OGJ Newsletter

Nov. 22, 2021


Tullow pre-empts Kosmos deal for assets offshore Ghana

Tullow Oil PLC has exercised its pre-emption rights related to the sale of Occidental Petroleum Corp.’s interests in Tullow-operated Jubilee and TEN fields offshore Ghana to Kosmos Energy.

The operator is poised to pay about $150 million for the Deep Water Tano (DWT) block based on joint venture partners exercising pre-emption rights.

If both Kosmos Energy Ghana HC and Petro SA do not pre-empt, Tullow would pre-empt the entire participating interest which would increase Tullow’s equity in the DWT block by 11.05% for $206 million.

The announcement falls within the 30-day pre-emption period noted at the time of the October deal struck between Kosmos and Occidental for an additional 18% interest in Jubilee field and an additional 11% interest in TEN fields (OGJ Online, Oct. 25, 2021).

The exercise of pre-emption rights is subject to finalizing definitive agreements with Kosmos-Anadarko and requires approval from Ghana National Petroleum Corp. and the Ghanaian Ministry of Energy. If completed, Kosmos’ ultimate interest in Jubilee would be reduced by 3.8% to 38.3% (Kosmos retains about 80% of the original acquired interest), and Kosmos’ ultimate interest in TEN would be reduced by 8.3% to 19.8% (Kosmos retains about 25% of the original acquired interest).

Continental Resources increases quarterly earnings, acquires Permian acreage

Continental Resources Inc., Oklahoma City, Okla., agreed to acquire certain Permian basin assets from Pioneer Natural Resources in an all-cash transaction valued at about $3.25 billion.

The deal, expected to close in December subject to conditions, was announced as part of both companies’ third-quarter 2021 earnings reports (OGJ Online, Nov. 4, 2021).

Continental said the assets complement its portfolio in the Bakken, Oklahoma, and—through an earlier deal with Samson Resources II LLC—the Powder River basin (OGJ Online, Mar. 15, 2021). The Permian deal includes production of 55,000 boe/d (70% oil) and 92,000 contiguous net leasehold acres with over 650 gross operated locations in Third Bone Spring/Wolfcamp A & B and over 1,000 total locations, including additional zones producing in the basin. Extensive water infrastructure is in place, the company said.

For the quarter, Continental had net income of $369.3 million compared to net income of $289.3 million in second-quarter 2021. Typically excluded items in aggregate for the third quarter represented $67.9 million of its reported net income. Adjusted net income for the quarter was $437.2 million compared to adjusted net income for second-quarter 2021 of $332.8 million. Net cash provided by operating activities for third-quarter 2021 was $1.02 billion and EBITDAX was $1.12 billion.

Third-quarter 2021 total production averaged 331,400 boe/d compared to second-quarter 2021 total production average of 338,700 boe/d. Third-quarter 2021 oil production averaged 157,200 b/d. Third-quarter 2021 natural gas production averaged 1,046 MMcfd.

Ensign acquires Eagle Ford acreage from Reliance

Ensign Natural Resources LLC, Houston, has acquired Eagle Ford assets from Reliance Eagleford Upstream Holding LP, a subsidiary of India’s largest business conglomerate, Reliance Industries Ltd.

The acquisition includes about 62,000 net acres in Bee, DeWitt, Karnes, and Live Oak Counties and current net production of about 18,000 boe/d, increasing Ensign’s current ownership to 100% in the leases and wells it acquired from Pioneer Natural Resources USA Inc. in 2019 and Newpek LLC in 2020 (OGJ Online, May 7, 2019, Aug. 19, 2020).

Post the Reliance acquisition, Ensign owns and operates 130,000 acres in the core of the Eagle Ford with current production near 40,000 boe/d, and Reliance has divested all its shale gas assets and has exited from the shale gas business in North America.

Ensign was formed in 2017 in partnership with Warburg Pincus. As part of the Pioneer acquisition, the company secured an equity commitment from the Kayne Private Energy Income Funds.

 Exploration & Development Quick Takes

Key Petroleum upgrades Cooper basin Alfajor prospect

Key Petroleum Ltd., Perth, has completed remapping of its Alfajor prospect in its 100%-owned and operated southern Queensland Cooper basin permit ATP 924 resulting in a material upgrade to potential recoverable gas resources within the primary target Permian-age Toolachee formation reservoir.

P50 prospective recoverable gas resources are estimated at 97.1 bcf. A P90 estimate is 33.9 bcf while P10 is 227.4 bcf, with a mean of 122.5 bcf.

Additional prospective resources may be ascribed within the prospect to overlying Jurassic Eromanga basin closures including the Hutton sandstone, the company said.

Alfajor prospect is now mapped as a prominent, relatively high relief structure with 4-way dip closure and enhanced trapping geometry due to drape closure over an early Permian glacial landscape of mesas and intervening steep valleys. The prospect is adjacent to the proven hydrocarbon generative Windorah Trough.

