OGJ Newsletter

Feb. 28, 2022
A roundup of General Interest, Exploration & Development, Drilling & Production, Processing, and Transportation news from around the industry.


Talos, EnLink to develop CCS project in Mississippi River corridor

Talos Energy Inc., Houston, and EnLink Midstream LLC executed a memorandum of understanding to jointly develop a complete CO2 capture, transportation, and sequestration system for industrial-scale emitters in Louisiana.

The offering is focused on one of the highest CO2 emitting regions in the US which emits about 80 million metric tonnes/year of CO2, the companies said in a joint statement Feb. 16. The Mississippi River corridor from New Orleans to Baton Rouge alone accounts for nearly two-thirds of the total industrial emissions in Louisiana. Emitting sources include ammonia, hydrogen, methanol, and base chemical facilities as well as refinery and other petrochemical infrastructure.

The service will use significant portions of EnLink’s existing regional pipeline infrastructure of about 4,000 miles in Louisiana and Talos’s recently acquired River Bend carbon capture and storage (CCS) site in east Louisiana.

EnLink and Talos have begun to market the offering to potential customers.

In a separate release Feb. 16, Talos detailed an agreement with a large landowner that will allow for multiple sequestration sites near EnLink’s existing pipelines. This agreement includes sequestration rights to about 26,000 surface acres in Iberville, St. James, Assumption, and Lafourche Parishes. The acreage comprises three strategically located sites along the Mississippi River industrial corridor known collectively as the River Bend CCS project.

Talos and EnLink believe the area provides the necessary structural geology and rock properties for CO2 sequestration, providing cumulative capacity of over 500 million metric tonnes. Talos has also secured a right of first refusal on about 63,000 additional acres in the area for phased, future expansion.

Talos will be the project manager and operator of the injection, storage, and monitoring and will be joined by its partner, Storegga Ltd.

EnLink has identified existing pipelines to be utilized for CO2 transportation from emissions sources in the Geismar, Donaldsonville, Plaquemine, and St. Charles areas in Louisiana.

Magnolia to continue two-rig program following year-over-year production increase

Magnolia Oil & Gas Corp., Houston, will continue a two-rig drilling program expected to generate high single digit full-year production growth following a 7% increase in year-over-year production after moving its Giddings asset in South Texas to full development.

The company provided the outlook as part of its full-year 2021 and fourth-quarter 2021 results Feb. 16.

One rig will continue to drill multi-well development pads in the Giddings area consisting primarily of wells with greater than 7,000-ft laterals and with four wells per pad. The second rig will drill a mix of wells in both the Karnes and Giddings areas of South Texas, including some appraisal wells in Giddings.

Production at Giddings field is expected to average about 40,000 boe/d during the year.

Based on the 2-rig drilling plan for full-year 2022, the company expects a drilling and completion capital budget of about $350 million.

For first-quarter 2022, the company expects drilling and completion capital of $85-90 million and total production to be about 70,000-72,000 boe/d.

Magnolia had fourth quarter and full-year 2021 net income attributable to Class A common stock of $150.2 million, and $417.3 million, respectively. Fourth-quarter and full-year 2021 total net income was $192.1 million and $559.7 million, respectively.

Net cash provided by operating activities was $260.5 million in the fourth quarter and $788.5 million for full-year 2021.

Total production in the fourth quarter grew 15% from fourth-quarter 2020 to 69,400 boe/d, a 3% sequential increase from third-quarter 2021 and growth of 15% from the prior year’s fourth quarter. Fourth quarter 2021 turn-in lines were more weighted to the Karnes area which resulted in a sequential quarterly production increase of 9% to 33,400 boe/d.

Production for full-year 2021 averaged 66,000 boe/d representing year-over-year volume growth of 7%.

Production at Giddings and other in the fourth quarter grew 27% compared to the prior year fourth quarter to 36,000 boe/d including year-over-year oil production growth of more than 40%.

TotalEnergies to farm out Greater Laggan Area interest

TotalEnergies SE has conditionally agreed to farm out a 20% interest in the Greater Laggan Area (GLA) producing gas fields and infrastructure alongside various interests in certain other exploration licenses, including a 25% interest in the Benriach prospect, to Kistos PLC.

Kistos will acquire 20% working interests in the producing Laggan, Tormore, Edradour, and Glenlivet gas fields, offshore the UK West of Shetland.

