OGJ Newsletter
GENERAL INTEREST Quick Takes
ExxonMobil, EnLink, CF Industries launch 2-million tpy CCS project
ExxonMobil Corp., EnLink Midstream LLC, and fertilizer manufacturing company CF Industries Holdings Inc. are collaborating to store as much as 2 million tonnes/year (tpy) of industrial CO2 emissions. Emissions from CF Industries’ Ascension Parish, La., complex will be transported through EnLink’s transportation network and stored underground at a 125,000-acre property owned by ExxonMobil in Vermilion Parish, about 100 miles southwest of CF’s complex.
The companies expect project start-up in early 2025. CF Industries recently announced a $198.5 million plan to build a CO2 dehydration and compression unit at its ammonia production plant in Donaldsonville, La., and expects to market up to 1.7 million tpy of blue ammonia.
EnLink suggested that it would use existing infrastructure for the transportation part of the collaboration, cutting both time and cost compared with possible newbuild options.
Louisiana has set a 2050 net-zero CO2 emissions target for the state.
A chemical process is considered “blue” when CO2 emissions are captured before their release into the air, making the process more carbon neutral. Demand for blue ammonia is expected to grow as a decarbonized energy source for hard-to-abate industries, both for its hydrogen content and as a fuel itself, because ammonia’s components—nitrogen and hydrogen—do not emit carbon when combusted.
IEA: Russian oil exports fall as trade flow reallocation slows
Russian oil exports fell 230,000 b/d in September to 7.5 million b/d, with crude down 260,000 b/d and products up by 30,000 b/d, according to data from the International Energy Agency (IEA). Revenues were down $3.2 billion to $15.3 billion on both lower volumes and prices but were still higher than the average monthly revenue in 2021.
Shipments to European Union countries fell by 390,000 b/d month-on-month (m-o-m) to 2.6 million b/d, with its share down to just 35% in Russia’s total oil exports, compared to 50% at the start of the year.
Exports to India were stable m-o-m at just under 1 million b/d, while loadings to China and Turkey were down by 115,000 b/d and 50,000 b/d, respectively. However, with close to 500,000 b/d of oil going to yet unidentified destinations, final numbers for each importing region may result in significant revisions to preliminary figures.
Nevertheless, the share of Russian oil exports to western markets fell, while Asian buyers gained in importance. In September, declared shipments to China and India combined were 160,000 b/d higher than those to Europe, including EU and non-EU countries. The US stopped importing Russian oil in April.
Since June, China has been the largest importer of Russian crude oil, ahead of the combined EU countries. EU crude oil imports from Russia fell to just 1.6 million b/d in September. While it has taken 7 months for them to replace 800,000 b/d of Russian crude oil imports, they will need to switch an additional 1.3 million b/d of seaborne and pipeline volumes in the 2 months remaining until the EU ban on Russian oil kicks in.
Oil product loadings to EU countries fell 130,000 b/d m-o-m to 965,000 b/d, bringing the cumulative post-Ukraine-invasion loss to 550,000 b/d. Diesel shipments were down by 70,000 b/d m-o-m to just 510,000 b/d.
Laredo Petroleum plans quarter-over-quarter production decrease
Laredo Petroleum Inc., Tulsa, expects fourth-quarter 2022 total production to be 72,500-75,500 boe/d and oil production to be 32,000-34,000 b/d, down from this year’s third quarter, with capital expenditures of $135-145 million, in-line with third-quarter 2022 levels.
The company provided the update with preliminary third-quarter results Oct. 18 ahead of complete results Nov. 3.
Updated fourth-quarter expectations include revised assumptions related to the impact of offset operator completions, production downtime due to increased equipment lead times, and a 1,600 boe/d (75% oil) reduction in volumes related to the sale of non-operated acreage in Howard County, Texas, to Northern Oil and Gas Inc., which closed Oct. 3, 2022.
In third-quarter 2022, the Permian basin-focused operator produced an average 79,500 boe/d, within guidance of 78,500-81,500 boe/d. Oil production for the quarter averaged 35,000 b/d, below guidance of 35,500-37,500 b/d. Oil production was negatively impacted as offset operator completions in Howard County affected more Laredo wells than expected, the company said. Of the impacted wells, newer, higher-production packages have returned to previous production expectations while older packages are taking longer than anticipated to return to expected production levels, the company said.