The early drape closure may mean that Alfajor was favorably positioned to capture migration of hydrocarbons from early phases of generation in Windorah Trough.

Key said the closure as mapped has limited or no faulting affecting the main closure. The company’s interpretation based on the new 3D data suggests the formation and reservoir characteristics for the trap may be analogous to the producing Barrolka gas field about 50 km to the southeast.

The prospect is about 40 km from the Carpentaria gas trunkline.

Key is finalizing a location to drill a 2,800-m deep wildcat to evaluate the Alfajor prospect. The company expects to complete preparations, including well planning and permitting, for drilling by mid-2022.

Aker BP plugs minor oil discovery south of Bøyla field in the North Sea

Aker BP ASA plugged a North Sea discovery as license holders do not consider it to be commercial. Preliminary estimates place recoverable oil equivalent at 800,000 standard cu m. (OGJ Online, Oct. 18, 2021).

Wildcat well 24/12-7—the first in production license 1041—was drilled about 17 km southwest of Bøyla field and 230 km west of Stavanger to a measured vertical depth of 2,275 m below sea level. It was terminated in the Heimdal formation. Water depth at the site is 118 m.

The primary exploration target was to prove petroleum in reservoir rocks from the Palaeocene in the Hermod formation. The secondary target was to prove petroleum in reservoir rocks from the Palaeocene in the Heimdal formation.

In the primary exploration target, the well encountered the Hermod formation in a thickness of about 75 m. A 38-m oil column was proven in a total of 20 m of sandstone, with very good to extremely good reservoir properties.

The oil-water contact at 2,132 m below sea level was confirmed with pressure points.

In the secondary exploration target, the well encountered a total of 34 m of aquiferous sandstone with good reservoir properties in the Heimdal formation.

The well was not formation-tested, but data acquisition was undertaken.

Aker BP is operator with 55% interest. Partners are Neptune Energy Norge AS (30%) and Lundin Energy Norway AS (15%).

Woodside increases Pluto field proven reserves

Woodside Petroleum Ltd. has increased total 1P reserves for the Greater Pluto field region on the Northwest Shelf off Western Australia by about 10%. At the same time, estimates for total 2P reserves have decreased by 10%.

The review follows completion of integrated subsurface studies incorporating 4D seismic and well performance data. The figures exclude production for 2021.

The region comprises five fields. Woodside is operator of production license WA-34-L (Pluto, Xena, Pyxis fields) with 90% interest. The company is operator of exploration permit WA-404-with 100% interest (Larsen, Martell, Martin, Noblige, Remy fields).

Woodside’s share of total 1P reserves (developed and undeveloped) in the area increased by 29.2 MMboe to 317.1 MMboe from 287.9 MMboe in 2020. The company’s share of total 2P reserves decreased by 45.7 MMboe to 394.9 MMboe from 440.5 MMboe in 2020. Greater Pluto 2C contingent resource decreased about 7% to 218.4 MMboe from 234.3 MMboe.

Greater Pluto has produced more than 440 MMboe from Pluto-Xena reserves since coming on stream in 2012. The region has total 2P reserves of about 360 MMboe for production in the years ahead, Woodside said.

 Drilling & Production Quick Takes

Timor Resources spuds first onshore well in East Timor in 50 years

Timor Resources Pty Ltd., Brisbane, has spudded the first onshore exploration well in East Timor in more than 5 decades.

The well, Feto Kmaus, lies in production sharing contract TL-OT-1708 in Suai near the island’s southern coast.

It is also the first well to be drilled onshore since East Timor gained its independence from Indonesia in 2002. Historically, drilling dates back to 1910 with the bulk of wells in the country drilled during the 1960s and early 1970s in an area that is noted for 30 oil and seven gas seeps.

There has been no commercial production, but some seepage oil is used by local villagers.

Timor Resources signed the PSC in 2017 and began its campaign by acquiring new 2D seismic data, interpretation of which has identified two prospects, Feto Kmaus and Liurai, both of which have multiple targets.

Historical data combined with modern technology has delineated structural and stratigraphic plays throughout the PSC, the company has said.

An independent assessment by Netherland Sewell in 2018 suggested the region has potential to yield more than 120 million bbl of recoverable oil.

The Feto Kmaus well will be followed immediately by Liurai.

Eastern Drilling is providing the rig and an operations crew. The rig was landed in East Timor last year, but the drilling program has been delayed by the COVID pandemic.

Timor Resources is operator of the program with 50% interest. East Timor’s state-owned company TimorGAP has the remaining 50%.

Elixir flows gas and water to surface in Nomgon-6 CSG well

Elixir Energy Ltd., Adelaide, has flowed gas and water to surface for the first time in its Nomgon coal seam gas exploration project in southern Mongolia.

