OGJ Newsletter

Oct. 3, 2022
A roundup of General Interest, Exploration & Development, Drilling & Production, Processing, and Transportation news from around the industry.


Talos adds GoM scale with $1.1-billion EnVen buy

Talos Energy Inc. has agreed to acquire EnVen Energy Corp., a private operator in the deepwater US Gulf of Mexico, for $1.1 billion, expanding Talos’s Gulf of Mexico operations with high margin, oil-weighted assets, the operator said in a release Sept. 22.

The deal increases operational scale and diversity, Talos said, increasing production by 40%, gross acreage by 35%, and doubles the company’s operated deepwater infrastructure footprint.

EnVen currently produces about 24,000 boe/d (80% oil-weighted, over 90% operated), primarily (95%) from deepwater regions. The company operates numerous platforms, including five major deepwater structures with open capacity and holds about 420,000 gross acres in core deepwater areas for future infrastructure-led development, exploitation, and exploration opportunities, Talos said.

The infrastructure is backed by over $160 million in restricted cash and receivables reserved against future abandonment obligations, the operator noted.

On a pro forma basis, Talos expects to be more than 70% oil-weighted, more than 75% operated, and over 80% focused in deepwater regions.

Consideration consists of 43.8 million Talos shares and $212.5 million in cash, plus the assumption of EnVen’s net debt upon closing, currently estimated at $50 million at yearend 2022.

At closing Talos shareholders will own about 66% of the pro forma company and EnVen’s equity holders will own the remaining 34%.

Closing is expected by yearend, subject to closing conditions, at which time Talos expects to provide 2023 financial guidance.

ShaMaran to double Kurdistan production with deal close

ShaMaran Petroleum Corp., Vancouver, BC, has closed a deal to acquire 100% of the shares of TEPKRI Sarsang A/S, a subsidiary of TotalEnergies, which holds an 18% non-operated participating interest in the Sarsang PSC in the Kurdistan region of Iraq.

Through the acquisition, ShaMaran adds cash flow and potential production growth underpinned by its interests in two PSCs with three producing oil fields in the same vicinity, the company said in its release Sept. 15.  

The 420-sq km onshore Sarsang block, in the Zagros fold and thrust belt of northern Kurdistan, is on the northern border of ShaMaran’s Atrush block (27.6%) and is comprised of two producing oil fields: Swara Tika and East Swara Tika. Each field contains three independent Triassic oil reservoirs.

Swara Tika is currently producing over 29,000 b/d of oil (36-39 API) from six wells, according to operator HKN Energy Ltd.’s website. East Swara Tika has one well producing about 2,500 b/d of oil, according to the Dallas-based operator.

At Swara Tika, an expansion project is under way with the addition of a new 25,000 bo/d processing plant, which is expected to lift gross production to 50,000 b/d of oil. First oil is expected mid-September, the operator said in an update Aug. 17. Over the next 30 or more days, HKN will commission the plant, tie-in five previously drilled wells, conduct flow testing, and then optimize production rates. Export pipeline tie-in remains on track to align with completion of the plant expansion, the operator said. 3D seismic acquisition covering the western part of Swara Tika began in February 2022 and is expected to conclude in this year’s third quarter, according to the update.  

The deal between ShaMaran and TotalEnergies was signed in July 2021 for a firm consideration of $155 million and an additional contingent consideration of $15 million dependent on future production and oil prices. ShaMaran has filed paperwork to change TEPKRI’s name to ShaMaran Sarsang A/S.

Sarsang, discovered in 2011, is operated by HKN (62%). KRG holds 20%.

Interior sets Cook Inlet lease sale for December

An offshore oil and gas lease sale for tracts in Alaska’s Cook Inlet has been scheduled for Dec. 30. Lease Sale 258 was canceled by the Biden administration in 2021 but revived as part of the tax and spending bill passed by Congress in August (OGJ Online, Aug. 8, 2022).

The sale will include up to 224 blocks in the northern part of the Cook Inlet planning area, from roughly Kalgin Island in the north to Augustine Island in the south, in water depths ranging from 33 to 260 ft. A final notice of sale will be published no later than Nov. 30 with a list of specific blocks to be offered for bidding.

The Interior Department’s Bureau of Ocean Energy Management (BOEM) formally announced the lease sale in the Sept. 23 Federal Register and posted details on its website.

When the administration canceled the sale in May 2021, Interior Secretary Deb Haaland said it was terminated because of a lack of interest. Sen. Lisa Murkowski (R-Alas.) disputed that, saying she had heard expressions of interest from the oil and gas industry.

The tax and spending bill, named the Inflation Reduction Act of 2022, forced the issue by requiring that Lease Sale 258 be held by Dec. 31. The act required that the sale be held in accordance with the terms in the Record of Decision published in the Jan. 19, 2017, Federal Register.

