OGJ Newsletter

Sept. 13, 2021


Enerplus agrees to sell certain Williston basin assets

Enerplus Corp., Calgary, has agreed to sell its interests in Sleeping Giant field (Montana) and Russian Creek area (North Dakota) in the Williston basin for $115 million to an undisclosed buyer.

In addition, Enerplus will receive up to $5 million in contingent payments if the WTI oil price averages over $65/bbl in 2022 and over $60/bbl in 2023.

The sale consists of the company’s interests in the developed Sleeping Giant field in Montana and the southernmost portion of Enerplus’ North Dakota position in the Russian Creek area. The Interests do not include any future drilling locations in Enerplus’ identified Williston basin drilling inventory.

Enerplus’ working interest production from the interests averaged 3,000 boe/d (77% crude oil and natural gas liquids) in second-quarter 2021 and includes 244 net wells. Estimated 2022 net operating income associated with the interests is $22 million based on a $60 WTI oil price.

With the sale, the company expects to both accelerate debt reduction and direct about 10% of the sale proceeds to incremental share repurchases. Debt reduction of $400 million is targeted by the end of first-quarter 2022 based on the current commodity price environment, the company said.

The sale is expected to close by end October, subject to customary closing conditions.

Sound Energy closes Schlumberger deal to add Morocco interests

UK-based Sound Energy PLC has closed a deal to acquire the entire issued share capital of Schlumberger Silk Route Services Ltd. (SSRS) from Schlumberger Holdings II Ltd. The deal, according to a September 2021 investor presentation, makes Sound Energy the largest onshore operator in Morocco.

SSRS holds a 27.5% participating interest in the Anoual and Greater Tendrara exploration permits in eastern Morocco, together with a 27.5% indirect interest in the Tendrara concession through its contractual relationship with the group. Sound Energy now controls operated working interests of 75% in the exploration permits and in the concession.

In the 8,853-sq km Anoual, two main gas prone plays have been identified beneath the regional salt seal: the Triassic TAGI and underlying Paleozoic formations, both of which are extensions of oil and gas plays established across the border in Algeria, Sound Energy noted on its website. In 2020, Sound Energy renegotiated the permit terms amending the work program having already completed the commitment to acquire FTG aerogradiometry and 600 km of 2D seismic by end 2018 (OGJ Online, July 7, 2020). ONHYM holds the remaining 25% interest in the license area.

Eight wells have been drilled in the 14,411-sq km greater Tendrara permit, and the company is working to advance monetizing the 377 bcf, 2C (100%) gas resource through a phased development, the company noted the September investor presentation.

Completion of the deal with Schlumberger, coupled with a recent 10-year take or pay offtake agreement with Afriquia Gaz, advances progression toward a final investment decision for its scalable, Phase 1 micro LNG project, said Graham Lyon, executive chairman, Sound Energy, in an Aug. 31 release (OGJ Online, Feb. 17, 2020).

Shell assumes interest, operatorship of blocks offshore South Africa

BG International, a Royal Dutch Shell PLC subsidiary, is operator of the Transkei & Algoa exploration right (Exploration Right 12/3/252) with a 50% interest following the close of a deal with Impact Oil & Gas Ltd. subsidiary Impact Africa Ltd.

The blocks cover about 45,838 sq km offshore eastern South Africa in water depths up to 3,000 m.

The license was initially awarded to Impact Africa as a technical cooperation permit in 2012, followed by an application for an exploration right, which was granted in 2014.

The South African government has granted a second renewal period of the license for a 2-year exploration period which began in August. Shell and Impact will proceed with the acquisition of about 6,000 sq km of 3D seismic in 2022.

Shell is operator in Transkei & Algoa with 50% interest. Impact Africa holds the remaining 50%.

 Exploration & Development Quick Takes

Eni eyes fast track of oil discovery offshore Ivory Coast

Eni SPA will begin studies for fast-track development of a “major” oil discovery in Block CI-101 offshore Ivory Coast and plans an evaluation program to assess area upside potential in the area.