The acquisition includes a 20% interest in the undeveloped Glendronach gas field as well as a 25% interest in Block 206/4a, which contains the 638 bcf (operator’s P50 resource estimate) Benriach prospect.

Kistos expects production from the assets to average about 6,000 boe/d (net) during 2022 with 2P reserves as at the effective date of Jan. 1 of 6.2 MMboe (operator’s estimate).

Total consideration is $125 million and additional contingent cash payments. If the average day-ahead gas price at the National Balancing Point exceeds 150p/therm in 2022, up to $40 million will be payable in January 2023. Should Benriach be developed, Kistos will pay $0.25/MMBtu of net 2P reserves after first gas.

The deal is expected to close in second-quarter 2022 subject to customary regulatory and partner consents.

The producing GLA gas fields lie water depths of 300-625 m up to 125 km northwest of the Shetland Islands.

Development approval for GLA was granted in 2010 and first gas was achieved at Laggan and Tormore fields in 2016. Glenlivet and Edradour fields received development approval in 2015 and came on-stream in 2017.

Glendronach field was discovered in 2018 and it is anticipated that development will use existing infrastructure.

Produced gas is routed through two dedicated flowlines which surface at the purpose-built Shetland Gas Plant (SGP), where further processing is carried out prior to export to the St. Fergus Gas Terminal in Scotland.

Drilling & Production Quick Takes

TotalEnergies makes discovery offshore Suriname

TotalEnergies SE and partner APA Corp. discovered oil and associated gas at the Krabdagu-1 well in Block 58, offshore Suriname. Testing will be carried out to appraise the resources and productivity, while at least three additional exploration and appraisal wells are planned for the block this year.

The well was drilled by the Maersk Valiant 18 km southeast of Sapakara South to a depth of about 5,273 m in water depth of 780 m. The well was designed to test multiple stacked targets in Maastrichtian and Campanian intervals and encountered approximately 90 m of net oil pay in good quality reservoirs.

Drilling and logging operations will continue, using the Maersk Valiant drillship.

The discovery follows previous finds at Maka, Sapakara, Kwaskwasi, and Keskesi, as well as the successful test of the Sapakara South-1 appraisal well.

The well “confirms our geologic and geophysical models and de-risks additional prospects we have matured in the area,” said Tracey Henderson, senior vice-president, exploration, APA Corp.

The discovery is a step toward achieving APA’s first FID in the block, said John J. Christmann IV, APA’s chief exploration officer and president.

While the rig is on location, TotalEnergies will progress with drill stem and other wellbore testing to assess the resource potential and productivity of two primary reservoirs.

TotalEnergies is operator (50%) with partner APA Corp. (50%).

Frontera, CGX JV to focus on Corentyne block, offshore Guyana

Frontera Energy Corp. will focus on exploration in Corentyne block, offshore Guyana, and not drill the Demerara block in 2022, as previously announced, due to positive results at the Kawa-1 exploration well.

Kawa-1 early-stage wireline logging results confirm the logging while drilling (LWD) indications previously disclosed Jan. 31, with a total of 200 ft of net pay encountered at multiple depths (OGJ Online Feb. 1, 2022). Further analyses of logs and samples are ongoing.

Frontera is majority shareholder of CGX Energy Inc. and joint venture partner with CGX in the block (OGJ Online, Dec. 11, 2018). The joint venture is in discussions with the Government of Guyana regarding Demerara block and will provide an update when a conclusion has been reached.

Strike flows gas at South Erregulla Perth basin wildcat

Strike Energy Ltd. reported strong gas flows to surface from the Wagina sandstone reservoir in its South Erregulla-1 (SE-1) wildcat in permit EP503 in the North Perth basin of Western Australia.

The Wagina was encountered at 4,072 m in the intermediate section of the well and appears to be made up of thick, clean sand units with elevated mud gas readings recorded.

A drilling break at 4,174 m coincided with a gas break that resulted in prolonged gas flaring at the surface.

Live logging while drilling data suggests it is a conventional gas-charged reservoir similar to nearby Beharra Springs field, the company said.

So far, SE-1 has correlated closely with the stratigraphy of West Erregulla gas field in adjoining Strike-operated EP469. SE-1 lies less than 5 km south of the nearest successful West Erregulla well.

