OGJ Newsletter

Nov. 7, 2022
A roundup of General Interest, Exploration & Development, Drilling & Production, Processing, and Transportation news from around the industry.


GECF sees natural gas market tightness through 2025

The 24th Ministerial Meeting of the Gas Exporting Countries Forum (GECF) concluded that medium-term tightness will continue in the global natural gas market, easing only after 2025 when new projects start coming online. It also pinned the current supply-demand imbalance on a lack of investment since 2015 and noted “dramatic” changes in both market function and physical flows while cautioning against “politically driven” price caps and other attempts manage market dynamics.

GECF said that geopolitical tensions had exacerbated the supply-demand imbalance, with Europe becoming the preferred destination for LNG cargoes as its typical pipeline supplies dwindled in the wake of Russia’s invasion of Ukraine. But cautioned that “artificial intervention in market functioning can only aggravate market tightness, discourage investment, and be detrimental to producers and consumers alike.”

The meeting reaffirmed that natural gas “will play a pivotal role in sustainable development and in a just and inclusive energy transition.”

Forum members are Algeria, Bolivia, Egypt (this year’s meeting host), Equatorial Guinea, Iran, Qatar, Russia, Trinidad and Tobago, and Venezuela. The meeting was also attended by observers Angola, Azerbaijan, Iraq, Malaysia, Mozambique, and the UAE. The 25th GECF Ministerial Meeting will convene October 2023 in Malabo, Equatorial Guinea.

Equinor to supply Norwegian gas to Ørsted

Equinor has entered into an agreement with Ørsted to supply Norwegian gas to Denmark via the 10-billion cu m/year Baltic Pipe gas pipeline.

The agreement, which will run Jan. 1, 2023, to Apr. 1, 2024, is for total supplied gas volumes equating to 8 TWh, about one quarter of the expected total Danish gas consumption, Ørsted said in a release Oct. 27.

The agreement ensures a stable supply of Norwegian gas when Tyra field isn’t supplying gas to Denmark, said Søren Thygesen Blad, head of gas portfolio management, Ørsted.

With the deal, “we’ll have more than enough gas to meet the gas demand of our customers for the coming and next winter, enabling us to stock up our Danish gas storage facilities over the summer,” he continued.

With supplied gas from the deal with Equinor, plus production from INEOS-operated South Arne field and from biogas, Ørsted said it has more than covered the consumption of its own customers, which are business customers in Denmark and Sweden.

Alberta Carbon Grid gets go-ahead to evaluate potential CCUS site

TC Energy Corp. and Pembina Pipeline Corp. have agreed with the Government of Alberta to further evaluate a 900,000-hectare area of interest (AOI) for storing carbon from industrial emissions in Alberta as part of the Alberta Carbon Grid (ACG). The land is north of Fort Saskatchewan, Alta.

The AOI’s proven deep porous geological formations and scale make it what the companies describe as an ideal CO2 storage site. The evaluation agreement will allow ACG to further examine the site’s subsurface properties.

TC Energy says the agreement will allow the Alberta Carbon Grid to move forward into the next phase of Alberta’s carbon capture utilization and storage (CCUS) process. As an open-access system, ACG is intended to allow access to customers of all sizes and industries, including oil and gas producers, refineries, petrochemical plants, and agricultural manufacturers.

ACG, still in its planning and evaluation stages, will come online in phases. The first phase is the 10-million tonne/year (tpy) Alberta Industrial Heartland project. Beyond that, ACG intends to expand through multiple storage hubs to as much as 20 million tpy throughout Alberta (OGJ Online, June 17, 2021).

 Exploration & Development Quick Takes

ExxonMobil makes two new discoveries offshore Guyana

ExxonMobil discovered oil at Sailfin-1 and Yarrow-1 wells in Stabroek block offshore Guyana, the company and partner Hess Corp. said in separate releases Oct. 26. Over 30 discoveries have been made by the operator on the block since 2015. The discoveries add to the block’s previously announced gross discovered recoverable resource estimate of about 11 billion boe.

Sailfin-1 encountered 312 ft (95 m) of hydrocarbon-bearing sandstone and was drilled in 4,616 ft (1,407 m) of water. It lies about 15 miles (24 km) southeast of the Turbot-1 discovery.

Yarrow-1 well encountered about 75 ft (23 m) of hydrocarbon-bearing sandstone and was drilled in 3,560 ft (1,085 m) of water. It lies about 9 miles (14 km) southeast of the Barreleye-1 discovery.

Both were drilled by the Stena Carron drillship.

Drilled earlier in the third quarter was the Banjo-1 exploration well. It did not not encounter commercial quantities of hydrocarbons, Hess said.