After more than 20 years of industry exploration in the country’s deep waters without a commercial discovery, the Baleine-1x successfully tested a new play concept in the sedimentary basin in Ivory Coast, the company said in a Sept. 1 release.

The exploration well, the first by Eni in the country, was drilled with the Saipem 10,000 drill ship about 60 km off the coast in 1,200 m of water, positioned based on 3D seismic data and regional studies. The well reached total depth of 3,445 m in 30 days.

Wireline formation testing and fluid sampling proved the presence of light oil-bearing intervals (40° API) of Santonian and Cenomanian-Albian age. The lower Cenomanian-Albian level shows discrete to good reservoir characteristics and has been successfully tested to production, the company said.

The aim of the pending evaluation program is to assess upside of the overall structure that extends into the Eni-operated Block CI-802.

Baleine’s potential is estimated at 1.5-2.0 billion bbl oil in place and 1.8-2.4 tcf of associated gas.

Eni is operator of Block CI-101 (90%) with partner Petroci Holding (10%). Eni also holds a participating interest in other blocks in the Ivorian deep water: CI-205, CI-501, CI-504, and CI-802, all with partner Petroci Holding.

Aker BP to downgrade North Sea discovery estimate

Aker BP ASA expects to downgrade resource estimates of its 2019 North Sea Liatarnet (25/2-21) oil discovery after drilling appraisal well 25/2-22 S (OGJ Online, July 23, 2019).

While the operator’s resource estimate prior to the appraisal was 13-32 million std cu m recoverable oil, it is too early to give an updated discovery estimate, the company said in a Sept. 1 release.

The well, the tenth in production license (PL) 442, was drilled about 40 km northeast of Alvheim field in 111 m of water by the Deepsea Nordkapp drilling facility to 1,767 m vertical and 1,772 m measured depth below sea level. It was terminated in rocks from the Oligocene/Eocene age (the Hordaland group).

The primary exploration objective was to take liquid samples to clarify quality of the oil proven in the Skade formation in well 25/2-21. The secondary objective was to collect geological information on formation strengths and to prove the oil-water contact.

The well encountered 31 m within the same reservoir interval as well 25/2-21 with extremely good porosity and moderate permeability. The uppermost 5 m contain traces of oil. Estimated oil saturations and liquid samples collected in the reservoir interval indicate that the oil in the well cannot be produced. The oil-water contact was not encountered.

The well was not formation-tested, but extensive data acquisition and sampling have been carried out. The well has been plugged.

Deepsea Nordkapp will proceed to the Alvheim area to drill a development well in Aker BP-operated PL 150.

Aker BP is operator at PL 442 (90.26%) with partner LOTOS Exploration and Production Norge AS (9.74%).

Triangle review sets up new Perth basin leads, prospects

Triangle Energy Ltd., Perth, has finalized a review of prospects and leads in its 50%-owned onshore North Perth basin license L7 in Western Australia which surrounds the former Mt Horner oil field.

The review, undertaken following a January agreement with JV partner Key Petroleum Ltd. in which Triangle will acquire Key’s interest, confirmed up to 18 new oil prospects and four gas leads in the permit (OGJ Online, Jan. 29, 2021).

Work comprised a look at historical well results, including a petrophysical analysis and a study of Key’s previous mapping in the area.

Triangle will now move to a 100% interest in L7 and intends to evaluate the new prospects with a 3D seismic survey (Booker survey) to be run December 2021 into January 2022.

The Mt Horner-Booker Shelf region is a proven oil-prone part of the basin, Triangle said. New targets include low risk Mt Horner field infill wells and Jurassic exploration plays, moderate risk Wagina-Dongara formation exploration prospects, and higher risk Permian exploration.

