OGJ Newsletter

Oct. 11, 2021


OPEC+ sticks to gradual monthly supply hikes

The Organization of the Petroleum Exporting Countries, Russia, and other allies (OPEC+) agreed Oct. 4 to stick to the

existing agreement to increase oil production by 400,000 b/d in November.

Crude oil price jumped higher on the news. West Texas Intermediate (WTI) crude jumped as much as 3.3% to $78.38/bbl in New York, the highest in almost 7 years. Brent crude roared above $81/bbl, reaching 3-year highs and intensifying inflationary pressures in the global economy.

The crude oil market has tightened sharply as the economy recovers from the pandemic and supply from the US Gulf of Mexico was disrupted by Hurricane Ida. Soaring natural gas prices have also raised the prospects for increased demand for oil products for power generation.

At the time of the agreement, OPEC+ seemed to control the oil market to a large extent. High oil prices have not prompted a supply surge from competitors. US shale producers aren’t investing enough to raise output. According to the oil trader Vidor Group, the cartel’s production policy will be the main factor affecting prices in the coming months.

OPEC+ ministers will meet again on Nov. 4.

Cabot-Cimarex combine: Coterra Energy

Coterra Energy Inc. is the name of the company formed through combination of Cabot Oil & Gas Corp. and Cimarex Energy Co. (OGJ Online, May 24, 2021).

Cabot disclosed the new name in an announcement about completion of the merger of companies.

Coterra holds over 700,000 net acres across Marcellus, Permian, and Anadarko basins and a combined production base of about 605,000 boe/d as of second-quarter 2021.

IPR eyes operatorship, working interest in Egypt concessions

IPR Lake Qarun Petroleum Co., a wholly owned subsidiary of IPR Energy AG, entered into conditional agreements to acquire 55% working interest and operatorship of the El Fayum and North Beni Suef concessions onshore Egypt from Pharos Energy PLC.

Consideration implies a gross value of up to $115 million for the assets and consists of $5 million cash at completion of the transaction, funding of the Pharos Group’s retained interest share of the cost of future activities on the assets for $38.425 million net (subject to working capital and interim period adjustments from the economic effective date of July 1, 2020), and contingent consideration of up to $20 million dependent on Brent oil prices in each calendar year from 2022 to 2025.

First-half 2021 net production from the fields is 3,718 b/d of oil. Full-year 2021 net production guidance was revised to 3,200-3,500 b/d of oil from 4,000–4,400 b/d of oil due to operational delays and the drive mechanism being primary depletion only (steep declines) until the main waterflood secondary recovery program is operational, Pharos said in a Sept. 15 investor presentation.

Plans in place to accelerate production enhancement in second-half 2021 include a second workover rig operating since end August, and recommencement of development drilling operations via a 3-well interim program approved by the board in mid-August. One drilling rig is being contracted and the first well is expected to spud in October, according to the presentation.

IPR has been present in Egypt for 40 years, currently with eight concessions and operating five (onshore and offshore) and active in all four key producing regions (Western Desert, Nile Delta, Gulf of Suez, and Eastern Desert).

Deal completion is expected in first-quarter 2022.

 Exploration & Development Quick Takes

CNOOC discovers oil in Bohai

CNOOC Ltd. made an oil discovery at Kenli 10-2 in Bohai. The oilfield lies in Laizhou Bay Sag in Southern Bohai Bay, with an average water depth of about 15.7 m.

The main oil-bearing formation is in the lower member of Neogene Minghuazhen formation and the oil properties are conventional heavy oil. Discovery well Kenli 10-2-4 was drilled and completed at a depth of 1,520 m, and encountered oil pay zones with a total thickness of about 27 m. The appraisal well was tested to produce about 569 b/d of oil.

The discovery “marked the breakthrough in discovery of lithological oilfield with reserve of 100 million tons in the shallow depression zone of the Bohai oilfields, demonstrated the broad prospects for exploration of lithological structures in the Bohai, and has great significance as a guide for exploration in similar basins,” said Xu Changgui, general manager of the company’s exploration department, in a Sept. 30 release.

TotalEnergies’ Suriname appraisal deemed non-commercial

TotalEnergies SE encountered non-commercial quantities of hydrocarbons in Keskesi South-1, about 6.2 km from the discovery well Keskesi East-1 on Block 58, offshore Suriname.

“The first appraisal well at Keskesi was a substantial step-out designed to assess the southern extent of the feature,” said Tracey K. Henderson, senior vice-president for block partner APA Corp. in a release Sept. 29. “This location had the potential to confirm a very large resource in place if connected to the reservoir sands in the discovery well. However, suitable reservoir quality sands were not developed in the Campanian target at the Keskesi South-1 location. Data gathered from the well will be used to calibrate our geologic model and inform the next steps for Keskesi appraisal.”