ExxonMobil’s first two sanctioned offshore Guyana projects, Liza Phase 1 and Liza Phase 2, are now producing above design capacity and achieved an average of nearly 360,000 b/d of oil in third-quarter 2022. A third project, Payara, is expected to start-up by end-2023, and a fourth project, Yellowtail, is expected to start-up in 2025 through the ONE GUYANA FPSO with production capacity of about 250,000 gross b/d of oil. The operator is currently pursuing environmental authorization for a fifth project, Uaru. A plan of development is expected to be submitted to the Government of Guyana before yearend. The development is expected to come online at end 2026 with a gross production capacity of about 250,000 b/d of oil, Hess said.

By the end of the decade, ExxonMobil expects Guyana’s oil production capacity to reach more than 1 MMboe/d.

Guyana’s Stabroek block is 6.6 million acres (26,800 sq km). ExxonMobil affiliate Esso Exploration and Production Guyana Ltd. is operator with 45% interest. Hess Guyana Exploration Ltd. holds 30% interest, and CNOOC Petroleum Guyana Ltd. holds 25% interest.

Petrobras, partners discover oil in Brazil’s Sépia field

Petrobras discovered oil in the northwestern part of Sépia oil field in Santos basin in water depths of about 2,000 m off the coast of Rio de Janeiro, Brazil.

Well 4-BRSA-1386D-RJS (the Pedunculo well) spudded late July. The oil-bearing interval was verified by electrical logs and fluid samples, which will be further characterized by laboratory analyses, Petrobras said in a release Oct. 31. The net oil column is one of the thickest ever recorded in Brazil, the company said.

Partners will continue operations to characterize the conditions of the discovered reservoirs and verify the extent of the discovery by conducting well tests.

This discovery lies within the Sépia co-participated area, which covers the Sépia Transfer of Rights (ToR) contract (Petrobras, 100%) and the Sepia ToR Surplus production sharing contract awarded in December 2021 to Petrobras (30%), TotalEnergies (28%), QatarEnergy (21%) and Petronas (21%), with Pre-Sal Petróleo SA as manager.

The Sépia co-participated area is operated by Petrobras, with a stake of 51.9%. TotalEnergies holds 19.2% net interest, alongside QatarEnergy (14.4%) and Petronas (14.4%). The Sépia shared reservoir is currently producing 170,000 b/d of oil.

The Sepia shared reservoir is currently producing about 170,000 b/d of oil.

Eni to farm out Sharjah Emirate exploration interest to PTTEP

Eni subsidiary Eni Sharjah BV has agreed to farm out a 25% interest in Sharjah Onshore Area A, an exploration block of the Sharjah Emirate in United Arab Emirates (UAE), to PTT Exploration and Production Public Co. Ltd. (PTTEP).

The deal, with PTTEP MENA Ltd., is expected to close by yearend subject to conditions and government approvals, PTTEP said in a release Oct. 26. Upon closing, participating interest of the 437-sq km Sharjah Onshore Area A will comprise Eni Sharjah BV (operator) 50%, Sharjah National Oil Corp. 25%, and PTTEP MENA 25%.

The investment is PTTEP’s fifth project in the UAE after entering in 2019. PTTEP holds interests in Abu Dhabi Offshore 1, Abu Dhabi Offshore 2, and Abu Dhabi Offshore 3, plus Sharjah Onshore Area C. All are in the exploration phase and in partnership with Eni. In August, Eni and PTTEP noted discovery of gas resources in the Abu Dhabi Offshore 2.

Equinor drills dry well near Norwegian Sea Norne field

Equinor Energy AS will plug exploration Norwegian Sea well 6607/12-5. The well is dry, with traces of gas, the Norwegian Petroleum Directorate said in a release Oct. 26.

The exploration well, the first in production license 943, was drilled about 18 km west of Norne field and 220 km west of Sandnessjøen by the Deepsea Stavanger semisubmersible drilling rig in 370 m water depth to a vertical depth of 3,861 m subsea. It was terminated in the Lange formation in the Early Cretaceous.

The objective was to prove petroleum in Cretaceous reservoir rocks in the Lange and Lysing formations, as well as to evaluate reservoir properties. The well encountered reservoir rocks of about 67 m thickness in the Cromer Knoll group, consisting of sandstones with interbedded silt- and claystones with poor to no reservoir quality.

The well was not formation-tested, but extensive data collection has been performed.

Equinor is operator of the license with 30% interest. Partners are DNO Norge AS (30%), Sval Energi AS (30%), and Aker BP ASA (10%).

The rig will now drill well 6507/8-11 S in Norwegian Sea production license 124 in, where Equinor is operator.

