OGJ Newsletter

GENERAL INTEREST Quick Takes

Russia to cut oil output by 500,000 b/d in March

Russia will cut oil output by 500,000 b/d in March, Russian Deputy Prime Minister Alexander Novak said Feb. 10. The news follows the G7 price cap as well as western countries’ bans on Moscow’s crude oil and petroleum products respectively implemented in December and February.

The cut, equivalent to 5% of Russian output, is about 0.5% of world supply.

“We will not sell oil to those who directly or indirectly adhere to the principles of the price ceiling,” Alexander Novak said in a statement. “In relation to this, Russia will voluntarily reduce production by 500,000 b/d in March. This will contribute to the restoration of market relations.”

Novak noted that the production cut doesn’t apply to gas condensate and will be calculated based on actual production levels rather than Russia’s quota in the OPEC+ production deal. Russia’s decision was made without consultation with the OPEC+ alliance.

Biden administration to sell 26 million bbl SPR crude

The Biden administration plans to sell 26 million bbl of crude oil from the Strategic Petroleum Reserve (SPR), which Congress had mandated in previous years.

The sale could push reserves down below their current level of about 372 million bbl to 345 million bbl, the lowest level since 1983. Bids for the oil are due to expire on Feb. 28, and the oil will be delivered between Apr. 1 and June 30, the US Department of Energy (DOE) said.

The department had considered canceling the fiscal year 2023 sale of the 26 million bbl after the Biden administration sold a record 180 million bbl from SPR last year. But such a cancellation would have required action by Congress.

DOE said it is implementing a three-part strategy to replenish long-term reserves, including buybacks with revenues from emergency sales, returns from prior exchanges, and working with Congress to avoid “unnecessary sales unrelated to supply disruptions,” to strategically maintain volume.

Last year, Congress canceled about 140 million bbl of SPR sales scheduled for fiscal years 2024 through 2027, after a DOE proposal to stop them.

Vital Energy makes Midland basin acquisition

Vital Energy Inc. (formerly Laredo Petroleum Inc.), Tulsa, Okla., signed an agreement to acquire Permian basin assets of Driftwood Energy Operating LLC, inclusive of all leasehold interests and hedges, in exchange for about 1.58 million shares of Vital common stock and $127.6 million of cash (total consideration of about $215 million). 

The southern Midland basin assets, primarily in Upton County, Texas, extend Vital Energy’s oil-weighted inventory with an added estimated 30 gross (23 net) operated horizontal locations in the Wolflcamp B, including four fross (four net) drilled but uncompleted locations, the company said in a release Feb. 14.

The deal includes about 16,500 gross (11,200 net) acres in Upton and Reagan counties, Texas, (about 91% held by production). Current production from the assets is about 5,400 boe/d (63% oil).

The transaction is expected to close early April 2023.

Exploration & Development Quick Takes

Shell discovers hydrocarbons at Pensacola prospect

Shell UK Ltd. discovered oil and gas in license P2252 in the Pensacola prospect, northwest of Breagh gas field in the Zechstein Reef play fairway, Southern North Sea, according to license partner Deltic Energy. 

Well 41/05a-2 reached a total depth of 1,965 m true vertical depth subsea (TVDSS), encountered the top Hauptdolomite reservoir at 1,745 m TVDSS, and confirmed a reservoir thickness of 18.8 m with better-than-expected porosity averaging 16%, Deltic said in a release Feb. 8. Presence of mobile gas and oil in the primary Zechstein Hauptdolomite carbonate target interval was confirmed via wireline logs.

The well penetrated the edge of the Pensacola structure in a down dip location and has proven a substantial hydrocarbon column. Post acidization, the well flowed gas at peak rates of about 4.75 MMscfd, declining to 1.75 MMscfd after 12 hours of test. These results are in-line with Deltic’s pre-test expectations based on the reservoir parameters derived from the well, it said.

Located down dip, the flow rates observed during the well test are not expected to be representative of those of potential future production wells which would likely target the central part of the structure and are expected to generate higher rates.

Light oil with a preliminary gravity of 34-36° API was also produced at a rate of about 18 b/d during the well test. The potential of this oil with respect to the Pensacola opportunity is yet to be determined.

Based on data collected during drilling and testing, the Pensacola discovery is now estimated to contain P50 EUR of 302 bcf (P90 to P10 range = 164-519 bcf). Following completion of the well test program, the well will be plugged and the Noble Resilient drilling rig will be demobilized.

