GENERAL INTEREST Quick Takes
Federal budget request avoids dramatic changes
The Trump Administration’s budget request for fiscal 2021 would not interrupt oil and gas resource management on federal lands if accepted by Congress.
The request, released Feb. 10, attempts to keep Interior Department spending on an even keel while urging a few more notable changes for the Energy Department.
For the Bureau of Land Management (BLM) within Interior, the budget plan would add $2.4 million to the Oil and Gas Permit Processing Improvement Fund to bring spending for fiscal 2021 up to $56.3 million. The program addresses the chronic complaints of companies about the slowness of permit processing.
But the overall BLM budget at $139.2 million would hardly change at all, down only $700,000 from the level enacted for fiscal 2020.
The Bureau of Ocean Energy Management (BOEM) budget would slip $2.8 million to $191.6 million, while the Bureau of Safety and Environmental Enforcement (BSEE) budget would gain $1 million to $204 million. BOEM leases federal offshore resources while BSEE regulates safety and environmental protection for offshore resource development.
A BSEE budget document stressed that the agency would continue to focus much of its effort on “risk-based” inspections, targeting more hazardous facilities and operations. The agency said it is also is trying to strengthen its ability to deal with the corporate bankruptcies, which raise the risk of companies defaulting on their obligation to decommission facilities at the end of their useful lifetimes.
The Trump administration budget request for the Energy Department included proposals to sell off the gasoline and heating oil in two regional reserves and shut the reserves down.
The government maintains one million bbl of gasoline and one million bbl of ultra-low-sulfur distillate in the Northeastern gasoline and heating oil strategic reserves. But they are not being used for their intended purposes, the Trump administration said.
In reference to the gasoline reserve, the Trump administration said its shutdown proposal was “consistent with past budget requests,” a reminder that administration budget proposals often resurface annually only to be rejected by Congress. Members of Congress from New York and New England tend to be proponents of the two Northeastern reserves.
The Trump administration wants to continue the program of crude oil sales from the Strategic Petroleum Reserve.
Equinor, Shell advance agreement after Vaca Muerta farm-in
Equinor and Shell are increasing activities in Argentina with a joint acquisition of interest held by Schlumberger in the Bandurria Sur onshore block in Argentina’s Neuquén province and a preliminary agreement with operator YPF.
For Schlumberger’s 49% interest in the block, each partner paid $77.5 million for their 24.5% interest.
The block covers 56,000 gross acres in the central area of the Vaca Muerta play. YPF, as operator (51%), is in the late pilot phase of development with current production of 10,000 boe/d.
As a result of the deal, a former Schlumberger subsidiary, which holds the 49% interest in the block, is now equally owned by Equinor and Shell.
Equinor and Shell also have reached a preliminary agreement to acquire an additional 11% interest from YPF. On completion of the additional transaction, which is subject to a conditions and authority approval, Equinor and Shell will each own a 30% non-operated interest with YPF owning a 40% interest and continuing as operator.
Equinor participates in eight offshore blocks in Argentina, six as operator. Equinor is also a 50% partner with YPF (operator) in the Bajo del Toro onshore block and has a 90% operated interest in the neighboring blocks Bajo del Toro Este and Aguila Mora Noreste, with Gas y Petróleo de Neuquén.
Hess earmarks bulk of 2020 spend to Guyana, Bakken
Hess Corp. will allocate more than 80% of its 2020 exploration and production capital and exploratory budget of $3.0 billion to high return investments in Guyana and the Bakken.
The company plans to spend $1.69 billion (56%) for production, $860 million (29%) for offshore Guyana developments, and $450 million (15%) for exploration and appraisal activities.
The majority of the production budget—$1.375 billion—will fund a 6-rig program in the Bakken where the company expects to drill 170 new wells and to bring online 175 new wells this year. Funds are also included for investment in non-operated wells.
Production operations in the deepwater Gulf of Mexico—which includes development of the Hess-operated Esox-1 tieback (57.14%) will see $135 million.
Another $170 million is allocated for production activities at Hess-operated North Malay basin (50%) and the Malaysia/Thailand joint development area (50%) in the Gulf of Thailand.
Net production is forecast to average 330,000-335,000 boe/d in 2020, excluding Libya. Bakken net production is forecast to average 180,000 boe/d in 2020.
The company has earmarked $100 million for Liza Phase 1 development offshore Guyana (30%), where first production was achieved in December 2019. Another $400 million is expected to go to Liza Phase 2 development, where first production is expected by mid-2022.
Some $360 million is expected to progress development plans for Payara field, where production is expected as early as 2023, and for front end engineering and design work for future developments.
