GENERAL INTEREST Quick Takes
Diamondback to acquire QEP
Diamondback Energy Inc. and QEP Resources have entered into a definitive agreement under which Diamondback will acquire QEP in an all-stock transaction valued at $2.2 billion, including QEP’s net debt of $1.6 billion as of Sept. 30, 2020. Consideration will consist of 0.05 shares of Diamondback common stock for each share of QEP common stock, representing an implied value to each QEP stockholder of $2.29/share based on the closing price of Diamondback common stock on Dec. 18, 2020. The transaction was unanimously approved by the board of directors of each company.
The acquisition adds material Tier 1 Midland basin inventory to Diamondback’s portfolio. QEP holds about 49,000 net acres in Midland basin. The company reported third-quarter 2020 average production of 48,300 bo/d, with average Permian basin production of 30,500 bo/d (47,600 boe/d).
Diamondback acquired 48 current drilled but uncompleted wells (DUC), which it plans to work down along with its own DUC balance in 2021. The company will divest QEP’s Williston assets pending market conditions, with potential sale proceeds used to reduce debt.
The pending QEP acquisition, together with the previously announced pending acquisition of assets from Guidon Operating LLC, will bring Diamondback’s total leasehold interests to over 276,000 net surface acres in Midland basin (429,000 Midland and Delaware basin net acres).
Rosneft completes KrasGeoNac farmout to Equinor
Rosneft completed a farmout of a 49% interest in KrasGeoNac LLC to Equinor for $550 million including a cash consideration of $325 million at the Jan. 1, 2019, effective date and customary adjustments.
KrasGeoNaC holds 12 conventional onshore exploration and production licenses in Eastern Siberia. One of the licenses, the North Danilovsky development, began production in July and is expected to reach 40,000 b/d of oil by 2024, with plans to increase production to 70,000 b/d of oil.
As part of the agreement, Equinor has redirected its remaining exploration commitments offshore in the Sea of Okhotsk and as such has no outstanding obligations in that area.
88 Energy farms out half interest in Alaska project
Perth-based 88 Energy Ltd. has farmed out a 50% interest in its Project Peregrine in the NPR-A region of the North Slope of Alaska to Alaska Peregrine Development Co. LLC (APDC). 88 Energy will retain a 50% stake.
APDC will contribute $11.3 million to the cost of the upcoming Merlin-1 wildcat which 88 Energy estimates will cost $12.6 million to drill.
The well, expected to spud during mid- to late-February 2021, is the first in a two-well program to evaluate the shallow target Nanushuk reservoir. Merlin lies directly north of the Umiat oil find estimated to contain more than 1 billion bbl of oil in place.
All American Oilfield LLC’s light-weight workover rig (Rig 111) has been contracted for the program. The unit can be transported off-road in pieces by tundra-safe track vehicles along snow trails and gravel roads and obviates the need for the construction of an ice road to the location.
The second well, Harrier-1, will follow immediately after Merlin-1 (OGJ Online, Nov. 19, 2020).
Drilling depths of 6,000 ft are anticipated to reach the reservoir formation which carries multiple conventional targets.
The Peregrine leases lie 35 km south of the ConocoPhillips oil discovery at Willow, which has an estimated 450-800 MMboe.
APDC is as a special purpose investment vehicle organized for Project Peregrine. Its members are a consortium of private US entities managed by individuals experienced in oil and gas, some of whom own businesses operating on the North Slope.
In a separate release, 88Energy said it has reduced its lease area for its Icewine project in the central North Slope by 25%. The company is now focusing on farmout negotiations for remaining leases around the recently drilled Charlie-1 well.
Exploration & Development Quick Takes
Petronas, ExxonMobil discover hydrocarbons offshore Suriname
Petronas subsidiary Petronas Suriname Exploration & Production BV (PSEPBV) and Block 52 partner ExxonMobil discovered hydrocarbons at the Sloanea-1 well offshore Suriname. The discovery is being evaluated to determine its resource potential.