 Drilling & Production Quick Takes

Energean reaches first gas from Karish, offshore Israel

Energean plc has reached first gas at Karish field, offshore Israel. Gas is being produced from the Karish Main-02 well where the flow of gas is being ramped up, the company said in a release Oct. 26.

Karish Main-01 and Karish Main-03 wells are expected to be on line in about 2 and 4 weeks, respectively.

The Energean Power FPSO and the sales gas pipeline have an ultimate capacity of 8 billion cu m/year (bcmy), the company said. Commercial gas sales are expected to reach initial capacity up to 6.5 bcmy in about 4-6 months following first gas.

The Karish North development, the second oil train and the second export riser, are on track for completion in late 2023, following which Energean will be able to produce up to full 8 bcmy capacity.

ShaMaran commissions new Sarsang production plant

ShaMaran Petroleum Corp., Vancouver, has commissioned a 25,000 bo/d production plant and the start of oil export via pipeline in Sarsang block in the Kurdistan region of Iraq.

Production was expected to exceed 20,000 bo/d by end-October.

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 is comprised of two producing oil fields: Swara Tika and East Swara Tika. Each field contains three independent Triassic oil reservoirs.

Magnolia increases quarterly production 10%

Magnolia Oil & Gas Corp., Houston, reported third-quarter production of 81,500 boe/d, a quarterly record for the company, representing a 21% increase compared with the prior-year quarter, and a 10% increase over second-quarter 2022, the company said in a release Nov. 1.

Total volumes, 7% ahead of the high end the company’s production guidance, were the result of stronger-than-expected well performance in Giddings and Karnes asset areas.

The company continues to operate two drilling rigs and expects to maintain this level of activity through 2023. One rig will continue to drill multi-well development pads in the Giddings area, and a second rig will drill a mix of wells in both the Karnes and Giddings areas, including some appraisal wells in Giddings, said Chris Stavros, president, and chief executive officer.

The company estimates fourth-quarter 2022 production of 77,000-79,000 boe/d, “as most of the wells in our program are expected to come online toward the latter part of the quarter,” Stavros said.

Drilling and completions capital of $125-140 million in fourth-quarter 2022 is expected due to a higher number of well completions and higher anticipated non-op activity that should result in yearend total production at a level that exceeds the third-quarter production, he said.

In 2023, the company plans to operate two drilling rigs and one completion crew and expects the capital program and activity levels to deliver full-year 2023 production growth of about 10% compared to 2022 levels.

Magnolia has operations primarily in South Texas in the Eagle Ford shale and Austin Chalk formations.


Federated Co-operatives adding renewable fuels plant at Saskatchewan refinery

Federated Co-operatives Ltd. (FCL) has let a contract to Topsøe AS to deliver process technology for a grassroots plant designed to produce low-carbon renewable diesel at its 130,000-b/d Co-op Refinery Complex (CRC) in Regina, Sask., Canada.

As part of the Oct. 26 contract, Topsøe will license its proprietary HydroFlex process technology to enable the proposed plant’s processing of canola oil into 15,000 b/d of renewable diesel, the service provider said.

To be part of the larger integrated agriculture complex (IAC) planned by FCL’s joint venture with AGT Food and Ingredients Inc. (AGT Foods)—which will include a canola-crushing plant—the renewable diesel plant supports FCL’s broader transition to a future low-carbon economy, said Gil Le Dressay, FCL’s vice-president of manufacturing.

If approved, the new renewable diesel plant is scheduled to enter production in 2027, according to Topsøe.

A value of the technology licensing contract was not revealed.

The contract follows FCL’s November 2021 notice to members that it secured a $5.48-million (Can.) land option from Regina’s city council to purchase property north of the CRC specifically for construction of the renewable diesel plant.

Securing of the land option was to enable FCL to begin formally assessing the project from a feasibility, engineering, and regulatory standpoint ahead of reaching final investment decision (FID) on the project, the operator said.

Formation of the partnership with AGT Foods followed in early 2022 with the companies’ entrance into a memorandum of understanding (MOU) under which FCL (51%) and AGT Foods (49%) plan to build the IAC as part of the operators’ shared goals of decarbonizing the Western Canadian economy while supporting regional crop production, FCL said in a Jan. 17 release.

As part of the MOU, the IAC’s $360-million canola crushing plant will supply about 50% of required feedstock for the proposed renewable diesel complex, which will source its remaining plant-based feedstock requirements from other regional canola crushing plants.

Alongside its $2-billion investment in construction of the IAC, FCL also signed an MOU with Whitecap Resources Inc. under which FCL plans to fund, build, and operate plants at the CRC and Co-op Ethanol Complex near Belle Plaine, Sask., to capture nearly 500,000 tonnes/year (tpy) of carbon dioxide (CO2) emissions for transport, storage, and use at the nearby Whitecap-operated Weyburn unit, which is currently the world’s largest carbon capture, utilization, and storage (CCUS) project, according to a late-October 2022 release from the companies.