The spending bill also revived Lease Sale 259, to be held for tracts in the Gulf of Mexico. That sale must be held no later than March 31, 2023. And the bill required that Lease Sale 261, also for the Gulf of Mexico, be held no later than Sept. 30, 2023.

 Exploration & Development Quick Takes

INEOS sanctions Solsort field expansion

INEOS made final investment decision to develop the west lobe of Solsort field (Solsort West) in the Danish North Sea after having received approval from the Danish Energy Agency. Production is expected to begin in fourth-quarter 2023.

The agency approved the plan for development and extraction on Sept. 21. Oil in the west lobe lies in Paleocene sands at a depth of 3,000 m. The accumulation extends across licenses 7/89, 3/09, and 4/98.

Solsort West, which lies about 250 km west of the Danish west coast, is expected to account for 12% of Danish oil production and 5% of gas production in 2024, according to the Danish Energy Agency’s production forecast released in August. 

Development consists of two wells (production well and a water injection well) drilled from the nearby INEOS-operated Syd Arne platform. The scope of work also includes unspecified changes to Syd Arne infrastructure. Produced oil from Solsort and Syd Arne is taken to Syd Arne’s storage tank on the seabed, the agency said. From there, the oil is exported using Syd Arne’s existing buoy loading system for tankers. Produced gas from Solsort is transported with Syd Arne gas through the Syd Arne-Nybro gas pipeline to the Nybro gas terminal on the west coast of Jutland where it is sent into Energinet’s transmission pipeline network. 

INEOS is operator of the Solsort unit. Partners are Danoil and Nordsøfonden.

VAALCO to advance Venus development with POD approval

VAALCO Energy is moving to develop the Venus discovery in Block P with the Sept. 16 plan of development (POD) approval from the Government of Equatorial Guinea. First oil is expected in mid- to late-2026, the operator said in a Sept. 26 release.

Block P covers an area of 1,253 sq km in the Rio Muni basin. The Venus discovery was made in 2005 by Devon Energy.

Upon execution of final documents, VAALCO will spud the first development well in early 2024, acquire, convert, and install production infrastructure over the next 3 years, and spud an additional development and a water injection well in 2025-26. Venus field activities are expected to add 23.1 million bbl of oil of 2P gross reserves.

Based on results from the initial discovery well and reservoir modeling, the operator expects production from the field to reach about 15,000 gross b/d of oil upon completion of the two development wells and injector well.

Preliminary estimated project cost for the development wells, injection well, and related production infrastructure is about $310 million.

The production sharing contract provides for a development and production period of 25 years from the POD approval date. Future production upside potential exists through the Europa discovery development and exploration upside potential exists with Saturno and Southwest Grande prospects, the company said as part of the accompanying investor presentation Sept. 26.

VAALCO is operator (80%) in Block P with partner Guinea Ecuatorial de Petroleós Co. (GEPetrol) (20% carried interest). The POD was submitted in July 2022 without the other Block P joint venture owner, Atlas Petroleum International Ltd., which opted not to participate. 

Shell lets EPCI contract for Jackdaw development

Shell plc has let an engineering, procurement, construction, and installation (EPCI) contract for Jackdaw gas field development in the UK North Sea, the service provider said in a release Sept. 22.

The contract, valued by the service provider at $75-250 million, covers pipelay for a 30-km tieback from the new Jackdaw platform to Shell’s Shearwater platform, as well as an associated riser, spoolpieces, subsea structures, and umbilicals.

The tieback will use pipe-in-pipe technology designed for high pressure, high temperature use.

The award comes on the heels of the operator’s wellhead platform contract to Aker Solutions in August and final investment decision (FID) taken on the project in July (OGJ Online, Aug. 2, 2022; July 25, 2022).

Jackdaw will comprise a wellhead platform, four production wells, and a 31-km pipeline from the platform to the Shearwater gas hub. The project is expected to come online mid-2020s, and at peak production rates estimated at 40,000 boe/d, could represent over 6% of projected UK North Sea gas production in the middle of this decade, the operator said at FID.

Jackdaw field is 100% owned and operated by BG International Ltd., a Shell UK Ltd. affiliate.

 Drilling & Production Quick Takes

Hess starts production at Malaysian offshore gas project

Hess Exploration and Production Malaysia BV began gas production at North Malay Basin (NMB) Phase III in Block PM302, 290 km offshore Malaysia, said partner PETRONAS Carigali Sdn Bhd in a Sept. 26 release.

NMB Phase III was sanctioned in 2019 and is part of a multi-phase development. It includes installation of the new Bergading-B wellhead platform that adds another 100 MMscfd of gas from the block, bringing total production to 400 MMscfd.