Total incurred capital expenditures during the third quarter were $140 million, excluding non-budgeted acquisitions and leasehold expenditures, higher than guidance of $120 million. Increased investments were related to the timing of drilling and completions activity and infrastructure build out.
Waldorf to acquire Dana, TAQA Dutch upstream businesses
Waldorf Energy Netherlands BV, a subsidiary of Waldorf Production Ltd., has entered agreements to acquire the respective Netherlands upstream businesses of Dana Petroleum Ltd., a wholly owned subsidiary of Korea National Oil Corp., and TAQA Energy BV, a wholly owned subsidiary of Abu Dhabi National Energy Co.
Neither financial terms nor asset specifics were disclosed. According to Dana Petroleum’s website, the company’s upstream business in the Netherlands includes interests in 21 oil and gas fields including De Ruyter, Hanze, Van Ghent, and Van Nes, one exploration license, two potential developments in Denmark, and two in the Netherlands.
TAQA, according to its website, has been extracting natural gas from onshore fields in Bergen II production license around Alkmaar, the Netherlands, since 1972. Gas is transported to TAQA’s gas treatment installation at Oude Helderseweg.
Exploration & Development Quick Takes
TotalEnergies to operate PSC off Malaysia
TotalEnergies EP Malaysia will serve as operator in a newly signed production sharing contract with PETRONAS Carigali Sdn Bhd, Sabah Shell Petroleum Co. Ltd., and Shell Sabah Selatan Sdn Bhd for Block 2K off the coast of Sabah.
The 1,952-sq km block lies in 3,000 m of water in the northwest ultra-deepwater area within a proven hydrocarbon basin, PETRONAS said in a release Oct. 13.
The signing “completes the licensing of the five ultra-deepwater blocks off the coast of Sabah, along the newly identified Oligo-Miocene carbonate trend proven by Tepat-1 oil discovery in Block N in 2018,” said Mohamed Firouz Asnan, senior vice-president, of Malaysia Petroleum Management, PETRONAS. Block 2V was signed in 2021, followed by Blocks 2W and X early this year.
A total of four wells are expected to be drilled in the blocks in 2022 and 2023, he continued.
TotalEnergies holds 34.9%. Parners are PETRONAS Carigali Sdn Bhd (40%), Sabah Shell Petroleum Co. Ltd. (25.1%), and Shell Sabah Selatan Sdn Bhd (25.1%).
NOPSEMA seeks partners to streamline decommissioning projects
Australia’s National Offshore Petroleum Safety and Environmental Management Authority (NOPSEMA) is seeking industry partners for a pilot project designed to investigate ways to streamline decommissioning of stranded or end-of-life oil and gas infrastructure.
Australia has an estimated $50 billion (Aus.) of decommissioning work in need of completion by 2050, according to a 2020 Wood Mackenzie report, half of which needs to begin within the next 10 years, NOPSEMA said.
The offshore regulator is working in conjunction with the Federal Department of Climate Change, Energy, the Environment and Water (DCCEEW) to evaluate options to accelerate assessment of decommissioning work proposals.
The project is aimed at understanding the technical, legal, policy, and administrative feasibility of full or partial streamlining of assessments. The process also could help reduce regulatory overlap and improve consistency while also maintaining desired environmental outcomes.
NOPSEMA said the initial phase of the project will be a trial in which the regulator will provide technical advice to support DCCEEW’s assessment of sea dumping permit applications for decommissioning projects regulated in tandem with environmental plans under the Offshore Petroleum and Greenhouse Gas Storage (Environment) regulations.
Sea dumping is used to describe ‘rigs to reef’ and carbon capture storage projects.
NOPSEMA has identified one partner and has begun an initial trial, but seeks industry input to nominate additional suitable decommissioning proposals to join phase one.
TAG Oil to develop Badr oil field reservoir in Egypt
TAG Oil Ltd. has formally entered a petroleum services agreement with Badr Petroleum Co. (BPCO) to begin development operations at the unconventional heavy oil Abu Roash “F” (ARF) reservoir in Badr oil field (BED-1), a 107-sq km concession in the Western Desert of Egypt.
TAG Oil was awarded the agreement in September after negotiations with Egyptian General Petroleum Corp. (EGPC) and a letter of intent confirming EGPC had commissioned BPCO to conclude the petroleum services agreement with TAG Oil.