The geological review confirmed a correlation of the Permian Kingia and High Cliff formation sandstone reservoirs in the permit which contain gas discoveries further south at Waitsia and West Erregulla fields, the company said.

Data acquired in the 3D seismic acquisition is expected to result in a multi-well exploration and appraisal program with potential to revive the Mt Horner surrounds as an oil producing area.

 Drilling & Production Quick Takes

CNOOC starts production at Luda 6-2

CNOOC Ltd. has started production at Luda 6-2 oil field ahead of schedule.

Luda 6-2 lies in Liaodong Bay of Bohai Sea, with average water depth of about 30 m. The project includes full utilization of existing processing facilities of Suizhong 36-1 oilfield and construction of a new central platform.

A total of 38 development wells are planned, including 29 production wells, 8 water injection wells, and 1 development and appraisal well. The project is expected to reach peak production of about 10,000 b/d of crude oil in 2022.

CNOOC is operator of the field with 100% interest.

Canacol to tie in Aguas Vivas 3 well in Colombia

Canacol Energy Ltd. will tie in production from the Argus Vivas 3 appraisal well and integrate drilling results of both Aguas Vivas 2 and 3 appraisals with existing 3D seismic to better define both the gas accumulation at Aguas Vivas and additional development locations for future drilling.

Argus Vivas 3 encountered 378 ft true vertical depth net gas pay with 22% average porosity within the Cienega de Oro (CDO) sandstone reservoir in the Magdalena basin of northwestern Colombia. The well was spudded on Aug. 11 and reached 8,000 ft measured depth on Aug. 17.

Upon completion and production tie in of Aguas Vivas 3, Canacol will mobilize the rig to drill the San Marcos exploration well which will further target gas within the CDO sandstone reservoir. Canacol expects drilling and completion to take about 4 weeks.

The wells are part of the company’s 2021 drilling program in which it expects to drill 12 wells (9 exploration, 3 development), all operated with 100% working interest (OGJ Online May 7, 2021).

Midland-Petro, Andros Capital close Permian drilling JV

Midland-Petro DC Partners LLC (MPDC), Midland, and Andros Capital Partners LLC, Houston, have closed a joint venture under which Andros affiliate Andros Permian LLC will fund about $150 million to participate in a development drilling program targeting the Midland basin Spraberry and Wolfcamp formations in Midland County, Tex.

Serica increases Rhum production with Rhum R3 recompletion

Serica Energy PLC started production from the Rhum R3 well in the UK Northern North Sea (OGJ Online, June 10, 2021).

First production was achieved on Aug. 23 and work has since continued to optimize production rates from Bruce, Keith, and Rhum fields, the company said in a Sept. 2 release. Keith and Rhum fields are both tied back to the Bruce complex where they are transported and processed for export. Gas is exported via the Frigg pipeline to the St Fergus terminal and liquids are exported via the Forties Pipeline System.

The successful recompletion of R3 has increased Rhum production capacity. In the week following startup, gross Rhum production averaged over 190 MMscfd of gas and 1,400 b/d of condensate. Average gross production for Rhum field is now over 34,000 boe/d compared to a maximum rate of 26,000 boe/d immediately prior to commencement of R3 production.

Serica is operator at Rhum (50%) with partner National Iranian Oil Co. (50%).

The company’s next project will be Columbus gas-condensate field in the UK Central North Sea where it expects first production in this year’s fourth quarter, the company said.


IOC lets contract for Gujarat refinery expansion works

Indian Oil Corp. Ltd. (IOC) has let a contract to Chevron Lummus Global (CLG)—a Chevron USA Inc.-Lummus Technology JV—to license process technologies for units involved in the lube-petrochemical (Lupech) portion of its previously announced and long-planned project that will expand crude oil processing capacity of its 13.7 million-tonne/year (tpy) Koyali refinery at Vadodara in India’s western state of Gujarat (OGJ Online, Nov. 16, 2011).