Shell is operator of the license with 65% interest. Partners are Deltic (30%) and ONE-Dyas BV (5%).

Vår Energi discovers oil near Hammerfest

Vår Energi ASA plans to drill a sidetrack well to better define the size of a new Barents Sea oil discovery. The company discovered oil in the 7122/8-1S Countach well in production license (PL) 229 (Goliat) northwest of Hammerfest.

The well is currently drilled to 2,958 m measured depth. Oil has been encountered in Realgrunnen and Kobbe formations.

Extensive data is being collected for further assessment.

Vår Energi is the operator (65%) with partner Equinor Energy AS (35%).

Aker BP makes non-commercial discovery in Central North Sea

Aker BP ASA discovered oil in the Central North Sea, but initial assessments show the discovery is not currently profitable, the Norwegian Petroleum Directorate reported Feb. 10.

Wildcat well 25/10-17 S was drilled by the Scarabeo 8 rig 12 km north of Ivar Aasen field and 187 km southwest of Haugesund in 116 m of water. Preliminary estimates place the size of the discovery at 0.5-1.4 million std cu m of recoverable oil equivalent.

The well, the first exploration in production license (PL) 867/B, was drilled to a vertical depth of 4,057 m subsea. It was terminated in the Skagerrak formation in the Upper Triassic in the Hugin reservoir.

The primary exploration target was to prove petroleum in Middle Jurassic reservoir rocks in the Hugin and Sleipner formations (OGJ Online, Jan. 13, 2023). The secondary exploration target was to prove petroleum in the Skagerrak formation from the Triassic.

The well encountered a 3-m oil column in the Hugin formation totaling 98 m, 80 m of which was sandstone of moderate reservoir quality. The oil-water contact was encountered at 3,654 m subsea. In addition, residual oil was encountered both over and under the oil column in the Hugin and Sleipner formations. The Skagerrak formation was water-bearing.

The well was not formation-tested, but data acquisition and sampling were carried out. The well will now be permanently plugged.

Scarabeo 8 will now drill wildcat well 16/1-25 S in PL 1141 in the North Sea, where Aker BP is operator.

Aker BP is operator at PL 867/B with 80% interest. Lime Petroleum holds 20%.

Drilling & Production Quick Takes

TotalEnergies, APA continue Sapakara South test, results add ‘substantial’ resources

TotalEnergies and APA Corp. are advancing work to drill two appraisal wells at the Krabdagu discovery following a successful flow test at nearby Sapakara South in Block 58, offshore Suriname, APA said in a release Feb. 8.

Sapakara South-2 (SPS-2) appraisal well, the second to test the previously reported discovery, encountered about 36 m (118 ft) of net oil pay in high-quality Campano-Maastrichtian reservoir, APA said. Data collected from the flow test and subsequent pressure build-up indicated incremental connected resource of more than 200 million bbl of oil in place.

SPS-2 lies about 4.6 km (3 miles) south of the Sapakara South-1 (SPS-1) appraisal well.

“Results from the SPS-2 drilling and flow tests are consistent with our pre-drill expectations, confirm our geologic, geophysical, and reservoir models, and, importantly, add substantial resources towards a potential development,” said John J. Christmann IV, APA chief executive officer and president.

Tests on the Krabdagu discovery, which lies about 17 km (11 miles) east of Sapakara are ongoing. Krabdagu-2 is currently drilling, and APA anticipates Krabdagu-3 will spud in February with a second drilling rig.

TotalEnergies is operator of Block 58 with 50% interest. APA Suriname holds a 50% working interest.

Frontera resumes Colombia operations, protest blockade lifted

Frontera Energy Corp. has resumed operations at Quifa and CPE-6 blocks in Colombia. Operations had been halted due to blockades by protesters on the road from Puerto Gaitán to the Rubiales village in the municipality of Puerto Gaitan, Meta Department, Colombia, that have been resolved, the company said in a release Feb. 8.

The company has resumed transporting on-site inventory, rotating crews, and delivering supplies to its Quifa and CPE-6 operations, and expects a return to pre-blockade production levels by late February or early March.

In a separate release Feb. 6, the company said it had reached its on-site storage capacity at the blocks and had shut-in about 11,500 boe/d of net production, suspending all construction and drilling activities in the area.

At that time, Frontera said hydrocarbon companies that operate in the area, including Ecopetrol, Hocol, Tecpetrol, and Cepsa, expressed concerns about the blockade that, at the time, had lasted 7 days and prevented the collective from producing over 49,500 b/d of oil.