The well has been plugged.

Maersk Developer has moved to the Sapakara South-1 well, where it will conduct a flow test of the previously announced appraisal success (OGJ Online, July 28, 2021). Following the completion of the Sapakara South-1 flow test, the exploration program will continue with the spud of the next exploration well targeting the Krabdagoe prospect just to the east of Keskesi. The Maersk Valiant is currently drilling Bonboni, the first exploration prospect in the northern portion of Block 58. Both rigs are operated by TotalEnergies.

TotalEnergies is the operator of Block 58 (50%) with APA Suriname holding the remaining 50%.

Black Sea installs topsides for Ana drilling campaign

Black Sea Oil & Gas SA (BSOG) installed the Ana platform for the Midia Gas Development (MGD) project, 120 km offshore in 70 m of water in the Romanian Black Sea, in anticipation of a drilling campaign in November.

Ana, the first offshore platform built and installed in Romania in the past 30 years, is a 3,000-tonne gas production platform consisting of a jacket that sits mainly underwater and a 3-decks topside above the water. Gas coming from Ana and Doina reservoirs is collected and measured on the platform, then delivered to the onshore gas treatment plant through a 121-km subsea and 4.5 km onshore pipeline. The platform holds minimum equipment and will be unmanned.

MGD consists of 5 offshore production wells (1 subsea well at Doina field and 4 platform wells at Ana field) and a subsea gas production system over the Doina well which will be connected through an 18-km pipeline with a new unmanned production platform over Ana field. A 126-km gas pipeline will link the Ana platform to shore and to a new onshore gas treatment plant in Corbu commune, Constanta County, with a capacity of 1 billion cu m/y, representing 10% of Romania’s consumption. Processed gas will be delivered into the NTS at the gas metering station to be found within the GTP.

Overall completion of the MGD project is currently at 70%.

BSOG is owned by Carlyle International Energy Partners and the European Bank for Reconstruction and Development. It is operator of the concession with 70% interest. Partners are Petro Ventures Resources SRL (20%) and Gas Plus Dacia SRL (10%).

 Drilling & Production Quick Takes

Lundin, partners start Solveig field production

Lundin Energy Norway AS produced first oil from Solveig field, 15 km south of Edvard Grieg in North Sea production license (PL) 359, on Sept. 30, 2021 (OGJ Online, Sept. 2, 2021).

Solveig Phase 1 development consists of a five well subsea tie-back to the Edvard Grieg platform with gross proved plus probable (2P) reserves of 57 MMboe and gross peak plateau production of 30,000 boe/d. The field will extend plateau production at Edvard Grieg, which has already been extended by 5 years to end 2023.

First oil has been delivered on schedule and in line with the budget estimate of $810 million gross. Breakeven oil price is below $20/boe.

Lundin Energy is operator of both PL359 (Solveig) and PL338 (Edvard Grieg) (65%) with partners OMV (Norge) AS (20%) and Wintershall Dea Norge AS (15%).

bp starts production at Matapal, Trinidad

bp Trinidad and Tobago LLC (bpTT) achieved first gas at its Matapal project, about 80 km off the southeast coast of Trinidad and about 8 km east of Juniper, in 163 m of water.

Matapal, bpTT’s second subsea development, is comprised of three wells which tie back into the existing Juniper platform via two 9 km flexible flowlines, minimizing development costs and associated carbon footprint.

Matapal will deliver gas into the Trinidad gas market from resources discovered by the Savannah exploration well, drilled in 2017. Initial production of 250-350 MMscfd is expected once all wells are fully ramped up.

Equinor’s Black Vulture appraisal well comes up dry

Equinor Energy AS did not encounter hydrocarbons in Black Vulture appraisal well 6507/3-14 in the Norwegian Sea. While too early to provide an updated resource estimate for the discovery, the well is expected to yield a reduced estimate, the Norwegian Petroleum Directorate said in a release Sept. 28.

Before well 6507/3-14 was drilled, the resource estimate for the discovery in the Lange formation was 0.4-4.4 million standard cu m of recoverable oil equivalents.

The main purpose of the well was to detect hydrocarbons in reservoir rocks from the Early Cretaceous Age (Lange formations) in the Black Vulture prospect in PL159 B.

The well was drilled by the West Hercules semisubmersible drilling rig in 368 m of water about 15 km southwest of Norne field in the northern part of the Norwegian Sea, and 200 km west of Sandnessjøen to a vertical depth of 3,384 m below sea level. It was terminated in the Lyr formation from the Early Cretaceous.