The company expects to spend $450 million to drill exploration and appraisal wells on the Stabroek and Kaieteur Blocks offshore Guyana (Hess 30% and 15%, respectively) and two exploration wells in the Gulf of Mexico. Funds are also included for seismic acquisition and processing in Guyana, Suriname, and the deepwater Gulf of Mexico, and for license acquisitions.
Exploration & Development Quick Takes
Oil Search finds oil in Pikka East Block, Alaska
Oil Search Ltd. plans a sidetrack well following an oil and gas discovery in Pikka East Block on the North Slope of Alaska.
The Mitqua-1 well, drilled to 2,472 m TD, encountered both oil and gas in the primary Nanushuk reservoir as well as in the deeper Alpine C target.
Preliminary evaluation of wireline logs, along with pressure and fluid sample data, indicates the Nanushuk Cretaceous-age Brookian sand has 60 m of net pay comprising 5 m of net gas and 55 m of net oil pay, the company said.
Data collected from the secondary Alpine C sandstone reservoir indicates the presence of 16 m of net hydrocarbon pay comprising 6 m of net gas and 10 m of net oil pay.
The Nanushuk section of the sidetrack will be cored and flow-tested to assess deliverability and provide a more accurate estimate of net pay thickness and commercial potential. The Alpine C reservoir is to be evaluated by future appraisal wells.
Mitquq-1 is about 8 km east northeast of the planned Nanushuk processing facility that will be built during Phase 2 of the Pikka Unit development.
Oil Search is operator of Pikka East with 51% interest. Repsol holds 49%.
Equinor to withdraw Thrace basin deep gas participation
Valeura Energy Inc., Calgary, expects to continue the deep gas appraisal program of the Thrace basin onshore northwest Turkey following notification from joint partner Equinor of its intent to withdraw.
Discussions have commenced around the commercial mechanism by which Equinor is to exit the play, Velura said Feb. 2.
In 2016, Equinor (then Statoil) farmed into an onshore acreage operated by Valeura. Equinor holds a 50% interest in formations deeper than 2,500 m within the Banarli and West Thrace licenses. Valeura holds 50% in the deep formations in the Banarli license, and 31.5% in the deep formations in the West Thrace. The remaining 18.5% in West Thrace is held by Pinnacle Turkey.
The first deep exploration well, Yamalik-1 in the Banarli license, was drilled to 4,200 m in 2017. The well discovered a 1,300-m natural gas and condensate column in overpressured reservoirs below 2,900 m in the Tertiary Teslimkoy and Kesan formations. Appraisal wells Inanli-1 and Devepinar-1 followed (OGJ Aug. 5, 2019, p. 32).
Through the partnership, said Sean Guest, Velura president and chief executive officer, the company has gathered “a significant volume of new data and key learnings about the attributes of the large gas resource base in the Thrace Basin, with much of the investment funded by Equinor’s carry under its agreements.”
Po Valley wins approval for Selva field development
Po Valley Energy Ltd., Perth, received formal technical environmental approval from the Italian Environment Ministry for the re-development of its Selva gas field onshore northern Italy.
This environmental approval is the penultimate step before a final sign-off on the project by decree from the Environment Minister and the final grant of a production concession issued by the Economic Development Ministry.
During the first phase of re-development, Po Valley intends to install a fully automated gas plant at its already-drilled Selva/Podere Maiar-1 directional well site and build a 1 km pipeline to connect the well with the nearby national Italian gas grid.
Michael Masterman, Po Valley chief executive officer, said that based on dynamic reservoir studies, the new development has been designed to produce at a maximum rate of up to 5.3 MMcfd from the C1 and C2 levels in the Upper Pliocene-age reservoir sands of the Porto Garibaldi formation.
Selva has estimated 2P gas reserves of 13.3 bcf. It was originally discovered by ENI and produced a total of 83 bcf over 35 years, ceasing production in 1984.
Po Valley is operator with 63% interest. Partners are United Oil and Gas 20%, and Prospex Oil and Gas 17%.
Masterman also said that the final environmental approval for its 100%-owned Teodorico offshore gas field project is expected within the next 2 months.
With estimated reserves of 36.5 bcf of gas, Teodorico has the largest gas-in-place of all the company’s fields in Italy and is in an advanced stage of assessment, ready for development.
Discovered in 1986 by ENI in the Adriatic Sea off the coast of Italy’s Emilia Romagna region, Teodorico—then named Carola/Irma—lies in water depth of 25 m.
Development plans include the drilling of two wells and installation of an unmanned three-legged platform that will be connected to ENI’s Naomi Pandora production facilities 12 km to the southeast.
Drilling & Production Quick Takes
Module on Troll C to accelerate, increase production
A new gas module to accelerate and increase oil production from Equinor ASA-operated Fram field in the North Sea was recently put on stream on the Troll C platform.
