OGJ Newsletter

Nov. 20, 2023
A roundup of General Interest, Exploration & Development, Drilling & Production, Processing, and Transportation news from around the industry.


KMI to acquire NextEra Energy South Texas assets for $1.8 billion

Kinder Morgan Inc. (KMI), Houston, has agreed to acquire NextEra Energy Partner’s South Texas assets, STX Midstream, for $1.815 billion.

The STX Midstream pipeline system includes integrated, large diameter high pressure natural gas pipelines that connect the Eagle Ford basin to Mexico and Gulf Coast demand markets.

The acquisition of 462 miles of pipeline with 4.9 bcfd of capacity compliments KMI’s assets and will enable the company “to capture incremental opportunities serving LNG, power generation, LDC customers, and exports to Mexico,” said Sital Mody, KMI president of natural gas pipelines.

STX Midstream includes a 90% interest in the NET Mexico pipeline; MGI Enterprises, a PEMEX affiliate, owns the other 10%.

STX Midstream owns and operates Eagle Ford Midstream, a 158-mile residue line connecting the Eagle Ford basin to the Agua Dulce Hub in Nueces County, Tex. Eagle Ford Midstream is connected to multiple pipeline systems, including KMI’s Tennessee Gas Pipeline, Kinder Morgan Tejas Pipeline, and Natural Gas Pipeline Company of America.

STX Midstream also owns a 50% interest in Dos Caminos LLC, which is operated by, and the other 50% interest owned by, Howard Energy Partners (HEP). Dos Caminos has placed in service a 62-mile pipeline that connects HEP’s existing midstream pipeline and infrastructure in Webb County, Tex. to KMI’s new Eagle Ford pipeline, which was recently placed in service.

The portfolio of assets is highly contracted, with an average contract length over 8 years, KMI said. About 75% of the business is supported by take-or-pay contracts.

The transaction is expected to close in first-quarter 2024.

S&P Global: Oil market fundamentals outweighing Middle East war fears

Oil market fundamentals remain stable despite the uncertainty and potential for volatility arising from the Israel-Hamas war, according to S&P Global Commodity Insights. Growth in non-OPEC+ supply, decelerating demand growth following China’s 2023 reopening, and sizeable OPEC spare capacity point to a well-supplied market in coming months.

“The onset of the Israel-Hamas war does fuel volatility and bring additional risks, but it has not affected underlying oil market fundamentals. Oil prices have remained below where they were in late September—a week before the Hamas attack. Strong oil market fundamentals are prevailing over any fears at the moment,” said Jim Burkhard, vice-president and head of research for oil markets, energy and mobility.

The outlook suggests that non-OPEC+ supply growth alone will be sufficient to meet global oil demand in 2023-2025. Each year, demand is anticipated to hit new records, yet the rate of increase is expected to slow down after the 2 million b/d rise this year, as the impact of mainland China’s reopening fades.

S&P Global Commodity Insights forecast that in 2024, oil supply from non-OPEC+ nations will grow by 2.3 million b/d, which is significantly more than the demand growth projected at 1.6 million b/d. For 2025, non-OPEC+ supply growth, estimated at 1.6 million b/d, is expected to exceed demand growth of just below 1 million b/d for that year.

Additionally, the considerable global crude oil production spare capacity, about 4.6 million b/d, serves as a cushion against potential supply interruptions. Supply restraint by OPEC+ will be essential for keeping oil prices over $80/bbl in 2024 and $70/bbl in 2025, according to the analysis. OPEC+ crude production in 2024 (excluding Iran, Venezuela, and Libya) is expected to be 500,000 b/d lower than it was in 2023.

“OPEC+, and particularly Saudi Arabia and Russia, are expected to produce less oil in 2024 than in 2023—and that trend could continue into 2025,” Burkhard said.

While market fundamentals do not point to an impending supply crisis, the risks of supply disruption are still higher than they were prior to the Hamas attack. How Iran and the US respond will continue to be key, the analysis said. 