The well, drilled to 15,682 ft total depth by the Maersk Developer rig, encountered several hydrocarbon-bearing sandstone packages with good reservoir qualities in the Campanian section. The well data proves excellent calibration of the hydrocarbon potential of the block, the operator said.
Block 52, north of the coast of Paramaribo, lies in the prospective Suriname-Guyana basin covering an area of 4,749 sq km with water depths from 50-1,100 m.
PSEPBV is operator of the block with 50% interest. The company completed a deal to farm out the other 50% interest to ExxonMobil subsidiary ExxonMobil Exploration and Production Suriname BV in May 2020.
Australian government to fund accelerated Beetaloo exploration
The Australian government plans to accelerate gas exploration and development in the Beetaloo sub-basin onshore Northern Territory.
Minister for Resources, Water and Northern Australia, Keith Pitt, said the government will provide up to $50 million (Aus.) for exploration that occurs before June 30, 2022.
The funding aims to fast-track drilling by providing grants to cover 25% of eligible exploration costs, capped at $7.5 million (Aus.) per well and three wells per exploration venture.
Pitt said that the Northern Territory’s Geological Survey estimates the sub-basin could hold more than 200,000 petajoules of gas.
“Even if only a very conservative 10% of that gas was recovered, it could supply Australia’s domestic gas demand for more than 10 years,” he said. “Industry analysis estimates the development of the sub-basin could increase economic activity by between $18 billion (Aus.) and $36.8 billion (Aus.) over the next 20 years,” he said.
Gjøa expansion startup gets green light
Neptune Energy has been granted consent from the Norwegian Petroleum Directorate for startup of a subsea installation with two new wells on Gjøa oil and gas field in North Sea production license 153.
At a cost of four billion kroner, the project is expected to add 2.4 million standard cu m of oil equivalent (15 MMboe) from the field off the coast of Florø. The new wells are linked to the P1 segment, one of seven segments on the field.
In addition to enabling recovery of oil and gas by drilling new wells in deeper-lying reservoirs, the Gjøa P1-segment will extend the operating life of the platform, said Erik Oppedal, Neptune Energy’s director of projects and engineering in Norway.
Continued work on Gjøa resulted in licensees submitting an application for exemption from a plan for development and operation (PDO) for the P1 segment in February 2019. A four-slot well template has been put into place and two wells have been drilled. Startup is expected in January 2021.
Licence partners are Neptune Energy Norge (30% and operator), Petoro AS (30%), Wintershall (28%), and OKEA (12%).
Aker BP to produce Gråsel field in late 2021
Aker BP and license partners will go forward with development of Gråsel in the Norwegian Sea, about 210 km west of Sandnessjøen. Final investment decision was made Dec. 17, 2020. First oil is expected fourth-quarter 2021.
Gråsel (Grey Seal) is within the same license unit as Skarv and Ærfugl fields. The reservoir, which extends over 7 km and is 2 km wide, lies above the Skarv reservoir, about 210 km west of Sandnessjøen. It holds mostly oil, with reserves estimated at 13 million boe. The development consists of a new producer drilled from an existing well slot on Skarv field, and injection support from a joint injector for Gråsel and Tilje. Production will come online concurrent with start-up of gas production from phase two of the Ærfugl development project.
Gråsel has a $15/bbl break-even oil price due to nearby production infrastructure, including the Scarv floating production and storage unit (FPSO), said Paweł Majewski, PGNiG SA chief executive officer.
Total investment costs for the project are 1.2 billion kroner.
Aker BP is operator with 24%. Partners are Equinor (36%), Wintershall DEA (28%), and PGNiG Upstream Norway (12%).