NMB is a long-life natural gas asset comprised of nine discovered natural gas fields with an estimated gross recoverable resource of more than 1.5 tcf natural gas and more than 20 million bbl condensate.

Hess operates the block with 50% interest. PETRONAS holds the remaining 50%.

Equinor drills dry hole near Oseberg Øst

Equinor Energy AS drilled a dry hole in the North Sea about 18 km north of Oseberg Øst field and 145 km northwest of Bergen in 185 m of water. The well is dry with traces of petroleum in all exploration targets. Data acquisition and sampling have been carried out, and the well has been permanently plugged.

Exploration well 30/3-11 S (Poseidon prospect), the first in production license (PL) 1104, was drilled by the Deepsea Stavanger drilling rig to a vertical depth of 4,593 m subsea. It was terminated in the Drake formation in the Middle Jurassic.

The objective of the well was to prove petroleum in Middle Jurassic reservoir rocks (the Brent group).

The well encountered about 120 m of sandstone with poor reservoir quality in the Tarbert, Ness, and Etive formations. In addition, about 75 m of sandstone were encountered with poor reservoir quality in the Oseberg formation.

The rig will now drill wildcat well 6607/12-5 in PL 943 in the Norwegian Sea, where Equinor Energy AS is operator.

Equinor is operator of PL 1104 with 40% interest. Partners are Lundin Energy Norway AS 40% and Source Energy AS 20%.

Mubadala subsidiary lets MOPU contract for Gulf of Thailand field

Mubadala Energy subsidiary Busrakham G11 Ltd. has let a contract to T7 Global Berhad subsidiary Tanjung Offshore Services Sdn. Bhd. for a mobile offshore production unit (MOPU) in Nong Yao oil field in the G11/48 concession of the southern Gulf of Thailand. 

Tanjung Offshore will be responsible for engineering, procurement, construction, installation, and commissioning of the MOPU and the subsequent leasing, operation, and maintenance for 5 years with a 2-year extension option.

Nong Yao field began production in June 2015. Mubadala Energy is operator with 90% participating interest. KrisEnergy Ltd. is partner.


TotalEnergies partners for Grandpuits sustainable aviation fuels production

TotalEnergies SE has entered an agreement with SARIA AS GmbH & Co. KG to partner on production of sustainable aviation fuel (SAF) as part of the operator’s Project Galaxie repurposing of its 101,000-b/d Grandpuits refinery at Seine-et-Marne near Melun in northern France, which intends to convert the site into a zero-crude industrial platform by 2025.

Under this agreement, TotalEnergies will take 50% ownership in SARIA’s conversion of animal fat esters into eligible feedstock to support production of SAF at the Grandpuits zero-crude platform, boosting the site’s proposed SAF capacity to 210,000 tonnes/year (tpy), or 25% higher, than initially planned for the conversion project, TotalEnergies said on Sept. 26.

As part of the deal, SARIA will take an equivalent stake in the Grandpuits biorefinery business, for which TotalEnergies will remain as operator, according to the companies.

In addition to other renewable-based feedstock, SARIA will directly supply used cooking oils as SAF feedstock for the project, TotalEnergies said.

Pending regulatory approvals, the planned strategic partnership with SARIA reinforces conversion of the Grandpuits site into a zero-crude platform specifically oriented towards SAF.

Already under way, TotalEnergies’ more than €500-million Project Galaxie at Grandpuits includes construction of a new biorefinery that will use Honeywell UOP LLC’s proprietary UOP Ecofining technology to process what initially was planned to be 400,000 tpy of mostly animal fats from Europe and used cooking oil—supplemented with other vegetable oils like rapeseed but excluding palm oil—primarily from local suppliers to produce 170,000 tpy of SAF; 120,000 tpy of renewable diesel; and 50,000 tpy of renewable naphtha for production of bioplastics.

TotalEnergies—which discontinued crude oil refining at Grandpuits in first-quarter 2021 and will cease storage of petroleum products at the site by late 2023—most recently said it expects to commission new units at Grandpuits in 2022-24 to reach full operation of the zero-crude platform by 2025.

Already supplying SAF to French aircraft operators since 2021, TotalEnergies also recently began producing SAF at its 253,000-b/d integrated Normandy refining and petrochemicals platform in Gonfreville l’Orcher, France.

Marathon, Neste formalize JV for Martinez refinery-to-renewables project

Marathon Petroleum Corp. (MPC) and Neste Corp. have finalized a deal to become equal partners in MPC’s Martinez Renewable Fuels (MRF) project to transform the now-idled Martinez, Calif., refinery into a renewable fuels production site.

With all required closing conditions met, including receipt of necessary permits and regulatory approvals, MPC and Neste have officially formed Martinez Renewables, a 50-50 joint venture partnership under which Neste joins the MRF with a total investment of $1 billion, inclusive of half the project’s estimated $1.2-billion total development costs through completion, the companies said on Sept. 21.