Badr oil field was discovered in 1982 by a joint venture of Shell Oil and EGPC (Bapetco). There has been production across the concession from conventional reservoirs of light oil and associated natural gas through primary development of Kharita, Bahariya, and certain Abu Roash sandstone formations. The ARF reservoir produced conventionally from some wells with considerable initial oil rates but has declined rapidly.
TAG Oil conducted analysis of the geologic, geophysical, and well production data of the target ARF zone, which is a deep, tight, low porosity, low permeability carbonate reservoir with varied fluid characteristics across BED-1, the company said in a September release. The company determined that there is a high probability for successful commercial development of the ARF reservoir by applying proven technologies including long-reach horizontal wells, hydraulic fracture stimulation, and potentially other enhanced oil recovery production techniques.
The 10-year concession includes an optional 10-year extension. Multiphase development is planned (evaluation in phase one and commercial production in phases two and three).
Drilling & Production Quick Takes
Neptune Energy to increase production in Germany
Neptune Energy Group Ltd. will increase production at Römerberg field in the Rhine Valley, southwestern Germany, after receiving approval from the State Mining Authority for Rhineland-Palatinate.
Production will increase by up to three times the current limit of 3,700 boe/d. The increase comes as Germany looks to shore up domestic energy security and supports the operator’s investment strategy for Römerberg field and its wider German business portfolio. Neptune is currently drilling the ninth production well on the field, which is due to come onstream in this year’s fourth quarter.
The decision “enables Neptune to mature our full-field development plans for the Römerberg oil field, including significant investment in surface facilities to support higher production rates, upgrade water treatment and reduce emissions associated with flaring,” said Neptune Energy’s managing director in Germany, Andreas Scheck.
The approval comes on the heels of a permit allowing Neptune to continue increased gas production from Duva oil and gas field in the Norwegian North Sea for supply to the UK this winter.
Neptune has been working for more than 6 years on the application to increase the production limit at Römerberg, which included a comprehensive environmental impact assessment and public consultation, it said.
Neptune Energy is operator at Römerberg (50%) with partner Palatina GeoCon (50%).
Equinor starts Peregrino Phase 2 production
Equinor ASA started oil production at Peregrino C platform in Brazil’s Campos basin as part of Peregrino field’s Phase 2 development. The project is expected to extend the life of Peregrino field to 2040, add 250-300 million bbl of oil, and halve expected CO2 emissions/bbl over the remaining life of the field, the company said Oct. 13.
The project was delayed from its expected 2020 start by COVID-19-related workforce cuts during the hook-up phase, but still delivered within the $3 billion cost estimate, the company said.
Phase 1 consisted of an FPSO unit supported by well head platforms Peregrino A and Peregrino B. Phase 2, expected to increase field production to 110,000 b/d at plateau, is comprised of Peregrino C with drilling equipment and living quarters tied to the FPSO and a new pipeline importing gas to the platform for power generation.
In Phase 2, power generation on Peregrino C was switched to gas from diesel—a move expected to avoid 100,000 tonnes/year of CO2 emissions from the field.
Peregrino is the largest field operated by Equinor outside of Norway and the first of a series of major field developments in Brazil. Remaining reserves from Peregrino Phase 1 are estimated at 180 million bbl (OGJ Online, July 19, 2022).
Equinor is operator at Peregrino (60%) with partner Sinochem (40%).
ADNOC lets drilling contract worth $980 million
Abu Dhabi National Oil Co. (ADNOC) let a contract for two jack up offshore rigs and associated manpower and equipment to ADNOC Drilling.
The contract is worth $980 million and brings the total value of awards from ADNOC Offshore to ADNOC Drilling in 2022 to $5.95 billion. In October, ADNOC Drilling was awarded a contract worth $1.53 billion for the provision of jack up and island rigs and associated integrated drilling services. This followed two awards in August worth $3.43 billion to hire eight jack up rigs.
These awards help support the expansion of ADNOC’s crude oil production capacity to 5 million b/d by 2030 and gas self-sufficiency for the UAE, the company said.
Shell lets drilling contract to Maersk Developer
Shell Brasil Petroleo Ltda. let a contract to Maersk Drilling Co. for work at BC-10 field in Campos basin, offshore Brazil.
The Maersk Developer semisubmersible rig will drill one exploration well and perform subsea well interventions.
The contract is expected to begin in March 2023, in direct continuation of the rig’s current contract, with an estimated duration of 90 days. Contract value is about $37 million, including a mobilization fee.