As part of the early September contract, CLG will license proprietary technologies, equipment, and catalyst for a grassroots catalytic dewaxing unit and revamp of an existing hydrocracker as part of Lupech project, which aims to increase the refinery’s production of premium base oils to help reduce India’s reliance imports from abroad, CLG said.

Alongside equipping the new 270,000-tpy catalytic dewaxing unit with its two-step all-hydroprocessing technology to selectively concentrate and isomerize the molecular structure of wax into isoparaffins at high yields, CLG said it will modernize and expand the refinery’s existing 1.2-million tpy hydrocracker to produce 1.55 million tpy of feedstock for production of API Groups II and III base oils to meet increased market demand.

The latest contract follows IOC’s October 2020 approval of the Lupech element of its revised 178.25-billion rupee expansion and Lupech integration project to increase crude processing capacity of the Gujarat refinery by 4.3 million tpy to 18 million tpy as well as result in proposed production of 500,000 tpy of polypropylene and 235,000 tpy of lube oil base stock at the site (OGJ Online, Oct. 20, 2020).

Inclusion of the Lupech component comes as part of IOC’s strategy to create a building block for future production of niche chemicals with a potential to increase petrochemical and specialty products integration index on incremental crude throughput to improve margins, IOC said.

Designed to improve the refinery’s energy performance as well as its ability to meet growing regional demand for finished products, the expansion and reconfiguration project also aims to equip the plant with greater flexibility to weather future disruptions in the supply-demand scenario and more closely integrate its production with downstream petrochemical units (OGJ Online, Aug. 8, 2017).

IOC—which in 2020 completed its Bharat Stage (BS) 4 and BS 6-grade (equivalent to Euro 5 and Euro 6-quality) fuels to enable Gujarat to produce Bharat Stage (BS) 4 and BS 6-grade (equivalent to Euro 5 and Euro 6-quality) fuels in line with the Indian government’s Auto Fuel Policy 2025 calling for 100% BS 6-quality fuel production—now plans to fully commission the long-awaited expansion and accompanying BS 6 fuel upgrading projects at the refinery during 2024-25, the operator said in its recently released 2020-21 annual report to investors.

PETRONAS’ refining subsidiary lets contract for new treatment plant

PETRONAS Refinery & Petrochemical Corp. Sdn. Bhd. (PRPC) subsidiary PRPC Utilities and Facilities Sdn. Bhd. (PRPC U&F), through a contractor, has let a contract to VA Tech Wabag Ltd. to provide a suite of services for a new effluent treatment plant at its Pengerang Integrated Complex (PIC) in southeastern Johor, Malaysia, which houses the PETRONAS-Saudi Aramco 50-50 joint venture Pengerang Refining Co. Sdn. Bhd.’s (PRefChem) 300,000-b/d integrated refining and petrochemical complex (OGJ Online, Jan. 4, 2019).

As part of the $11.45-million contract awarded directly by Dialog E&C Sdn. Bhd., Wabag will license its proprietary water technology as well as deliver design, engineering, procurement, and supervision activities for the proposed ETP, which will consist of a two-stage biological treatment, advance oxidation process, ammonia stripper, and drier installation for sludge treatment, the service provider said in Sept. 6 filings to the National Stock Exchange of India Ltd. and BSE Ltd.

Wabag did not disclose additional details regarding the contract award, and further information regarding the ETP project remained unavailable from PETRONAS, Aramco, PRPC, PRefChem, and PRPC U&F.

Alongside the PIC refinery’s production of petroleum products such as low-sulfur jet fuel, gasoline, and diesel, the PIC includes a steam cracking complex that houses a cracker as well as methyl tertbutyl ether and benzene units that produce more than 3 million tonnes/year (tpy) of ethylene, propylene, butadiene, C4 olefins, and aromatics from a feedstock of propane, LPG, and naphtha delivered from the refinery. The PIC’s petrochemical complex also hosts polymer and glycols units equipped to produce 3.3 million tpy of polypropylene, linear low-density polyethylene, high-density polyethylene, monoethylene glycol, and diethylene glycol.