Williams earnings up 10%, boosted by sale

Williams Cos. Inc.’s third-quarter 2023 net income rose 10% year-on-year, reaching $654 million. Williams ascribed the improved earnings to a $130-million gain from the sale of its 270-mile Bayou Ethane Pipeline system and higher service revenues driven by recent acquisitions and increased volumes and rates on its Northeast Gathering & Processing unit.

Bayou Ethane uses 6- to 12-in. OD pipe to ship the liquid from multiple third-party fractionation and storage sites in Mont Belvieu, Tex., to Nova Chemicals Corp.’s 1.8-billion lb/year Geismar, La., ethylene plant, also previously owned by Williams. Williams said it will use proceeds from the sale to strengthen its position in the Denver-Julesburg (DJ) basin.

The company placed Phase 1 of Transcontinental Gas Pipe Line Corp.’s (Transco) 829-MMcfd Regional Energy Access expansion project into service and advanced an additional 2 bcfd of Transco expansion for completion by end-2025. It also signed precedent agreements for Transco’s 1.4-bcfd Southeast Supply Enhancement.

Williams completed integration of MountainWest Pipelines Holding Co.’s 2,000-mile system into its operations in third-quarter 2023, completing a process begun with its acquisition early in the year. It also completed an anchor-shipper precedent agreement for the system’s 113-MMcfd Uinta basin expansion. Additional capacity is expected by July 1, 2024. 

Exploration & Development   Quick Takes

Equinor makes oil, gas discovery near North Sea Oseberg field

Equinor ASA discovered oil and gas in two formations near Oseberg field in the North Sea and will work to improve understanding of the discovery and to identify production solutions, the Norwegian Petroleum Directorate said in November.

Preliminary estimates place the size of the discovery in the Eiriksson formation at 0.2-0.4 million standard cu m of recoverable oil equivalent. The preliminary size estimate for the discovery in the Cook formation is 0.2-1.0 million standard cu m of recoverable oil equivalent.

The exploration well, 30/6-C-2 A (Lambda), was drilled to a vertical depth of 2,795 m subsea about 4 km west of Oseberg field from the Oseberg C platform in the northern part of the field in production license (PL) 053. It was terminated in the Eiriksson formation. Water depth at the site is 109 m.

The primary target was to prove petroleum in Upper Triassic to Middle Jurassic reservoir rocks in the Statfjord Group. The secondary target was to prove petroleum in Lower Jurassic reservoir rocks in the Cook formation.

The well encountered about 23 m of oil and gas-filled sandstone with good reservoir quality in the Eiriksson formation in the Statfjord Group. In the Cook formation, the well encountered about 15 m of oil and gas-filled sandstone with moderate to good reservoir quality. The petroleum-water contact was encountered in the Eiriksson formation, but not in the Cook formation.

The well was not formation-tested, but data collection has been carried out.

Equinor is operator with 49.3% interest. Partners are Petoro AS (33.6%), TotalEnergies (14.6%), and ConocoPhillips (2.4%).

Petronas discovers oil offshore Suriname

Petronas subsidiary Petronas Suriname E&P BV discovered oil at the Roystonea-1 exploration well in Suriname’s Block 52. The company is working to evaluate the full extent of the discovery and its potential development synergy with the Sloanea-1 discovery made in 2020 within the same block, the company said in a release Nov. 2.

The well, which lies about 185 km offshore in water depth of 904 m, was drilled to a total depth of 5,315 m. It encountered several oil-bearing Campanian sandstone reservoir packages.

The 4,749-sq km block lies north of the coast of Paramaribo, Suriname, within the prospective Suriname-Guyana basin in water depths of 50-1,100 m.

Petronas is operator in a 50-50 JV with ExxonMobil.