Vår Energi reduces production at Balder

Vår Energi ASA has temporarily reduced production from Balder field in the central part of the North Sea by about 9,000 b/d, partner Mime Petroleum AS said in a release Feb. 10.

The precautionary measure follows a potential integrity concern associated with a riser identified through the operator’s monitoring systems. Ongoing inspection and analysis will determine when production can be resumed.

A riser change is scheduled for 2023, and measures are being investigated to accelerate the timeline. 

Balder field has been developed with subsea wells tied-back to the Balder production, storage, and offloading vessel (FPSO). The Ringhorne deposit, 9 km north of the FPSO, is included in the Balder complex. The field is developed with a platform with initial processing and water injection capabilities. Production of oil and gas is routed to the Balder FPSO for final processing, storage, and export.

Vår Energi is operator of Balder and Ringhorne with 90% working interest. Mime Petroleum holds the remaining 10%.

Vintage commissioning Vali field infrastructure

Vintage Energy Ltd., Adelaide, operator of Vali gas field joint venture (JV) in Cooper basin of southwest Queensland, started commissioning gas production infrastructure at Vali-1 in preparation for startup.

Discovered in 2020 and assessed as containing 101 petajoules of 2P reserves, the field is being connected over the state border to the South Australian Cooper basin gas gathering system.

The project includes installation of metering infrastructure at the field, including separation, installation of flowlines connecting the field’s three completed wells to the metering installation, and twin export gas pipelines from the field to tie into the Moomba gas gathering network at nearby Beckler gas field.

Wells will be connected and brought online progressively.

First gas from Vali-1 is expected by end-February. Vali-2 and Vali-3 commissioning is expected in early March.

Vintage has 50% interest and operatorship. Metgasco Ltd. and Bridgeport (Cooper Basin) Pty Ltd. each hold 25% interest.

PROCESSING Quick Takes

New Fortress Energy lets contract for FLNG projects

New Fortress Energy Inc. has let a contract to Honeywell UOP LLC to provide a suite of natural gas processing technologies for the operator’s Fast LNG projects currently under development in North America (OGJ Online, Nov. 4, 2022).

As part of the early February contract, Honeywell UOP will license a series of its proprietary technologies aimed at removing various contaminants from natural gas before its subsequent liquefaction at the Fast LNG (FLNG) projects, each of which will include a nominal 1.4-million tonne/year (tpy) LNG gas treating and liquefaction plant, the service provider said.

Alongside enabling critical removal of impurities from natural gas, implementation of the ready-now technology will allow the FLNG plants to increase throughput volumes all while reducing utility consumption, said Bryan Glover, president of Honeywell UOP.

While UOP did not respond to OGJ inquiries regarding the locations at which the technologies will be implemented, New Fortress is currently developing five FLNG units in the US and Mexico, the first of which is under modular construction for installation offshore Altamira, Tamaulipas, Mexico, following its targeted mechanical completion in March 2023, according to the operator’s website.

According to an investor presentation, New Fortress plans to complete an additional four FLNG units—consisting of modular liquefaction and processing equipment designed to be placed on fixed platforms, jack-up rigs, or semi-submersible rigs—by mid-2024, including two for installation offshore Louisiana; one 70 km off the coast of Veracruz, southeastern Mexico, including 1.1-tcf Lakach deepwater natural gas field; and another offshore Altamira.

KazMunayGas executing repairs at Atyrau refinery

Kazakhstan’s state-owned JSC NC KazMunayGas (KMG) subsidiary ANPZ LLP is in the process of repairing the fluid catalytic cracker (FCC) at its 100,000-b/d Atyrau refinery following the unit’s unplanned shutdown in early February.

As of Feb. 7, a specially created operational headquarters at the refinery was managing repair and restoration works on the FCC with support from specialists of Axens SA, which licensed the unit’s catalytic cracking process technology, ANPZ and KMG said.

Based on results of an inspection of the unit carried out by Axens, ANPZ said it expects to complete all necessary repair work by Feb. 18, with preliminary startup activities at the cracker scheduled to run from Feb. 18 through Feb. 22.

Official restart of the unit is planned for Feb. 23.

ANPZ initiated an unscheduled shutdown of the catalytic cracker on Feb. 1 following an increase in the temperature profile of the unit’s regenerators, ANPZ and KMG said on Feb. 3.