Enbridge buys Moda Ingleside crude export terminal

Enbridge Inc. has agreed to purchase the Moda Ingleside Energy Center (MIEC) and other assets from Moda Midstream LLC and EnCap Flatrock Midstream. MIEC, with an export capacity of 1.6-million b/d from Ingleside, Tex., is the largest crude export terminal by volume in the US, having loaded more than 25% of all US Gulf Coast crude exports in 2020, according to Moda. The companies expect the $3-billion transaction to close by end 2021.

MIEC has an aggregate storage capacity of more than 15 million bbl and can load very large crude carriers. It connects Permian and Eagle Ford production to international markets via direct connectivity to transmission pipelines including Plains All American Pipeline LP’s 390,000-b/d Cactus I and 670,000-b/d Cactus II pipelines, Phillips 66 Partners’ 900,000-b/d Gray Oak pipeline, the 600,000-b/d EPIC Crude Pipeline (expandable to 1-million b/d), and Harvest Midstream Co.’s 600,000-b/d Ingleside pipeline.

Other assets included in the transaction are Moda’s 350,000-bbl Taft storage terminal, near MIEC; a minority, non-operating interest in the Cactus II pipeline; a 100% interest in Moda’s 300,000-b/d Viola pipeline; and Moda’s St. James Development Project, a brownfield effort to build storage and terminal infrastructure near St. James, La. The St. James site is within the crude hub already established in the area with marine waterfront and pipeline connectivity. It includes one dock and room for a second, as much as 8 million bbl of permitted storage capacity with in-tank blending, and additional land available for expansion.

Moda and EnCap will retain ownership in Vopak Moda Houston, a deepwater terminal in the Port of Houston at Deer Park, Tex., the companies own with Royal Vopak. Vopak Moda Houston includes a rail loop and is capable of handling petrochemical and LPG feedstocks. It recently commissioned a Suezmax-scale dock and built storage and terminaling infrastructure for its industrial gas product line.

Colonial Pipeline restores service to refined product Lines 1, 2

Colonial Pipeline Co. restored service to refined product Lines 1 and 2 from Houston to Greensboro, NC, before midnight on Monday, Aug. 30. The lines were temporarily shut down on Sunday afternoon, Aug. 29, as a precautionary and routine safety measure in advance of Hurricane Ida making landfall off the coast of Louisiana (OGJ Online, Aug. 30, 2021).

After receiving clearance to enter the impacted areas, crews followed procedures to inspect the infrastructure for integrity and completed all restart protocols, the company said in an Aug. 31 release.

Despite partial shutdown, fuel supply continued to be available throughout the southeast from the numerous terminals located along the supply route.

Canacol to build new Colombian gas pipeline

Canacol Energy Ltd. has executed a long-term take-or-pay natural gas sales contract with Empresas Publicas de Medellin ESP (EPM) supporting a new 20-in., 300-km pipeline that will allow Canacol to sell up to 100 MMscfd into Colombia’s interior market. The pipeline will be expandable to 200 MMscfd if demand warrants.

Under the terms of the contract Canacol will deliver gas to EPM in Medellin starting Dec. 1, 2024, with an initial minimum volume of 21 MMscfd, escalating to 54 MMscfd on Dec. 1, 2025, and remaining at that level until the contract expires Nov. 30, 2035.

The pipeline will start at Canacol´s gas treatment plant in Jobo and run southward to Medellin.

Canacol expects by end first-quarter 2022 to have finalized work on the permits to submit to the National Authority of Environmental Licenses for approval; finalized selection of a company to build and operating the pipeline; arranged financing; and begun negotiations with consumers regarding an additional 45 MMscfd to fill the pipeline’s initial capacity.