Petrobras lets contract for Mero 4 field development offshore Brazil

Petrobras has awarded a contract amendment to Subsea 7 SA for development of Mero 4 field, which lies about 200 km off the coast of Rio de Janeiro, Brazil, at 2,200 m water depth in the presalt Santos basin.

Mero 4 is the fourth definitive project of Mero unitized field operated by Petrobras (38.6%) in partnership with Shell Brasil (19.3%), TotalEnergies (19.3%), CNPC (9.65%), CNOOC (9.65%), and Pré-Sal Petróleo SA (PPSA) (3.5%), representing the government in the non-contracted area.

The award was announced in redacted form in late September 2023. The contract amendment scope includes engineering, procurement, fabrication, installation, and pre-commissioning of 76 km of rigid risers and flowlines for the steel lazy wave production system.

Project management and engineering will begin immediately at Subsea7’s offices in Rio de Janeiro and Paris. Fabrication of the pipelines will take place at Subsea7’s spoolbase at Ubu in Espirito Santo, and offshore operations are scheduled to be executed in 2025 and 2026. 

Subsea7 said the value of its share of the contract is over $750 million.

Drilling & Production   Quick Takes

ExxonMobil adds production offshore Guyana

ExxonMobil started production at Payara, Guyana’s third offshore oil development on Stabroek block, bringing total production capacity in Guyana to about 620,000 b/d, the company said Nov. 14.

The Prosperity floating, production, storage and offloading (FPSO) vessel—which arrived in Guyana waters in April—is expected to reach initial production of about 220,000 b/d over first-half 2024 as new wells come online.

The additional capacity will be the third major milestone towards reaching a combined production capacity of more than 1.2 MMboe/d on the block by year-end 2027, the operator said.

The Prosperity FPSO, with a design that largely replicates that of the Liza Unity FPSO, will have associated gas treatment capacity of 400 MMcfd and water injection capacity of 250,000 b/d. It is spread moored in water depth of about 1,900 m and crude oil storage capacity of 2 million bbl.

ExxonMobil Guyana anticipates six FPSOs will be in operation on Stabroek block by year-end 2027. Yellowtail and Uaru, the fourth and fifth projects, are in progress and will each produce about 250,000 b/d of oil. The company is working with the government of Guyana to secure regulatory approvals for a sixth project at Whiptail.

Pampa Energía plans Vaca Muerta crude development

Pampa Energía SA plans to invest $161 million through 2024 and early 2025 to develop crude oil from its Rincón de Aranda block in Vaca Muerta. The company expects to reach maximum production of 15,000-20,000 b/d by 2027-28.

Pampa’s natural gas production has already been rising due to startup this summer of the 11-million cu m/day (MMcmd) President Néstor Kirchner Gas Pipeline. Pampa produced an average of nearly 13 MMcmd in third-quarter 2023, a new high for the company and up 20% year-on-year. Production peaked at 16 MMcmd, 44% higher than 2022’s single biggest day. Forty-three percent of Pampa’s gas production came from the Vaca Muerta formation, compared with 3% in the same quarter last year.

Rincón de Aranda was jointly owned with TotalEnergies SE until an asset exchange in September gave Pampa full control.

In third-quarter 2023 Pampa had sales of $474 million, down 7% compared with third-quarter 2022, and a net profit of $152 million. The company ascribed the softer sales to the decline in international prices.

Petrobras increases 2023 oil, gas production guidance

Petróleo Brasileiro SA (Petrobras) has increased its 2023 oil and gas production guidance based on its third-quarter production.

Full-year 2023 oil and gas production guidance is now 2.8 MMboe/d from 2.6 MMboe/d, its commercial production guidance increased to 2.4 MMboe/d from 2.3 MMboe/d, and oil and NGL production guidance increased to 2.2 MMboe/d from 2.1 MMboe/d. The increases are due to third-quarter performance and forecasts for ramp-ups and new wells in the fourth quarter, Petrobras said in a release Nov. 10.