The 6507/3-13 oil and gas discovery (Black Vulture) was proven in 2019 in reservoir rocks from the Early Cretaceous (oil and gas in the Lange formation) and the Late Cretaceous (gas in the Lysing formation).

The appraisal well encountered the Lange formation, about 45 m thick, of which a total of 24 m was sandstone layers with moderate reservoir properties. Weak traces of petroleum were encountered. The well is classified as dry.

Formation tests were not conducted, but data acquisition has been carried out. The well will be permanently plugged and abandoned.

This is the fifth exploration well in production license 159 B. The license was carved out from PL 159 in 2004.

The drilling rig will now drill wildcat well 6407/1-9 in production license 939 in the Norwegian Sea for Equinor.

Equinor is operator of PL159B with 53%. Partners are DNO Norge AS (32%) and Ineos E&P Norge AS (15%).

Neptune begins Dugong Tail drilling campaign

Neptune Energy Norge AS spudded the Dugong Tail exploration well in PL 882, 120 km west of Florø, in the Norwegian sector of the North Sea.

The well is close to existing production facilities of Snorre field. Water depth is 320 m, and the reservoir lies at a depth of 3,200-3,500 m.

The drilling program comprises a main bore with the potential for sidetracks, should hydrocarbons be encountered. The well is being drilled by the Deepsea Yantai, a semisubmersible rig, owned by CIMC and operated by Odfjell Drilling.

A recent drill stem test (DST) of Dugong has been completed and is currently under evaluation.

Neptune Energy is operator at PL 882 (45%) with partners Petrolia NOCO AS (20%), Idemitsu Petroleum Norge AS (20%), and Concedo AS (15%).


Russian refinery lets contract for grassroots delayed coking complex

Surgutneftegas PJSC subsidiary LLC Kirishinefteorgsintez (KINEF) has let a contract to Lummus Technology LLC to supply equipment for construction of a new delayed coking complex at the operator’s 20.1-million tonnes/year (tpy) refinery in Kirishi, Leningradskaya Oblast, Russia.

As part of the contract, Lummus will design and supply two proprietary fired heaters for implementation in the new complex that will be used to convert heavy oil residues—which otherwise would end up in fuels—into valuable lighter products, the service provider said on Oct. 5.

This latest contract for the planned grassroots delayed coking complex complements KINEF’s previous award in 2018 to Chevron Lummus Global (CLG)—a Chevron USA Inc.-Lummus Technology JV—to license CLG’s proprietary delayed coking technology for the project, Lummus said.

Lummus did not reveal further details regarding either the equipment supply contract or the earlier technology award to CLG, which appears to have been publicly undisclosed until now.

While KINEF has yet to disclose proposed capacities or specific units to be included in the proposed delayed coking—or heavy oil residue refining—complex, Surgutneftegas confirmed in its latest annual report to investors that KINEF in 2020 began preparing for implementation of the project, which included completion of preliminary site works as well as selection of licensors.

In a separate release dated Dec. 31, 2020, Vadim Evseevich Somov—KINEF’s director general—said construction of the new complex would begin a new stage of technological development for the refinery, forming part of the operator’s ongoing and phased modernization of its refining processes to improve production quality, reduce operating costs, ensure health and safety, and protect the environment.

In December 2013, KINEF’s Kirishi refinery completed construction of a grassroots advanced oil refining complex (AORC) that has since allowed the manufacturing site to produce more than 2 million tpy of ultralow-sulfur Euro 5-quality diesel and kerosine, as well as an additional 600,000 tpy of feedstock for production of high-octane gasoline, according to the operator’s website.

Equipped with flexibility to operate for maximum production of diesel, kerosine, or both depending on market conditions, the AORC’s main unit—the atmospheric residue deep conversion plant—includes the following unit capacities:

  • Vacuum distillation, 4.9 million tpy.
  • Hydrocracking, 2,9 million tpy.
  • Visbreaking, 1.9 million tpy.
  • Hydrogen production, 112,000 tpy.

The AORC also includes a 570,000-tpy wastewater recovery and sour water stripping plant, as well as an associated 75,000-tpy Klaus sulfur recovery plant that produces granulated sulfur with a hydrogen sulfide content below 0.001%.

Meridian inks product offtake agreement for Davis refinery

Meridian Energy Group Inc. has entered an agreement with Love’s Travel Stops & Country Stores Inc. subsidiary Musket Corp. for the long-term offtake of transportation fuel production from Meridian’s 49,500-b/sd high-conversion Davis refinery now officially under construction in Belfield, Billings County, ND, in the heart of southwestern North Dakota’s Bakken shale region (OGJ Online, June 30, 2020).