Fram oil finds, about 20 km north of Troll field in 350 m of water, are tied in via pipelines to Troll C for processing. In 2017, Fram partners, in agreement with Troll partners, decided to invest 1 billion kroner in the gas module to boost gas processing capacity on Troll C by 3.5 million standard cu m/day (scmd). The investment was essential to further developing Troll C as a hub for the area, Equinor said. Additionally, the new gas module will allow tie in from future discoveries, Equinor noted in a Feb. 11 release.
Aibel in Haugesund built the slightly more than 400-tonne module featuring gas drying and cooling units, and Aibel in Bergen was responsible for the engineering work.
In November 2019, Fram partners made an oil and gas discovery at Echino South, 3 km southwest of the field (OGJ Online, Nov. 6, 2019). Several additional prospects in the area are being considered for drilling, Equinor said.
Alligin goes onstream west of Shetland
Production from Alligin oil field in the North Sea began in late December 2019, operator BP said Feb. 4.
Alligin is a 20 million-bbl recoverable oil field in the Greater Schiehallion area about 140 km west of Shetland in 475 m of water (OGJ Online, Oct. 22, 2018).
Alligin forms part of the Greater Schiehallion Area and has been developed as a two-well subsea tieback into the existing Schiehallion and Loyal subsea infrastructure and the Glen Lyon floating, production, storage, offload (FPSO) vessel.
Ooriginally forecast to produce 12,000 boe/d (gross) at peak reached 15,000 boe/d (gross) at peak since start-up.
The development includes new subsea infrastructure consisting of gas lift and water injection pipeline systems and a new controls umbilical.
Alligin is operated by BP with 50%. Shell is partner with the remaining 50%.
International rig count down 26 units in January
The international rig count for January reached 1,078, a decrease of 26 units from December 2019 and up 54 units from the 1,024 counted in January 2019, according to Baker Hughes data (OGJ Online, Jan. 8, 2020).
The international offshore rig count January was 245, down 12 units from December 2019, and up 3 units from the 242 counted in January 2019.
The worldwide rig count for January was 2,073, up 30 units from the 2,043 counted in December 2019, and down 192 units from the 2,265 counted in January 2019.
The average US rig count for January was 791, down 13 from the 804 counted in December 2019, and down 274 from the 1,065 counted in January 2019.
Europe was down 6 units with 133 in January and up 47 units year-over-year. Effective June 7, 2019, Ukraine has been added to the Baker Hughes International Rig Count.
Latin America is down 12 units from the previous month with 179 units and down 1 unit year-over-year.
The Asia-Pacific region is down 4 with 222 units month-over-month and down 10 units from its year-ago average.
The Middle East unchanged month-over-month at 430 and up 28 units year-over-year.
The average Canadian rig count for January was 204, up 69 units from the 135 counted in December 2019, and up 28 units from the 176 counted in January 2019.
PROCESSING Quick Takes
Dow to expand ethylene capacity at Fort Saskatchewan plant
Dow Inc. is moving forward with a project to incrementally expand ethylene capacity at subsidiary Dow Chemical Canada ULC’s (Dow Canada) petrochemicals manufacturing site just north of Fort Saskatchewan, Alta.
Known as the FS1 project, the expansion will involve increasing capacity of the ethylene plant by about 130,000 tonnes/year with the addition of another furnace, Dow told investors in its latest earnings presentation for fourth-quarter 2019.
Scheduled for startup during first-half 2021, additional ethylene produced by the $200-225-million expansion will be consumed by existing polyethylene assets in the region, according to the operator.
Dow said it will coinvest in the expansion with an unidentified regional customer, evenly sharing project costs and ethylene output.
With all regulatory approvals previously secured from Alberta’s Ministry of Environment and Parks, construction on the FS1 project—which, in addition to the new furnace, also will involve installation of unidentified associated equipment—is already under way, according to Dow Canada’s web site.
While Dow does not disclose production capacities of specific plants per company policy, Dow Canada’s Fort Saskatchewan manufacturing site produces more than 1.4 million tpy of products, including ethylene and polyethylene, according to a 2018 regional company overview from Alberta’s Industrial Heartland Association.
Dow also told investors it expects to bring two new furnaces into service as part of its previously announced 500,000-tpy capacity expansion of its 1.5 million-tpy TX-9 ethylene cracker at the operator’s olefins manufacturing complex in Freeport, Tex. (OGJ Online, May 12, 2017).
With the furnaces scheduled to come online by the middle of second-quarter 2020, Dow said it expects to begin commissioning activities at the site by the end of this quarter.
Once fully commissioned, the expanded TX-9 cracker will have a capacity of 2 million tpy, making it the world’s largest ethylene facility, Dow said.