In this year’s third quarter, average production of oil, NGL, and natural gas reached 2.88 MMboe/d, 9.1% higher than in second-quarter 2023. Production in pre-salt reached a new quarterly record of 2.25 MMboe/d, equivalent to 78% of Petrobras’ total production, surpassing the previous record of 2.06 MMboe/d in second-quarter 2023. Total operated production by Petrobras also reached a record with 3.98 MMboe/d in the same period, 7.8% above this year’s second quarter.

Total 2023 capital spending guidance is $13 billion, an increase of more than 30% compared with 2022, but a reduction from previous guidance of $16 billion. Exploration and production spending declined to $11.2 billion from $13.3 due to supply market challenges in the inflationary context, the operator said.

PROCESSING   Quick Takes

Lukoil, CC7 ink deal for potential Stavropol gas-to-chemical complex

PJSC Lukoil has signed an agreement with China National Chemical Engineering Corp. subsidiary China National Chemical Engineering & Construction Corp. Seven Ltd. (CC7) to cooperate on development of a new gas chemical complex (GCC) to be built in Budennovsk, Stavropol Territory, the industrial center of Southern Russia’s North Caucasus region.

Lukoil and CC7 agreed to develop project documentation in cooperation with yet-to-be-identified Russian companies for creation of the proposed GCC, Lukoil said.

If completed, the project would process natural gas produced from Lukoil’s northern Caspian Sea fields to manufacture carbamide.

Without revealing additional GCC details, Lukoil did confirm it is examining an option to use an incentive mechanism for the project in collaboration with Stavropol regional authorities that could take the form of a special investment contract that would create new jobs and additional tax payments.

Lukoil subsidiary Stavrolen LLC currently operates the 2.2-billion cu m/year gas processing unit 1 (GPU-1) at its petrochemical complex in Budennovsk that—commissioned in February 2016—enabled the first production of petrochemicals based on Lukoil’s own feedstock of associated gas sourced from its North Caspian fields.

In October 2021, Lukoil broke ground on the 2.8-billion cu m/year GPU-2 at Stavrolen’s Budennovsk complex that—once completed—would boost Stavrolen’s processing capacity of associated gas delivered from Lukoil’s northern Caspian Sea fields to 5 billion cu m/year.

The first unit to be built under the Stavrolen integrated development program—which forms an essential part of Lukoil’s broader petrochemical strategy aimed at maximizing use of its own raw materials for production of chemicals—GPU-2 specifically would allow Stavrolen’s pyrolysis units to supply additional ethane and NGL feedstocks to expand the volume and variety of polyethylene and polypropylene produced at the site.

Lukoil said upon announcing the GPU-2 project that it expected Stavrolen’s integrated development program would increase production of:

  • Ethylene to 420,000 tonnes/year (tpy) from 350,000 tpy.
  • Polyethylene to 405,000 tpy from 300,000 tpy.
  • Copolymer polypropylenes to 120,000 tpy from 80,000 tpy.

Since first announcing the proposed development, Lukoil has not disclosed details regarding a status of Stavrolen’s GPU-2 project.

Flint Hills’ Pine Bend refinery commissions solar project

Flint Hills Resources LLC (FHR), Wichita, Kan., has started up one of the US’ largest solar installations to help power operations, lower energy costs, improve energy efficiency, and reduce emissions at subsidiary Flint Hills Resources Pine Bend LLC’s (FHR Pine Bend) 335,000-b/d Pine Bend refinery in the city of Rosemount, Dakota County, Minn.

Commissioned on Nov. 9, the new Pine Bend solar project includes more than 120,000 panels, FHR said in a post to its official LinkedIn page.

Upon first announcing the $75-million project in May, FHR said the 45-Mw solar installation—slated to become the US’ largest single-site use of direct solar power—would include at least 100,000 9-14-ft panels across 200 acres of a 300-acre tract of company-owned property immediately adjacent and connecting directly to FHR Pine Bend’s refining complex.