Drilling & Production Quick Takes
Equinor to invest $343 million in Statfjord Ost
Equinor Energy AS and partners will invest $343 million in North Sea Statfjord Ost field to improve recovery by 23 million boe. As part of the project, four new wells will be drilled from existing subsea templates between 2022 and 2024. Statfjord Ost comprises Production Licenses 037 and 089 and is 3 miles northeast of Statfjord C. It is tied back to the Statfjord C platform by pipelines. The project also includes modifications on Statfjord C and a new pipeline for gas lift. Production from the new wells is scheduled to start in 2024.
Statfjord Ost came on stream in 1994. Original oil volume in place was 415 million bbl oil with 56% current recovery factor. The new project is expected to increase recovery factor to 62%.
Written notification of material changes to the plan for development and operation for Statfjord Ost has been submitted to the Ministry of Petroleum and Energy.
Equinor is operator in Statfjord Ost (31.6875%) with partners Petoro AS (30%), Var Energi AS (20.55%), Spirit Energy Norway AS (11.5625%), Idemitsu Petroleum Norge AS (4.8%), and Wintershall Dea Norge AS (1.4%).
Snorre expansion production begins offshore Norway
Production from the Snorre Expansion Project in the North Sea began Dec. 12, 2020. The increased oil recovery project—originally scheduled to come on stream first-quarter 2021—is expected to add almost 200 million bbl of recoverable oil reserves and help extend the productive life of the field through 2040, operator Equinor said in a Dec. 14, 2020, release.
In November 2020, Equinor received consent from the Norwegian Petroleum Directorate to start up Snorre expansion in Blocks 34/4 (PL 057) and 34/7 (PL 089) of the Tampen area, about 200 km west of Florø in the Norwegian North Sea (OGJ Online, Nov. 16, 2020).
The expansion consists of 24 new wells (13 production wells, 11 water-alternating gas injectors) in six subsea templates and will be tied into Snorre A floating tension-leg platform (OGJ Online, Oct. 10, 2018). Bundles connecting the new wells to the platform have been installed, in addition to new risers. The project also includes a new module and modifications on Snorre A.
After 3 years of modifications on a platform on stream, final preparations to receive oil from the new wells were performed during a major turnaround in 2020.
Equinor is operator at Snorre (33.3%) with partners Petoro AS (30%), Var Energi AS (18.5%), Idemitsu Petroleum Norge AS (9.6%), and Wintershall Dea Norge AS (8.6%).
W&T Offshore increases guidance with restored production
W&T Offshore Inc., Houston, has increased its fourth-quarter production guidance following restoration of the majority of production that was shut-in due to storms in the Gulf of Mexico as well as production at Magnolia field that was offline due to extended downtime at a third-party operated platform downstream from the field.
The operator now expects fourth-quarter production to average 34,700-36,900 boe/d, of which 34% is estimated to be oil, 11% natural gas liquids, and the balance natural gas. A prior estimate was an average of 31,500-35,000 boe/d.
W&T Offshore produced 34,459 boe/d (48% liquids) in third-quarter 2020, reflecting a 16% decrease from the year prior quarter, primarily due to shut-ins related to the 2020 hurricane season.
The company became the sole owner of Magnolia field in 2020 following deals with ConocoPhillips and Marubeni (OGJ Online, Mar. 5, 2020).
Norway production increased in November, NPD says
Norway’s liquids production averaged 2.026 million b/d in November, the Norwegian Petroleum Directorate reported. Norway’s daily liquids production averaged 1.877 million b/d in October (OGJ Online, Nov. 23, 2020).
On Apr. 29, the government decided to implement a cut in Norwegian oil production. The production figures for oil in November include this cut of 134,000 b/d in the second half of 2020. Oil production in November is equal to the NPD’s forecast, and 1.9% below the forecast so far this year.
The average daily liquids production in November consists of 1.725 million b/o, 290,000 bbl of NGL, and 12,000 bbl of condensate.
The total petroleum production for the first 11 months of the year is about 207.9 million standard cu m oil equivalents.