Strike is gathering pressure data and samples via a wireline program before it finalizes its petrophysical analysis to assess the significance of the results so far.

The well will continue drilling down to the primary target of the Kingia sandstone.

Strike is operator of EP503 with 100% interest.

SE-1 is expected to encounter the Kingia target at a shallower depth than at West Erregulla-2 and the company plans to collect whole core and an advanced series of wireline logs across the Kingia sandstones.

If gas is encountered, the reservoir will be flow tested and potentially completed as a future producer.

The primary objective of SE-1 and any subsequent appraisal wells is to delineate around 350 petajoules of high confidence resource to secure the gas requirements for Strike’s proposed 1.4 million tonnes/year Project Haber urea manufacturing facility.

Drilling & Production Quick Takes

bp starts up Herschel expansion in Gulf of Mexico

bp completed start-up of the Herschel expansion project in the US Gulf of Mexico, providing infrastructure for future well tie-in opportunities and advancing the operator’s goal to increase production from the area to 400,000 boe/d by the mid-2020s.

The expansion is the first of four major projects scheduled to be delivered globally this year.

Herschel expansion lies in Mississippi Canyon block 520, southeast of the bp-operated Na Kika platform in about 6,700 ft of water.

Phase 1 of the Herschel expansion project comprises development of a new subsea production system and the first of up to three wells tied to Na Kika platform. At its peak, this first well is expected to increase platform annual gross production by an estimated 10,600 boe/d.

The bp-operated well, drilled to a depth of about 19,000 ft, lies southeast of the platform, about 140 miles off the coast of New Orleans, La.

bp and Shell each hold a 50% working interest in Herschel development.

bp operates four production platforms in the deepwater Gulf of Mexico—Thunder Horse, Atlantis, Mad Dog, and Na Kika—with a fifth platform, Argos, expected to come online in 2022.

Laredo to maintain flat production with front-loaded 2022 budget, activity

Laredo Petroleum Inc, Tulsa, Okla., expects a total capital expenditure budget in 2022 of $520 million to maintain flat activity levels versus 2021. The budget includes about $20 million for non-operated activity and about $10 million for ESG focused investments, the company said Feb. 22.

Oil production is expected to remain flat with fourth-quarter 2021 levels with expected full-year oil production growth of 24 -34% versus 2021, driven primarily by production acquired in second-half 2021.

With rig and completions crew count flat with 2021, activity and capital levels are front-end loaded with the year’s highest level of investment occurring in first-quarter 2022. The Permian basin-focused company plans to operate three drilling rigs and two completions crews for much of the quarter. Laredo plans to release one drilling rig and one completions crew by the end of the first quarter and operate a constant two drilling rigs and one completions crew for the remainder of the year.

The year’s development plan is focused entirely on oil-weighted Howard County, Tex. inventory. Efficiencies are expected to further improve with 18 15,000-ft wells in the 2022 plan and average lateral length increasing about 18% to 11,800 ft.

The company estimates full-year 2022 production of 82,000-86,000 boe/d with oil production of 39,500-42,500 b/d.

In fourth-quarter 2021, the company produced 41,080 b/d of oil and 85,240 boe/d, an increase of 87% and 3%, respectively, versus fourth-quarter 2020. Oil cut as a percentage of total production was increased to 48% in fourth-quarter 2021 versus 27% in fourth-quarter 2020.

In September 2021, the company agreed to acquire about 20,000 net acres in western Glasscock County, Tex., from Pioneer Natural Resources Co. for $230 million.

The company expects to return cash to shareholders by early 2023.


MMEX advances West Texas integrated refining, hydrogen complex

MMEX Resources Corp. has gained regulatory approval to move forward with its modified plan to build what will now be an integrated ultralow-sulfur fuels refining and hydrogen production complex equipped with carbon capture in Pecos County, Tex., near the Sulfur Junction spur of the Texas Pacifico railroad, about 20 miles northeast of Fort Stockton.

The Texas Commission on Environmental Quality (TCEQ) on Feb. 18 approved the operator’s plan to build and operate the proposed solar-powered UltraClean refining complex with carbon capture, MMEX said on Feb. 22.

With TCEQ’s approval and 100% of the project’s front-end engineering and design (FEED) package now completed, MMEX will now move forward with planned financing and commercial arrangements for the complex, according to Jack W. Hanks, MMEX’s president and chief executive officer.