The company reported that fluids flowed to surface from four separately tested zones in its Nomgon-6 well. The presence of methane was recorded from all four zones using a handheld gas meter.

Cumulative water production rate from the four zones was 280 b/d.

Nomgon-6 was drilled to a total depth of 501 m and intersected 84 m of coal.

Elixir said four air-assisted drill stem tests (DST) were performed over the 100-series coal. The DSTs comprised an air-assisted flow test, a conventional flow test, and an injectivity fall-off test.

Methane concentrations of up to 25,000 parts per million were measured over a background of zero (uncalibrated).

Data gathered from these tests will now be fed directly into the planning of a long-term pilot production testing program which is planned for 2022, the company said. In the meantime Nomgon-6 has been suspended and will be used as a monitoring well in the coming long-term test.

Elixir said its exploration work in the recently-discovered Richcairn subbasin has been proceeding in parallel with the Nomgon work.

Richcairn-2S, about 25 km northeast of Nomgon-6, reached a depth of 801 m and logged 8 m of coal and 9 m of highly carbonaceous mudstone. This was followed by nearby Richcairn-3S which reached a depth of 800 m and logged 13 m of coal.

The company plans to follow this work up with Richcairn-4S in the same cluster while a second rig will move to drill the Bag-1S exploration well in a separate area about 70 km to the east.

A third rig has spudded the delayed Richcairn West-1S about 35 km west of Richcairn-4S.

At the same time, the company is running a new 300 km 2D seismic survey in the region and has acquired about 132 km (44%) so far.

Elixir has 100% interest in the overall Nomgon IX coal seam gas production sharing contract.

LOGOS brings Mancos shale wells online

LOGOS Resources II LLC, Farmington, NM, brought online two natural gas wells in the Mancos shale in northwest New Mexico.

Early production rates at the Rosa Unit #654H and Rosa Unit #656, both in Rio Arriba County, are the highest achieved in the past 20 years within the San Juan basin, the company said in a release Oct. 29.

Rosa #654H achieved an average 30-day initial production (IP30) rate of about 18.2 MMcfd and Rosa #656H achieved an IP30 of 18.3 MMcfd, while the wells were choked back by an average of about 33%. The IP30 for each well exceeded the previous Mancos gas horizontal IP30 record by about 40%.

The wells were drilled from a single pad with a 10,000-ft laterals in an area known as the Rosa Exploratory Unit. The 54,000-acre unit is operated by a LOGOS affiliate.


ExxonMobil reaches FID on proposed Guangdong chemical complex

ExxonMobil Corp. is moving forward with a previously announced plan to build a grassroots chemical complex in the Dayawan Petrochemical Industrial Park in Huizhou, Guangdong Province, China.

Intended to help meet China’s ongoing demand growth for performance chemical products, the planned multibillion-dollar petrochemical complex will produce performance polymers used in packaging, automotive, agricultural, and consumer products for hygiene and personal care, ExxonMobil said in a Nov. 8 release.

Aimed at supporting China’s national petrochemical development priorities—which include self-sufficiency, diversified feedstock sources, and advancement of new competitive technology—the greenfield complex also will feature technologies to improve the site’s overall efficiency, according to the operator.

Processing units planned for the new complex include:

  • A 1.6-million tonnes/year (tpy) flexible-feed steam cracker.
  • Three performance polyethylene lines.
  • Two differentiated performance polypropylene lines.

While ExxonMobil confirmed construction on the greenfield project is already under way, the operator did not reveal a definitive timeline for targeted commissioning.

Official confirmation of FID on the proposed Guangdong petrochemical project follows ExxonMobil’s initial 2018 announcement that it was in discussions with the provincial government to build the complex which, at the time, was to house a 1.2-million tpy ethylene flexible-feed steam cracker, in addition to the two performance polyethylene lines and two differentiated performance polypropylene lines.

ExxonMobil said the Guangdong complex now comes as part of the operator’s prioritization of near-term capital investments on advantaged assets with the highest potential value and ability to generate attractive shareholder returns, which includes investments on chemical projects to expand production of high-value performance products by 60% by 2027.

ExxonMobil’s total investment in the Guangdong petrochemical complex—the first large-scale petrochemical project to be built in China by a wholly-owned US company—amounts to about $10 billion, the government of China said in a release on Apr. 22, 2020.

Alongside announcing FID for the Guangdong complex, ExxonMobil also confirmed its joint venture with Saudi Arabian Basic Industries Corp. (SABIC), Gulf Coast Growth Ventures LLC (GCGV), continues to progress with startup of its 1.8-million tpy ethane cracking complex in Portland, San Patricio County, Tex., near Corpus Christi (OGJ Online, July 26, 2021).