PROCESSING Quick Takes
ExxonMobil considers upgrading Baton Rouge refining complex
ExxonMobil Corp. is considering a more than $240-million investment on an initial round of modernization projects aimed at ensuring long-term competitiveness of subsidiary ExxonMobil Fuels & Lubricants Co.’s 518,000-b/d integrated refining and petrochemical complex in Baton Rouge, La.
Still pending final engineering, design, and investment decisions, the proposed suite of potential projects would involve works to improve the refinery’s processing capability and increase its flexibility for meeting market demand, as well as installation of technology that would reduce volatile organic compound emissions at the site by 10%, Louisiana Gov. John Bel Edwards, the Louisiana Economic Development (LED), and Baton Rouge Area Chamber (BRAC) said in separate Dec. 16 releases.
To support the proposed investment, LED said it has offered ExxonMobil the comprehensive solutions of its FastStart state workforce training program as well as access to Louisiana’s Industrial Tax Exemption Program (ITEP). As part of the incentivization program, ExxonMobil would, in turn, focus on providing supplier opportunities specifically to North Baton Rouge businesses, according to LED and BRAC.
While neither LED, BRAC, or ExxonMobil have officially revealed additional information regarding specific projects to be included in the potential spending plan, the proposed investment program, if approved, would pave the way for more extensive works at the site, according to Gloria Moncada, plant manager of the Baton Rouge refinery.
Seemingly dependent upon ITEP incentives, ExxonMobil could reach FID on the initial $240-million investment plan in 2021, LED said.
In its latest presentation to investors, ExxonMobil said it continues to progress with construction of a 450,000-tonnes/year polypropylene (PP) unit at the Baton Rouge complex, which remains on track for startup sometime in 2021 (OGJ Online, Mar. 1, 2019).
Tüpras¸ upgrades Izmit refinery to expand diesel production
Türkiye Petrol Rafinerileri AS¸ (Tüpras¸) has completed a project to increase conversion capability of the 8,000-cu m/day (50,000-b/d) integrated hydrocracking unit installed as part of the operator’s $2.7 billion residuum upgrading project (RUP) commissioned in 2015 at the 11.3-million tonnes/year Izmit refinery in District Körfez of Turkey’s northwestern province of Kocaeli, to enable processing of high-sulfur fuel oil and other excess residual products into higher-value clean fuels that meet Euro 5 standards (OGJ Online, July 27, 2016).
As part of the unit upgrade to expand production of diesel, Honeywell UOP LLC delivered basic engineering, catalysts, and technical services for the addition of an external heavy polynuclear aromatics (HPNA) stripper to the RUP’s existing Honeywell UOP-licensed two-stage Unicracking system, the service provider said.
Alongside allowing Tüpras¸ to increase its flexibility to process heavier feedstocks, addition of the HPNA stripper will increase conversion efficiency of the integrated Unicracking unit by mechanically removing HPNAs that cause catalyst deactivation, enabling the operator to maximize conversion in the unit to and increase its yield of distillates, according to UOP.
Tüpras¸ completed project-related works on the Unicracking system’s hydrocracker in PLT-147 of the Izmit refinery’s RUP during scheduled maintenance executed during fourth-quarter 2020, the operator said in its December 2020 presentation to investors.
In addition to its hydrocracker, the RUP’s integrated Unicracking system includes a 1,200-cu m/day (7,500-b/d) naphtha unit and 4,000-cu m/day diesel desulfurization unit, both based on Honeywell UOP’s proprietary Unionfining process technology, according to Tüpras¸ and the service provider.
Brazos Midstream lets contract for gas plant upgrades
Brazos Midstream Holdings LLC has let a contract to Honeywell International Inc. subsidiary UOP LLC to deliver technology licensing for the upgrade of two cryogenic natural gas processing plants at the company’s operations in Reeves County, Tex., in the Permian basin.
As part of the contract, UOP will upgrade two existing 200-MMcfd gas processing plants from gas subcooled process (GSP) to UOP-owned Ortloff recycle split vapor (RSV) technology, a newly developed technology that can increase recovery of more ethane and propane, UOP said on Dec. 17, 2020.