The operator already has signed letters of intent with an unidentified international trading company to supply crude oil and purchase finished products from the planned refinery, Hanks said.

Previously slated to produce 10,000 b/d of ultralow-sulfur diesel and gasoline from West Texas light crudes using proprietary UltraClean technology licensed by Polaris—which will also act as engineering, procurement, and construction (EPC) contractor on the project—the Pecos County complex now will be able to produce 11,600 b/d of fuels following revisions to the process design to enable additional crude flexibility, according to a July 29, 2021, release from MMEX.

Designed to become the world’s first oil refinery to fully capture carbon dioxide (CO2) emissions, the 450-acre complex will be equipped with carbon-capture technology licensed by BASF SE from its proprietary OASE technology portfolio, MMEX confirmed in a December 2021 release.

The project site will additionally include the capability to produce up to 50 tonnes/day of green hydrogen using Siemens AG subsidiary Siemens Energy AG’s proprietary Silyzer 300 electrolyser technology, as well as an installation able to produce 60 tonnes/day of blue hydrogen via steam-methane reforming and hydrogen liquefaction, the operator said in late-August 2021.

MMEX said in August 2021 it also had entered a contract to buy another 632 acres of nearby land for construction of a solar power complex that will power the refining, green hydrogen, and blue hydrogen installations.

While MMEX’s website confirms the modularly-based project will enable an expedited construction period of 15-18 months, a definitive timeline for the project’s completion has yet to be disclosed.

MMEX said the revised Pecos County UltraClean project comes as an interim step in its move to clean energy production ahead of the broader transition to a hydrogen economy.

Aramco inks supply, offtake deal with proposed Egyptian integrated complex

Saudi Aramco’s Aramco Trading Co. (ATC) has executed a long-term, nonbinding agreement to supply 100,000 b/d of Arabian crude oil to Red Sea National Petrochemicals Co.’s (RSNPC) grassroots integrated refining and petrochemicals complex to be built on the Gulf of Suez at the Suez Canal Economic Zone (SCZone) in Ain Sokhna, Suez Province, Egypt, east of Cairo (OGJ Online, May 5, 2021).

Alongside its supply of crude to RSNPC, ATC said the Feb. 15 agreement also contains an offtake provision under which Aramco will be able to purchase RSNPC’s production of refined and petrochemical products, including polymers and olefins.

While ATC did not reveal specific details regarding either the duration of the agreement or the grades of crudes to be delivered, ATC Chairman Mohammed Y. Al Qahtani the agreement aligns with Aramco’s strategy to maximize liquid-to-chemical conversion, as well as its commitment to support continued development of Egypt’s oil and gas resources.

Once completed, RSNPC’s integrated complex will have a liquid-to-chemical conversion rate of about 60-70%, according to ATC.

To be built on 3.56 million sq m within the SCZone’s southern sector in line with the Egyptian government’s plan to help meet increased demand for transportation fuels and petrochemical products in Egypt’s domestic market as well as create opportunity for exports abroad, RSNPC’s proposed $7.5-billion Ain Sokhna complex is a project under the downstream pillar of Egypt’s Ministry of Petroleum & Mineral Resources’ (MOPMR) petroleum sector modernization program (PSMP) to help transform Egypt into a strategic and sustainable hub for global oil and gas trade.

According to the latest update from state-owned Egyptian Petrochemicals Holding Co. (ECHEM), RSNPC’s complex will process about 4 million tonnes/year (tpy) of crude oil to produce 2.8 million tpy of petrochemical products and 930,000 tpy of high-quality petroleum products that include: polypropylene, polyethylene, terephthalic acid, benzene, polyethylene terephthalate, paraxylene, monoethylene glycol, diethylene glycol, jet fuel, and low-sulfur fuel oil.

With major execution of engineering, procurement, and construction (EPC) to be delivered by Bechtel Corp. and a memorandum of understanding for front-end engineering design (FEED) now signed with Bechtel, Engineering Co. for Petroleum & Chemical Industries (ENPPI), and Petroleum Projects & Technical Consultation Co. (Petrojet), securing of major permits and approvals for the project is now under way, according to ECHEM.

Contracts for the complex’s process design package (PDP) and technology licensing also are nearing completion, official project updates from ECHEM show.