In its latest annual report to members, FCL said it expects carbon capture at CEC to begin in 2024, with startup of carbon capture at CRC to follow in 2026.

Marathon Petroleum reiterates Martinez Renewables guidance, posts net income of $4.5 billion

The Martinez Renewables Fuels project (MRF), a joint venture of Marathon Petroleum Corp.  and Neste to transform the now-idled Martinez, Calif., refinery into a renewable fuels production site, remains on track to reach mechanical completion by yearend.

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.

Marathon noted the unchanged project guidance as part of its third-quarter 2022 report.

The company reported net income of $4.5 billion for third-quarter 2022, compared with net income of $694 million for the same period in 2021.

Adjusted net income was $3.9 billion for the quarter. This compares to adjusted net income of $464 million for third-quarter 2021. Adjusted results for third-quarter 2022 exclude net pre-tax benefits of about $1 billion and for third-quarter 2021 exclude pre-tax charges of $48 million.

The refining and marketing had adjusted EBITDA of $5.5 billion in the quarter, versus $1.2 billion for third-quarter 2021. Segment adjusted EBITDA excludes refining planned turnaround costs, which totaled $384 million in third-quarter 2022 and $205 million in third-quarter 2021. The increase in segment adjusted EBITDA was driven by higher margins and volumes.

Crude capacity utilization was about 98%, resulting in total throughput of 3 million b/d for third-quarter 2022. Crude capacity utilization in third-quarter 2021 was about 93%, which resulted in total throughput of 2.8 million b/d.


QatarEnergy selects ConocoPhillips as third, final international NFS expansion partner

QatarEnergy selected ConocoPhillips as its third and final international partner in the 16-million tonne/year (tpy) North Field South (NFS) expansion project comprised of two 8-million tpy liquefaction trains. The project is expected to raise Qatar’s total LNG production capacity to 126 million tpy.

ConocoPhillips will hold an effective net participating interest of 6.25% out of a 25% interest available for international partners, QatarEnergy said in a release Oct. 31. QatarEnergy will hold the remaining 75% interest.

The North Field Expansion Project, comprising NFS and the North Field East (NFE) expansion projects, will start production in 2026 and will add more than 48 million tpy to the world’s LNG supplies by 2027, QatarEnergy said.

QatarEnergy selected TotalEnergies SE as the first international partner in the NFS project in September and Shell plc as the second partner in October (OGJ Online, Sept. 26, 2022; Oct. 23, 2022).

Transco get positive FERC draft EIS on Southside Reliability project

Transcontinental Gas Pipe Line Co. LLC (Transco) received a draft environmental impact statement (EIS) for its 423-MMcfd Southside Reliability Enhancement Project from the US Federal Energy Regulatory Commission (FERC). Transco proposes to build and operate one new 33,000-hp compressor station and modify two existing compressor stations and three existing meter stations in North Carolina and Virginia. 

The project would provide expanded year-round firm transportation capacity from Transco’s Compressor Station 165 and the Pine Needle Storage site along the mainline pipeline system to delivery points in North Carolina. 

FERC staff concluded that construction and operation of the project would result in limited adverse environmental impacts, most of which would be temporary (during construction) or short-term (returning to background levels within 3 years following construction). Some permanent impacts, though not significant according to FERC, would occur from project operation. Project effects would be reduced to less than significant levels by proper mitigation, minimization, and avoidance measures and adherence to FERC recommendations, except for climate change impacts that were not characterized in this EIS as significant or insignificant.

The draft EIS addresses the potential environmental effects of:

  • Installation of a new compressor station (Compressor Station 168) which includes one new 33,000-hp electric motor-driven compressor unit, and installation of new mainline valves on South Virginia Lateral A-Line and B-Line at the new station in Mecklenburg County, Va.
  • Addition of one 16,000-hp electric motor-driven compressor unit at existing Compressor Station 166 in Pittsylvania County, Va.
  • Installation of piping modifications to allow for flow reversal at existing Compressor Station 155 in Davidson County, NC.
  • Replacement of one meter run to increase delivery volumes at the existing Ahoskie Meter Station in Hertford County, NC.
  • Installation of new equipment to increase delivery volumes at the existing Pleasant Hill Meter Station in Northampton County, NC.
  • Upgrading meter and controls and debottleneck piping at the existing Iredell Meter Station in Iredell County, NC.

FERC commissioners will take into consideration staff’s recommendations when they make a decision on the project. The draft EIS comment period closes Dec. 12, 2022.