Following the Feb. 1 incident, KMG confirmed terminating Rakhimzhan Zhangabylov, ANPZ’s first deputy general director, as well as issuing a reprimand to Murat Dosmuratov, the refinery’s general director.

Magzum Mirzagaliyev, chairman of KazMunayGas, also called for a special response team—led by Arman Kairdenov, deputy chairman of KMG’s refining and petrochemicals management board—to investigate the incident and make further refinery personnel decisions based on results of the investigation.

During the FCC outage, Mirzagaliyev has instructed Kazakhstan’s three refineries—including the Atyrau refinery, POCR LLP’s 120,000-b/d Pavlodar refinery, and PetroKazakhstan’s 120,000-bd Shymkent refinery—to maximize capacity utilization to ensure sufficient output of light petroleum products to meet regional demand and prevent a national fuel deficit.

Before the Feb. 1 unit shutdown, ANPZ most recently was forced to halt operations of Atyrau’s catalytic cracker and associated installations from Jan. 10-11 amid a shortage of free LPG storage space resulting from untimely LPG truck pickups from regional gas network companies under a distribution schedule administered by Kazakhstan’s Ministry of Energy, ANPZ said.

While ANPZ confirmed restart of the FCC and related process units on Jan. 11, the operator said the temporary outage reduced the refinery’s normal output of:

• 500 tonnes/day of LPG to 20 tonnes/day.
• 6,000 tonnes/day of motor gasoline to 1,500 tonnes/day.
• 4,000 tonnes/day of diesel to 2,000 tonnes/day.

Petrobras updates LUBNOR refinery sale progress

Petrobras is awaiting approval from regulators on its contract for sale of its 10,400-b/d Lubrificantes e Derivados de Petróleo do Nordeste (LUBNOR) refinery in Fortaleza, Ceará, Brazil.

On Feb. 8, the court of Brazilian regulators the Administrative Council for Economic Defense (CADE) approved an order from councilors requesting additional time for analysis of the operator’s proposed sale of LUBNOR, Petrobras said.

While it did not reveal a timeframe for the proposed additional review period, Petrobras said it must now await CADE’s final decision on planned sale.

The update on the proposed LUBNOR divestment follows a deal Petrobras signed in May 2022 under which Grepar Participações Ltda.—jointly owned by Grecor Investimentos em Participações Societárias Ltda., Greca Distribuidora de Asfaltos Ltda. and Holding GV Participações SA—agreed to acquire Petrobras’s ownership interest the LUBNOR refinery and associated logistics assets for an overall purchase price of $34 million.

One of Brazil’s leading asphalt production plants and the country’s only refinery equipped to produce naphthenic lubricants, LUBNOR processes ultra-heavy Brazilian crude oil from Espírito Santo basin and the Ceará cluster.

The sales processes is governed by a 2019 agreement governing the operator’s program to divest most of its Brazilian refining and related logistics assets, as well as the opening of Brazil’s refining sector to increased competitiveness and transparency.

As part of its portfolio management strategy, Petrobras will concentrate investments on assets with lower greenhouse gas emissions that have proved competitive over the years.

TRANSPORTATION Quick Takes

TC Energy: Bending stress, weld flaw caused Keystone oil spill

TC Energy Corp. said that the Dec. 7, 2022, leak from its 622,000-b/d Keystone crude oil pipeline was due to a combination of factors, including bending stress on the pipe and a weld flaw at a pipe-to-fitting girth weld completed during fabrication.

“Although welding inspection and testing were conducted within applicable codes and standards, the weld flaw led to a crack that propagated over time as a result of bending stress fatigue, eventually leading to an instantaneous rupture,” TC Energy said. “The cause of the bending stress remains under investigation as part of the broader third-party root cause failure analysis.”

Metallurgical analysis identified no issues with the strength or material properties of the pipe or manufactured fitting, according to the company, which added that the pipeline was operating within its operational design and within the pipeline design maximum operating pressure. Investigation by the US Pipeline and Hazardous Materials Safety Administration is ongoing.

The line was shut after spilling 12,937 bbl of oil in rural Washington County, Kansas. TC Energy expects repairs and remediation to cost $480 million.

The company is operating Keystone at reduced pressure while it continues its response and investigation. It began a controlled restart late last year (OGJ Online, Jan. 2, 2023). “Our team is progressing a remediation plan, including an analysis of other areas with potentially similar conditions, the use of additional in-line inspections, and further operational mitigations,” TC Energy said.