Designed to improve conventional GSP cryogenic gas processing by recycling the gas product to increase the recovery rate of NGLs from about 92% to nearly 100%, the Ortloff RSV technology will enable Brazos Midstream’s two plants to better process NGL-rich gas produced in the region to improve operating margins, according to UOP.
While neither UOP nor Brazos Midstream provided additional details on the proposed upgrade or a timeline for its commissioning, UOP did confirm its UOP Russell business will provide fabrication and assembly of the modular RSV units.
Brazos Midstream previously let a contract to UOP to provide engineering, fabrication, and supply of proprietary UOP Russell modular cryogenic NGL-recovery units for its Comanche I, II, and III plants in the Delaware portion of the Permian basin (OGJ Online, Jan. 23, 2018; Oct. 10, 2017).
TRANSPORTATION Quick Takes
Tellurian withdraws Permian Global Access prefiling
Tellurian Inc.’s Permian Global Access Pipeline LLC (PGAP) in December 2020 withdrew the National Environmental Policy Act (NEPA) prefiling request with the US Federal Energy Regulatory Commission (FERC) for its proposed 625-mile, 42-in. OD natural gas pipeline. PGAP’s planned route from Waha, Tex., to Gillis, La., crossed 24 counties and 4 parishes.
The pipeline would have provided as much as 2.3 bcfd of incremental firm transportation service to markets in Southwest Louisiana, including Tellurian’s planned 27.6-million tonne/year Driftwood LNG liquefaction plant. Tellurian is still seeking customers for Driftwood, which it hopes to start building in 2021. Tellurian earlier in 2020 delayed PGAP construction as part of cost-cutting related to Driftwood LNG (OGJ Online, Aug. 13, 2020).
PGAP said in the letter withdrawing the prefiling that it continues to believe that in time the pipeline would provide significant benefits, but that the arrival of the COVID-19 pandemic, ensuing collapse of domestic and global energy commodity prices, reduced consumption, and the addition of alternative transportation solutions out of the Permian basin had reduced need for the project to the point that it was no longer viable.
The company added that in the event market conditions rebound and the market needs an additional transportation solution, it would host a new open season and work with FERC to reestablish the NEPA prefiling review process.
PGAP filed with its NEPA prefiling request with FERC on Aug. 20, 2019. FERC approved the request Sept. 13, 2019.
Sempra, Total finalize ECA LNG equity investment
Sempra LNG and Infraestructura Energética Nova SAB de CV (IEnova) joint venture ECA Liquefaction (ECA LNG) signed an equity investment agreement to finalize Total’s 16.6% equity stake in 3.25-million tonne/year (tpy) ECA LNG Phase 1 in Baja California, Mexico. ECA LNG Phase 1 will be built at IEnova’s existing Energía Costa Azul LNG regasification terminal and is expected to begin operations in 2024. Sempra and IEnova will each retain 41.7% ownership. The equity acquisition by Total does not include an equity interest in the regasification terminal.
In November 2020, ECA LNG announced it had reached a final investment decision for construction and operation of the plant (OGJ Online, Nov. 17, 2020). ECA LNG Phase 1 will use a single liquefaction train with an initial offtake capacity of 2.5 million tpy.
Earlier in 2020, Total signed a 20-year agreement for 1.7 million tpy of ECA LNG’s production. ECA LNG Phase 1 also has an agreement with Mitsui & Co. Ltd. for the purchase of 0.8 million tpy of LNG from the project.
Sempra LNG and Total are already partners in Cameron LNG, a 12-million tpy plant operating in Hackberry, La. Phase 1 of Cameron LNG reached full commercial operations in August 2020.
Sempra is developing additional LNG export capacity on the Gulf Coast and Pacific Coast of North America, including 8-million tpy Cameron LNG Phase 2 and 7-million tpy ECA LNG Phase 2.