Altus commissions Alpine High gas processing complex
Altus Midstream Co.—which owns substantially all gas gathering, processing, and transportation assets servicing Apache Corp.’s production in the Delaware basin’s Alpine High play—has completed startup of all three cryogenic natural gas processing trains at its Diamond Cryo Complex (DCC) in Alpine High, in southern Reeves County, Tex. (OGJ Online, Aug. 9, 2018).
Commissioned over phases beginning in May 2019, each of the DCC’s 200-MMcfd processing trains—which are equipped with Honeywell UOP LLC’s proprietary Ortloff supplemental rectification with reflux (SRX) processing technology—are in operation, enabling the complex to process up to 600 MMcfd of natural gas produced in the region.
Marking the first global application of the new technology to optimize processing economics with better NGL recoveries in both ethane recovery and rejection mode vs. more commonly used processing methods in the Permian Basin, Ortloff SRX technology passed performance testing at the site while recovering more than 99% of ethane and 100% of propane in ethane recovery mode, and more than 99% propane in ethane rejection mode at design capacity.
Altus Midstream previously said the DCC also will be producing an estimated 60,000-75,000 b/d of NGLs for Apache.
Construction activities wrapped on the DCC in late 2019.
Indorama Ventures commissions ethane cracker
Indorama Ventures Olefins LLC (IVO), an indirect subsidiary of Thailand’s Indorama Ventures PCL (IVP), Bangkok, has started commercial operations at its previously announced project to renovate and restart a dormant ethane cracker in Westlake, La., just west of Lake Charles in Calcasieu Parish (OGJ Online, Sept. 25, 2015).
The 440,000-tonne/year cracker entered commercial operation on Jan. 31, IVP said on Feb. 3.
To date, the restarted plant already has achieved an operating rate of more than 80%, said Tony Barre, IVO’s site director.
Integrated with US Gulf Coast ethylene pipeline infrastructure to enable efficient distribution, the Westlake plant will provide long-term captive ethylene supplies to Indorama Ventures Oxide and Glycols’s (IVOG) plant in Clear Lake, Tex., as well as IVL’s recently acquired integrated ethylene oxide-propylene oxide and derivatives assets in Port Neches, Tex., which the operator completed purchase of from Huntsman Corp. in early January, according to an IVL filing with the Stock Exchange of Thailand on Jan. 6.
Nearly 80% of the plant’s ethylene capacity will provide captive supply specifically to IVOG’s Clear Lake plant, according to IVL’s website.
Originally planned for commissioning in late 2017 and mechanically completed in May 2019, the refurbished cracker—jointly owned by IVP (76%) and Singapore-based Indorama Corp. (24%)—is designed to process attractively priced ethane and propane feedstock from US shale to produce about ethylene and propylene (OGJ Online, May 6, 2019).
TRANSPORTATION Quick Takes
Elengy buys Fos Cavaou LNG regas terminal shares
Elengy has acquired Total’s shares in Fosmax LNG, the company that owns the LNG terminal at Fos Cavaou, France. Elengy now owns 100% of its three LNG terminals: Fos Cavaou, Fos Tonkin, and Montoir-de-Bretagne. Until now Fosmax LNG was owned 72.5% by Elengy and 27.5% by Total Gaz Electricité Holding France.
The acquisition of the shares was financed mainly by an increase in Elengy’s capital reserved for the Société d’Infrastructures Gazières (SIG). SIG now owns close to 18% of Elengy’s capital, with the balance held by GRTgaz.
Elengy described the acquisition as part of efforts to increase industrial development of its sites at Fos Cavaou and Fos Tonkin.
ARB Midstream expands DJ basin system
ARB Midstream LLC subsidiary DJ South Gathering LLC’s Platteville complex now has connectivity to Tallgrass Energy LP’s Pony Express Pipeline and terminal system. With an initial throughput of 48,000 b/d, the connection into Tallgrass’ Grasslands terminal continues the company’s expansion of its crude oil gathering and transportation system in the DJ basin in northeastern Colorado.
ARB’s link to Tallgrass’ Pony Express system will be fed by ARB’s 300,000 bbl of dedicated crude oil storage at Platteville, Colo., which is in turn fed by DJS’s 90,000 b/d Badger segment, 220,000 b/d Matador pipeline, and the 150,000 b/d bi-directional Freedom pipeline, linking Platteville to Lucerne West (OGJ Online, Oct. 15, 2019).
ARB’s crude oil gathering systems include over 250 miles of new pipeline covering the core of the DJ basin, with over 625,000 b/d of planned and existing throughput capacity and 600,000 bbl of storage. At over 250,000 dedicated acres underpinned by long term, fixed-fee contracts with numerous customers, ARB is the largest privately held crude oil gatherer in the DJ basin.
The continued expansion of the pipeline system in the DJ basin is funded by Ball Ventures through its energy division BV Natural Resources.