Mexico Pacific to sell LNG to ExxonMobil

Mexico Pacific Ltd. LLC has executed two long-term sales agreements with ExxonMobil LNG Asia Pacific for a combined 2 million tonnes/year (tpy) of LNG from Mexico Pacific’s 14.1-million tpy Saguaro Energia LNG plant in Puerto Libertad, Sonora, Mexico. The ExxonMobil affiliate will purchase LNG on a free-on-board basis from the plant’s first two trains and has an option for 1 million tpy from 4.7-million tpy Train 3.

“We have reached a critical point on contract volumes required for final investment decision (FID) on our first two trains and will now shift focus to close contracting…for a subsequent Train 3 FID,” said Ivan Van der Walt, chief executive officer of Mexico Pacific. “As we position for FID on the first two trains, we will also commence advanced engineering with Bechtel.”

The company is targeting first LNG exports in 2027.

ONEOK Inc. last year filed for permission to build and operate its 2.8-bcfd Saguaro Connector natural gas pipeline, crossing into Mexico from Hudspeth County, Tex. It expects to take FID on the pipeline, which would connect to one being developed on the Mexican side of the border for delivery to the LNG plant, by mid-2023 (OGJ Online, Dec. 21, 2022).

Freeport LNG requests FERC authorization to return to commercial operation

Freeport LNG Development LP has requested US Federal Energy Regulatory Commission (FERC) authorization to progress to the full, commercial operations of its 15-million tonne/year (tpy) Phase I liquefaction plant on Quintana Island, Tex. Phase I includes three 5-million tpy liquefaction trains, two 160,000-cu m storage tanks, and one loading dock.

Dock 1 and Loop 1 LNG transfer piping have been fully reinstated, and on Feb. 11, 2023, loaded 152,000-cu m Kmarin Diamond, chartered by a unit of bp PLC, one of Freeport LNG’s term customers. Train 3 has been restarted and is ready to ramp up to full production rates. Train 2 has completed its pre-startup safety review (PSSR) and is ready to begin its restart, and Train 1 will follow “within the next few weeks,” according to Freeport LNG. Tanks 1 and 2 have remained in operation throughout recovery from the June 2022 ignition of a natural gas vapor cloud and subsequent fire.

Freeport LNG noted in a letter to FERC requesting the resumption of full operations that the LNG trains were not involved in the June 8 incident and thus no restoration work was performed on them. “As such, restart of those trains does not entail the review or verification of any restoration work,” the company continued, asking permission to commence restart of Trains 1 and 2 once both trains have completed PSSR.

Having completed repairs and performed other remedial actions, Freeport last month obtained FERC’s approval to commission Loop 1 and reinstate its boil-off gas management system. Thereafter, Freeport obtained additional approvals from FERC, including authorization to return Loop 1 to service, including berthing and loading LNG vessels from Dock 1, and cooldown and restart of Train 3.

Freeport says it has already performed a full PSSR of Train 2, identified and completed corrective work necessary to safely restart the unit, and is ready to do so. PSSR of Train 1 and any necessary corrective work will follow.

The company last year, but before the explosion, requested a 26-month FERC extension to put 5.1-million tpy Train 4 in service.

Coastal GasLink 83% complete, costs increase

TC Energy Corp. has updated cost estimates for its 2.1-bcfd Coastal GasLink natural gas pipeline in Western Canada, ascribing the adjustments to material cost pressures that include shortages of skilled labor, impacts of contractor underperformance and disputes, and unexpected events like drought conditions and resulting erosion and sediment control problems. The company now expects Coastal GasLink to cost C$14.5 billion ($10.9 billion), up from C$11.2 billion.

Coastal GasLink is about 83% complete, according to TC Energy. The entire route has been cleared, grading is more than 94% complete, and more than 485 km of the 670-km, 48-in. OD pipeline has been backfilled, with restoration activities under way in many areas.

Commissioning has started at Wilde Lake compressor and meter station at Groundbirch, BC, with introduction of natural gas expected in March. Coastal GasLink is expandable to 5 bcfd with the addition of compression along its route and subject to permitting. The pipeline will supply the 14-million tonne/year LNG Canada liquefaction plant under development in Kitimat, BC.

The project is targeting mechanical completion by end-2023, with commissioning and cleanup work continuing into 2024-25. Extension of construction well into 2024 would increase costs by up to an additional $1.2 billion.