valeura seeks an additional partner for the deep unconventional play who brings both financial and technical capabilities. The work program is expected to include drilling new vertical and horizontal wells, reservoir stimulation, and production testing operations.
PROCESSING Quick Takes
NNPC seeks investors to run Nigerian refineries
Nigerian National Petroleum Corp. (NNPC) is planning to relinquish control of Nigeria’s three state-run refineries following completion of a long-planned program to rehabilitate and optimize processing capacities at the sites (OGJ Online, Sept. 30, 2019; Dec. 21, 2016).
NNPC will no longer be involved in management of the refineries after their rehabilitation, following which the services of an unidentified company will be procured to manage the plants on an operations and maintenance (O&M) basis, NNPC said in a release.
Mallam Mele Kyari, NNPC’s managing director, announced the proposed change in addressing the specific program for full rehabilitation of NNPC subsidiary Port Harcourt Refining Co. Ltd.’s (PHRC) Port Harcourt refining complex—which includes a 60,000-b/sd hydroskimming refinery and 150,000-b/sd full-conversion refinery—in Nigeria’s Rivers state.
“We are going to get an O&M contract, NNPC won’t run it. We are going to get a firm that will guarantee that this plant [PHRC] would run for some time. We want to try a different model of getting this refinery to run. And we are going to apply this process for the running of the other two refineries,” Kyari said.
The plan, ultimately, is to get private partners to invest in the refineries and get them to run on the same model used by Nigeria Liquefied Natural Gas Ltd., where shareholders would be free to decide the future of the refineries to ensure their long-term operation, according to Kyari.
Scheduled to begin in January at PHRC’s Port Harcourt refining complex, the full rehabilitation program also will include works at NNPC subsidiaries Warri Refining & Petrochemcial Co. Ltd.’s 125,000-b/sd refinery in Delta state, and Kaduna Refining & Petrochemical Co. Ltd.’s 110,000-b/sd refinery in Kaduna state, with the entire program at all three refineries due to be completed by 2022 (OGJ Online, Dec. 19, 2019; Sept. 30, 2019).
Sasol, Total halting production at South African refinery
Sasol Ltd. and partner Total SA are suspending operations at their jointly owned National Petroleum Refiners of South Africa (Pty) Ltd.’s (Natref) 108,000-b/d refinery in Sasolsburg, South Africa, amid reduced regional demand resulting from measures aimed at reducing the spread of coronavirus (COVID-19).
Beginning Apr. 9, Natref will halt production at the refinery until further notice, Sasol said on Apr. 8.
The decision follows an unprecedented decline in fuel demand following South Africa’s national COVID-19 lockdown that began on Mar. 27, according to the operator.
Sasol and Total own the Natref refinery through subsidiaries Sasol Oil (Pty) Ltd. 64% and Total South Africa (Pty) Ltd. 36%, according to the companies’ websites.
Separately, Sasol said, until further notice, it was also reducing daily production rates to meet current market demand as a result of COVID-19 by about 25% at its Secunda Synfuels Operations (SSO), which is the world’s only commercial coal-based synthetic fuels manufacturing site to synthesis gas (syngas) through coal gasification and natural gas reforming.
Chemicals production will continue to be prioritized within the revised SSO operating parameters including this cutback scenario.
Despite suspension of production at the Natref refinery and lower production rates at SSO, Sasol said it will continue to meet South Africa’s current demand for fuels and chemicals, including sanitizers, by prioritizing production of chemicals at its regional operations.
Given these developments as a result of reduced demand, Sasol said it expects liquid fuels sales volumes for 2020 to average 50–51 million bbl, down from its previous guidance of 57–58 million bbl. Synfuels production also will fall to about 7.3-7.4 million tonnes/year from an earlier estimate of 7.7-7.8 million tpy.
NARL halts operations at Come-by-Chance refinery
NARL Refining LP has paused production activities at its 130,000-b/d refinery at Come-by-Chance, Newf., to ensure safety of its employees, their families, and operations amid the coronavirus (COVID-19) pandemic.
“The refinery will maintain a reduced workforce with the primary tasks of maintaining the facility and the performance of storage and inventory services,” said Jette Enevoldsen, chief operations officer of North Atlantic Refinery Ltd.
In the short term, NARL Refining’s marketing team will maintain product deliveries to customers and retail locations as usual as the company continues working with government officials to ensure supply and delivery of essential products to Newfoundlanders and Labradorians, according to Enevoldsen.
The operator did not disclose a definitive timeframe for when it will resume normal operations at the refinery but did confirm plans to provide regular progress updates.
NARL Refining previously announced it is in the process of undertaking projects aimed at increasing crude flexibility and efficiency at the refinery as part of the operator’s strategy to support the long-term viability and competitive advantage of operations (OGJ Online, Aug. 1, 2019; July 8, 2019).
TRANSPORTATION Quick Takes
Annova LNG gets Texas OK for Brownsville plant
Annova LNG Common Infrastructure LLC received permission from the Texas Commission on Environmental Quality to build its 6.5-million tonne/year (tpy) liquefaction plant at the Port of Brownsville. The plant’s gas would be delivered via the Aqua Dulce hub.
Annova received its US Federal Energy Regulatory Commission (FERC) construction permit fourth-quarter 2019 and its US Department of Energy (DOE) permit to export to non-free trade agreement countries in February 2020 (OGJ Online, Nov. 21, 2019). DOE authorized export of about 360 bcf/year (~6.95 million tpy), Annova’s optimal production capacity. Annova plans to start operations of at 6.5 million tpy and increase output as operating conditions and commercial demands allow.
In November FERC also approved, with conditions, Brownsville Ship Channel projects proposed by Texas LNG Brownsville LLC and Rio Grande LNG LLC.
Annova LNG expects to begin operations in 2024.
Oneok granted ND permission to build NGL pipeline
Oneok Bakken Pipeline LLC has received permission from the North Dakota Public Service Commission to build its 90,000-b/d Williams County NGL pipeline. The project consists of about 75 miles of 16-in. OD steel pipe in Williams County, ND. Oneok anticipates a fourth-quarter 2020 in-service date.
The pipeline includes four mainline block valves, one pig launcher, one pig launcher with receiver, and one pig receiver. It will start at the Hess Tioga natural gas processing plant and end at an interconnection near Oneok’s Stateline-to-Riverview NGL pipeline. The system has a maximum operating pressure of 1,480 psi.
Estimated cost is $100 million.
Denbury gets ND permission to build CO2 pipeline
Denbury Green Pipeline North Dakota LLC has received permission from the North Dakota Public Service Commission to build its 180-MMcfd Cedar Hills CO2 pipeline. The project consists of about 18 miles of 12-in. ID welded steel pipe, with 9.23 miles in North Dakota. Denbury anticipates a November 2020 in-service date.
Cedar Hills will start at a connection point to Denbury’s Cedar Creek Anticline (CCA) CO2 pipeline in Fallen County, Mont., and end at Denbury’s Miller Production Tank Battery Enhanced Oil Recovery Development Site in Bowman County, ND. The project includes metering stations, block valves, pig launchers and receivers, and associated equipment.
The pipeline’s 0.469-0.562-in. WT will allow a maximum operating pressure of 3,702 psig and a maximum operating temperature of 100° F.
Estimated cost of the project is $9.2 million.
Denbury Resources Inc., Plano, Tex., earlier this week cut $80 million from its 2020 capital budget and deferred its CCA CO2 tertiary flood development beyond the end of the year (OGJ Online, Mar. 31, 2020).