Designed with a peak solar-energy production capacity to satisfy roughly 30% of the refinery’s 135-Mw power needs during optimal conditions, the new solar installation now serves as FHR Pine Bend’s second source of on-site power generation following completion of its combined heat and power (CHP) system in 2019, which currently supplies the refinery about 50 Mw of electricity, or roughly 40% of what is required to power daily operations.

Arizona-based DEPCOM Power Inc.—a fellow subsidiary of FHR’s owner Koch Industries Inc.—delivered engineering, procurement, and construction services for the project.

Alongside supplying most of the transportation fuels used in Minnesota and a large portion of fuels used throughout the Upper Midwest, the FHR Pine Bend refinery also produces asphalt, home heating fuels, as well as raw materials used in a wide range of manufacturing processes.


New Fortress charters FSRU for Terminal Gas Sul

New Fortress Energy Inc. has chartered the 160,000-cu m floating storage and regasification unit (FSRU) Energos Winter from Petróleo Brasileiro SA (Petrobras) starting December 2023. Energos Winter will be immediately deployed to Terminal Gas Sul (TGS), NFE’s new-build LNG terminal in Santa Catarina, Brazil, which will start commercial operations in January 2024.

TGS, sited 300 m offshore, will connect via 32 km of pipe to an existing onshore gas distribution pipeline to help replace declining gas imports from Bolivia. It has a designed regasification capacity of 15 million cu m/day.

Energos Winter will be sub-chartered by NFE through the remaining term of the Petrobras charter with Energos infrastructure and then direct-chartered by NFE on a long-term basis with Energos. This will enable NFE to begin commercial operations at TGS in January 2024 and continue uninterrupted service on a long-term basis.

Energos Infrastructure, owner of the Energos Winter, is owned 80% by funds managed by Apollo Global Management Inc. and 20% by NFE.

TotalEnergies commissions FSRU in Port of Le Havre, France

TotalEnergies has commissioned Hoegh LNG AS’s 400-MMcfd Cape Ann floating storage and regasification unit (FSRU) in Port of Le Havre, northern France.

The terminal injected its first MWh of gas into the grid operated by GRTgaz with  LNG from Norway, the company said late October.

TotalEnergies has contracted 50% of the terminal’s annual capacity of around 5 billion cu m (about 10% of French consumption), to supply it with LNG from its global portfolio. Remaining capacity will be marketed according to rules approved by the regulator.

The regasification capacity comes online as part of a planned strategy by the European Union and the UK to expand LNG import capacity since Russia’s full-scale invasion of Ukraine in February 2022 and the reduction in natural gas pipeline imports from Russia that followed (OGJ Online, Nov. 29, 2022).

Finland: Container ship likely cause of Balticconnector damage

Finland’s National Bureau of Investigation (NBI) has established the sequence of events behind the damage incurred in October on the subsea 7.2-million cu m/day Balticconnector natural gas pipeline, determining that the Hong Kong-flagged Newnew Polar Bear container ship likely caused the damage.

A 1.5-4.0 m-wide dragging trail leads to the point of damage, with an anchor visible “a few meters” in the distance, according to the agency’s lead investigator. Upon lifting the anchor, traces were visible indicating it had been in contact with the gas pipeline. Imaging also revealed a narrow dragging trace on the seafloor consistent with the part of the anchor connecting it to its chain.

Ship-traffic data confirmed Newnew Polar Bear’s proximity to the damage, with investigators subsequently unable to confirm that both the vessel’s front anchors remained in place. Newnew Polar Bear did not cooperate with investigators and has since left Finland’s exclusive economic zone.

NBI said it had established contact with Chinese authorities in regard to continuing its work. “Particular attention will be paid to investigating if there [was] any premeditation or negligence involved in the sequence of events,” the agency added.

Gasgrid Finland Oy and Estonian gas transmission system operator Elering AS had earlier shut down Balticconnector’s operations after noticing an unusual drop in pressure.