As part of the late-September agreement, Musket will purchase, market, distribute, and resell the entirety of Davis’ diesel (360 million gal/year) and gasoline (280 million gal/year) production for an initial period of 10 years beginning upon startup of the refinery, Meridian said.

Alongside possible term extensions, the agreement provides for the parties to establish similar offtake arrangements between the companies for Meridian’s future refineries, which currently include proposed manufacturing sites in the Permian basin of West Texas and near the US domestic crude collection-marketing hub at Cushing, Okla. (OGJ Online, Apr. 1, 2020).

Meridian—which aims to have up to 350,000 b/sd of clean-tech refining capacity in operation in 5-10 years—already has initiated siting and prepermitting design works for both the Texas and Oklahoma refineries, according to the operator’s website.

Based on a modular design that will result in the refinery having total emissions of one-eighth of industry average and less than one-half of the industry’s GHG emissions, Meridian’s Davis plant, once in operation, will produce ultralow-sulfur diesel and premium gasoline from prolific crude feedstocks from the Bakken shale basin using a suite of advanced technologies licensed by Axens Group intended to maximize operational efficiencies while minimizing environmental impacts.

In an e-mail dated Sept. 27, Meridian said that, while it continues to make steady and methodical progress on the Davis refinery—most recently scheduled to enter commercial operation during fourth-quarter 2023 at an estimated overall cost of about $1 billion—the project has faced delays related to impacts of COVID-19 as well as now-resolved litigation matters.

Meridian confirmed it let a contract on June 12 to an unidentified service provider to deliver engineering, procurement, and construction (EPC) for the planned refinery’s crude distillation unit. The EPC agreement—which represents a substantial portion of the refinery’s total installed costs—includes an option to fold in EPC of remaining units at Davis as CDU design proceeds, the operator said.

While it has yet to identify a definitive startup date for the Davis refinery, Meridian said work on the project for the next several months will focus on detailed design as well as procurement and fabrication of modules.

Substantial construction activity at the site will resume in 2022, when Meridian will begin work on foundations and other subsurface elements, according to the operator.


Canada invokes 1977 treaty to keep Enbridge Line 5 open

The Canadian government has requested diplomatic negotiations with the US to keep Enbridge Inc.’s Line 5 crude and propane pipelines open in Michigan. Canada filed the request in federal court in the Western District of Michigan, the latest step in an ongoing dispute following Gov. Gretchen Whitmer’s November 2020 order that the 540,000-b/d system be shut due to concerns it could leak.

Enbridge and Michigan have been in mediation regarding the dispute. But this process has stalled, and Canada invoked a 1977 treaty in a request the court suspend its review of the order as a preemptive effort to keep the line open.

In her 2020 order, Whitmer said she was revoking Enbridge’s 1953 easement for the pipeline’s 4-mile crossing under the Straits of Mackinac. She gave the company until May 12, 2021, to shut the line down, but Enbridge has insisted she does not have the authority to force a closure and has kept it operating (OGJ Online, May 12, 2021).

Gov. Whitmer said she was “profoundly disappointed” by Canada’s decision and calling on Prime Minister Justin Trudeau to reverse his country’s invocation of the treaty. Whitmer added that she “remains confident Michigan will prevail in its legal efforts with respect to Line 5” and that she “will continue to fight to get the pipelines out of the water.”

Line 5 runs from Superior, Wisc., to Sarnia, Ont.

Tallgrass to implement real-time emissions detection, RSG certification

Tallgrass Energy and Project Canary have partnered in a project to make Tallgrass’ +1,700-mile Rockies Express pipeline (REX) the first interstate natural gas transmission pipeline in the US to implement real-time emissions detection and monitoring across all its compressor stations. The Payne Institute at Colorado School of Mines will partner with Project Canary to review and validate data.

REX will also be the first pipeline to differentiate carbon neutral transportation capacity from others along its system, according to the companies, enabling continued evolution of certified carbon-neutral gas services. The ability to differentiate between carbon-neutral and other system segments will be the first step toward tip-to-tip certification and tracking of gas molecules, including responsibly sourced gas (RSG) and renewable natural gas.

The bidirectional REX is one of the country’s largest natural gas header systems, with a total capacity of more than 4.4 bcfd, bringing gas to Midwestern markets from producing basins in both the Rockies and Appalachia. REX initially will dedicate specific capacity to moving certified RSG from Appalachian producers to the Midwest.

Project Canary will quantify emissions data, track progress, and certify Tallgrass’ operational and environmental performance. The certification process is expected to begin fourth-quarter 2021 and be completed by mid-2022.

REX became fully operational in 2009. It is owned by Tallgrass (75%) and Phillips 66 (25%).