According to the latest update from MOPMR, RSNPC’s planned complex is scheduled to be completed by year-

end 2024.


ConocoPhillips gains additional interest in Australia Pacific LNG

ConocoPhillips closed a deal to acquire an additional 10% interest in Australia Pacific LNG (APLNG) from Origin Energy Ltd. for $1.645 billion. After customary closing adjustments, cash paid for the additional interest is about $1.4 billion.

The project, in Gladstone, Queensland, has nameplate capacity of 9 million tonnes/year and supplies LNG to long-term buyers in both China and Japan. It is currently the largest supplier of natural gas to Australia’s East coast domestic market, meeting over 30% of its total demand.

ConocoPhillips’ full-year 2021 production from APLNG was 113,000 boe/d and full-year 2021 financial distributions were about $750 million.

Both companies retain their existing seats on the APLNG board. Origin remains upstream operator of the project,

responsible for the upstream exploration, development, and production activities. ConocoPhillips operates the downstream LNG export infrastructure and the LNG export sales business.

In December 2021, ConocoPhillips’ Australian subsidiary notified Origin Energy that it would exercise its preemption right to purchase up to an additional 10% shareholding interest in APLNG following EIG’s attempt to acquire 10% interest in the project (OGJ Online, Oct. 25, 2021; Dec. 8, 2021). That deal received approval from the Australian Foreign Investment Review Board but was subject to the waiving of preemptive rights by ConocoPhillips and Sinopec.

The APLNG joint venture shareholders now comprise ConocoPhillips (47.5%), Origin (27.5%) and Sinopec (25%).

Trans Mountain adds $7 billion to expansion project budget, expects late-2023 completion

Trans Mountain Corp. has entered the second half of the Trans Mountain expansion project, while also increasing the cost to C$21.4 billion (US$16.9 billion) from C$12.6 billion (US$9.9 billion) and extending the completion date.

Mechanical completion of the expansion—expected to transport an additional 590,000 b/d of Western Canadian crude oil between Edmonton, Alta., and Burnaby, BC for a total system post-expansion capacity of 890,000 b/d—has been pushed out to third-quarter 2023 from late 2022.

The cost increase includes the all known project enhancements, changes, delays and financing, including impacts of the COVID-19 pandemic, and the preliminary impacts of the November 2021 British Columbia floods in the Hope, Coquihalla, and Fraser Valley areas, the company said in a statement Feb. 18.

Originally planned by Kinder Morgan in 2014, construction on the project was estimated to cost $5.4 billion (OGJ Online, Dec. 13, 2013). In May 2018, Kinder Morgan Canada Ltd. agreed to sell the project to the Canadian government for $4.5 billion (OGJ Online, May 29, 2018).

The largest project in the pipeline’s history, the expansion project it involves installing about 980 km of new pipeline, new and modified infrastructure including pump stations and terminals, and a new dock complex at the Westridge Marine Terminal in Burnaby, BC.

Targa Resources to sell 25% stake in Gulf Coast Express pipeline

Targa Resources Corp. has executed agreements to sell its wholly-owned subsidiary that holds a 25% equity interest in the Gulf Coast Express pipeline (GCX) to an undisclosed buyer for $857 million.

Targa expects to receive the full proceeds from the sale in second-quarter 2022 following a customary call right period in favor of the other members of GCX.

Kinder Morgan Texas Pipeline LLC (KMTP), DCP Midstream LP, and an affiliate of Targa Resources Corp. built the 2-bcfd Gulf Coast Express Pipeline project, the mainline of which consists of roughly 82 miles of 36-in. OD pipeline and 365 miles of 42-in. pipeline starting at the Waha Hub near Coyanosa, Tex., in the Permian basin and ending near Agua Dulce, Tex. GCX’s Midland Lateral includes about 50 miles of 36-in. pipeline and associated compression, connecting with the GCX mainline.

The $1.7-billion project started full commercial operation in September 2019 (OGJ Online, Sept. 25, 2019).

Earlier this year, Targa Resources executed agreements to repurchase interests in its development company joint ventures from Stonepeak Partners LP for about $925 million. With that deal, pro forma, Targa owns 75% interest in its Grand Prix NGL pipeline, 100% of its Train 6 fractionator in Mont Belvieu, Tex., and a 25% equity interest in the Gulf Coast Express pipeline.