While MPC will continue to manage project execution and operate the renewables plant, the partners will equally be responsible for feedstock sourcing, as well as evenly share annual production output from the site.

Currently targeted to reach mechanical completion by yearend 2022, the MRF’s first phase is scheduled to begin production of 260 million gal/year of renewable diesel in early 2023, with pretreatment capabilities to come online in second-half 2023.

By yearend, 2023, MPC and Neste said they expect the converted Martinez refinery to reach its full nameplate production capacity of 730 million gal/year.

Finalizing of the partnership follows MPC’s early August announcement it received Bay Area Air Quality Management District’s (BAAQMD) preliminary approval of the MRF’s air quality permit based on the local regulator’s determination that the MRF will comply with all local, state, and federal air quality-related regulations, including health risks resulting from toxic air contaminant emissions.

While BAAQMD’s preliminary recommendation to issue a final permit for the project remained subject to a 30-day public comment period on the draft air permit that ran through Aug. 23, the agency has yet to issue word of its formal permit approval.


Momentum to build Hayneville gathering, sequestration network; completes acquisitions

M6 Midstream LLC (Momentum) has taken final investment decision (FID) on its new natural gas gathering and carbon capture and sequestration project, New Generation Gas Gathering (NG3). NG3 will have an initial gas gathering capacity of 1.7 bcfd, expandable to 2.2 bcfd. It will also capture and permanently sequester up to 2.0 million tons/year of CO2. The project is expected to begin operations in second-half 2024.

The system is anchored by long-term volume commitments from Haynesville shale producers, including Chesapeake Energy Corp., which also has an option to own 35% of the project. It will deliver to US Gulf Coast markets.

Momentum also completed acquisitions of Midcoast Energy LLC’s East Texas business (Midcoast ETX) from an affiliate of ArcLight Capital Partners LLC and Align Midstream Partners II from Tailwater Capital. Both businesses are also active in the Haynesville.

The combined assets of Midcoast ETX and Align Midstream bring Momentum’s current gathering capacity to more than 2 bcfd across roughly 3,000 miles pipeline. It also now has 1.5 bcfd of gas treatment, 700 MMcfd of gas processing, 200,000 hp of compression, and 820 miles of transportation pipelines delivering gas to Gulf Coast markets in southeast Texas and the Carthage and Bethel hubs in east Texas.

Terms of the transactions were not disclosed.

QatarEnergy chooses TotalEnergies as North Field South partner

QatarEnergy has selected TotalEnergies SE as the first international partner in the 16-million tonne/year (tpy) North Field South (NFS) LNG project. TotalEnergies will obtain a 9.375% participating interest in the NFS project – out of a total 25% available for international partners – with QatarEnergy holding the remaining 75%.

The upstream part of the project will develop the southern area of the North Field with five platforms, 50 wells, and natural gas pipelines to the onshore processing plant. Downstream will include two 8-million tpy liquefaction trains. NFS and 32-million tpy North Field East (NFE) form the wider North Field Expansion project, through which QatarEnergy plans to add 48 million tpy of LNG export capacity by 2028, bringing its total to 126 million tpy (OGJ Online, June 20, 2022).

TotalEnergies was also the first partner selected for NFE and holds 6.25% of the project, which combined with its stake in NFS will add 3.5 million tpy of LNG production to its portfolio by 2028.  

TotalEnergies will invest a total of roughly $1.5 billion in NFS.

Equinor signs gas deal with PGNiG

Equinor Energy AS agreed to a 10-year gas supply agreement with Poland’s PGNiG, the company said in a Sept. 23 release.

The agreement calls for the supply of 2.4 bcm/year (bcmy) of gas from the Norwegian Continental Shelf to be exported through the new Baltic Pipe, which connects the Norwegian gas export system to Poland via Denmark and facilitates flow of Norwegian pipeline gas to Poland.

Volumes under the new, long-term agreement are equivalent to around 15% of the typical, annual gas consumption in Poland. The agreement runs January 2023 to January 2033.

The pipeline—a joint project of Polish GAZ-SYSTEM and Danish Energinet—is expected to begin operations Oct. 1. Beginning in 2023, the pipeline will enable transportation of about 10 bcmy, of which PGNiG has reserved about 8 bcmy, the company said in a separate release Sept. 23.

According to PGNiG, 3 bcm of gas delivered via the Baltic Pipe will be supplied from PGNiG’s own Norwegian Continental Shelf production with an expected increase to 4 bcmy by 2027.

As part of an ongoing strategy to move away from Russian-supplied gas, PGNiG has signed contracts with suppliers operating on the Norwegian Continental Shelf to utilize the remainder of the reserved capacity, including the recent agreement with Equinor.