GCGV’s Corpus Christi complex remains on schedule for full commissioning by the end of fourth-quarter 2021.

Big West Oil lets contract for unit revamp at Utah refinery

FJ Management Inc. subsidiary Big West Oil LLC has let a contract to Honeywell UOP LLC to deliver technology for the conversion of an existing hydrofluoric acid (HF) alkylation unit at its 33,000-b/d refinery in North Salt Lake City, Utah, into an alkylation unit based on ionic liquids alkylation technology.

As part of the contract, Honeywell UOP will license the Chevron USA Inc.-developed ISOALKY alkylation technology that uses a nonaqueous liquid salt, or ionic liquid, instead of HF or sulfuric acids as a liquid alkylation catalyst to produce a high-octane alkylate blending component for production of clean-burning fuels, the service provider said on Nov. 11.

Alongside representing a key component of Big West Oil’s Tier 3 solution to deliver low-sulfur gasoline to the Utah market, the planned unit revamp also will improve the refinery’s operational efficiency, according to Mike Swanson, president of Big West Oil’s refining division.

Honeywell UOP disclosed neither a value of the contract nor a timeframe for completion of the proposed unit revamp.

Announcement of Big West Oil’s HF-to-ISOALKY alkylation unit conversion project follows startup of the first commercial-scale HF-to-ISOALKY unit revamp earlier this year at nearby Chevron Corp.’s 58,000-b/d Salt Lake City refinery.

Suitable for existing unit retrofits or new units, ISOALKY technology affords refiners process safety, performance, and economic advantages compared to conventional liquid acid alkylation technologies, as ionic liquids have strong acid properties that allow them to produce alkylate without the volatility of conventional acids, providing for simpler handling procedures.

Additionally, ionic liquids are regenerated on-site, eliminating any need for road or marine transportation for offsite regeneration and polymer byproduct handling.


GIP to sell Freeport LNG interest to JERA Americas for $2.5 billion

Global Infrastructure Partners (GIP) agreed to sell its 25.7% interest in Freeport LNG Development LP to JERA Americas Inc., the US-based subsidiary of JERA Co. Inc., for $2.5 billion. Global Infrastructure Partners II acquired the stake in 2015.

JERA, through its subsidiaries, owns 25% of Freeport LNG Train 1 and purchases and transports 2.32 million tonnes per year (tpy) of LNG for use in Japan and other LNG importing countries.

Freeport owns and operates an LNG export facility on Quintana Island, near Freeport, Tex. In May 2020, Freeport completed construction on the third of its three liquefaction trains, which together produce over 15 million tpy and are underpinned by long-term contracts.

Freeport is in the process of pursuing multiple growth opportunities, including a fully permitted, shovel-ready Train 4 expansion (OGJ Online, June 30, 2017).

Woodside sells 49% stake in Pluto Train 2 LNG project

Woodside Petroleum Ltd. is selling a 49% nonoperating participating interest in the 5-million tonne/year Pluto Train 2 joint venture to Global Infrastructure Partners (GIP). Pluto Train 2 is part of Woodside’s Scarborough offshore development and includes a new LNG train to be built at the existing Pluto LNG onshore site, with the first cargo expected to ship 2026.

Completion of the deal is subject to conditions including final investment decisions (FID) for the Pluto Train 2 and Scarborough developments. Woodside is expected to take Scarborough FID on Dec. 15, 2021. The company received nearshore environmental approval for the project earlier this year (OGJ Online, Aug. 12, 2021).

Following completion Woodside will hold a 51% participating interest in the Pluto Train 2 joint venture and remain as operator. Pluto Train 2 development is expected to be supported by a long-term processing and services agreement between the Pluto Train 2 and Scarborough joint ventures.

Woodside expects Pluto Train 2 to cost US$5.6 billion. In addition to its 49% share of capital expenditure, the joint venture arrangements require GIP to fund an additional $835 million. Woodside’s joint venture capital contributions will be reduced accordingly. Woodside and GIP also signed a project commitment agreement (PCA) as the part of the deal. The PCA includes provisions for GIP to be compensated for exposure to additional Scope 1 emissions liabilities above agreed baselines, and to sell its 49% interest back to Woodside if the status of key regulatory approvals materially changes.

The effective date of the sale is Oct. 1, 2021, and completion is expected January 2022.

Pluto LNG is an integrated offshore and onshore LNG plant near Karratha in the northwest of Western Australia. The first cargo from Pluto Train 1 was delivered in 2012. Expansion of Pluto LNG will include the construction of Pluto Train 2, associated infrastructure, and modifications to Pluto Train 1 to allow it to process Scarborough gas. Woodside is targeting emissions reductions of 30% by 2030 and net zero by 2050 at Pluto LNG, including Pluto Train 2 and the proposed development of the Scarborough gas resource.