Maersk Developer is able to operate in water depths up to 10,000 ft. It was delivered in 2009 and is currently operating offshore Brazil for Karoon Energy Ltd.
PROCESSING Quick Takes
OMV Petrom’s Petrobrazi refinery to expand production capacity
OMV Petrom SA, Bucharest, is doubling aromatics production at its 4.5-million tpy Petrobrazi refinery in southeast Romania, near Ploiesti City, building a new 100,000-tpy aromatics unit to replace its current one, commissioned in 1961. The project will cost €130-million.
Work includes construction of a new unit that will process 1,500 tonnes/day of reformed gasoline to expand production of aromatics at the refinery to 100,000 tpy from its current output of about 50,000 tpy, OMV Petrom said on Oct. 12.
The new unit specifically will ensure increased recovery of toluene as well as ongoing production of gasoline with a benzene content of less than 1 vol % in compliance with European emission standards, according to the operator.
Scheduled for construction between 2023-25, the new aromatics unit is targeted for startup in 2026.
“Other major investments will follow at Petrobrazi, both in the technological efficiency of the refinery as well as in the production of second-generation biofuels,” said Radu Ca˘pra˘u, OMV Petrom executive board member responsible for the operator's downstream business.
In its 2021 annual report, OMV Petrom said it expects the Petrobrazi refinery to maintain an average utilization rate over 95% until 2030, save for upcoming major turnarounds planned in 2023 and 2028, when utilization rates will average 85-90%.
OMV Petrom also intends to execute a project to upgrade bottom-of-the-barrel crude material into non-fuel products, including bitumen, carbon black, or calcined coke by up to 200,000 tpy by 2030, the operator said.
Renewables production
In line with commitments to help meet the European Commission’s goals of reducing CO2 emissions from air travel, OMV Petrom said in late June 2022 that the Petrobrazi refinery will be Romania’s first to produce sustainable aviation fuel (SAF).
Following a pilot project completed in July 2020, the refinery was scheduled to produce SAF via co-processing of locally produced rapeseed oil in a series of test-run volumes beginning in July.
By 2030, OMV Petrom plans for the refinery to produce a combined 450,000 tpy of SAF and hydrotreated vegetable oil (HVO), according to Ca˘pra˘u.
Compared to conventional jet fuel, Petrobrazi’s production of SAF would help reduce CO2 emissions from commercial flights by about 70%, while the site’s HVO production—usable as a replacement for conventional diesel—would lower CO2 emissions by at least 65%, according to the operator.
OMV Petrom said it plans to expand the refinery’s output of SAF in the future by incorporating a wider slate of renewable waste feedstocks, such as used cooking oil.
Texas operator proposes building grassroots decarbonized refinery
Prairie Energy Partners LLC, a subsidiary of Southern Rock Energy Partners LLC, El Campo, Tex., is selecting the site for proposed construction of a grassroots, full-conversion, decarbonized refinery to process US-produced light, sweet conventional and shale crudes into low-carbon transportation fuels.
As of Oct. 10, Prairie Energy Partners was working to finalize a location for the planned $5.56-billion refinery in either Victoria County, Tex., or Payne and Lincoln County, Okla., Southern Rock Energy Partners said.
To be built on a footprint of 400 acres, the refinery would be equipped to process West Texas Intermediate (WTI) and sweet shale crudes sourced from the Eagle Ford, Permian, DJ, and Bakken basins into 91.25 million bbl/year of clean finished products, including gasoline, diesel, and jet fuel, according to the operator.
The complex also would be outfitted with technologies and processes capable of reducing and eliminating 95% of greenhouse gas emissions as well as for reducing water production and consumption by 90%, with 80% of waste water further recycled and repurposed, the company said.
Unlike most conventional refineries that power process heating units with natural gas, the planned refinery would combine pure oxygen with blue hydrogen (from refinery offgases) and green hydrogen (from electrolysis) to yield a primary waste stream of steam.
Alongside including an associated carbon capture and storage system for its hydrogen complex, the refinery would be powered by renewable electricity, either sourced from the grid or generated on-site from recycled and repurposed waste heat or geothermal and solar assets.
Project plans also include construction of a new bidirectional refined products pipeline connecting to nearby terminals, an 8-bay truck terminal, a 300-car rail terminal, and a 4-barge marine terminal located at or near the project site.
Pending final investment decision and necessary permitting, Prairie Energy Partners intends to break ground on the project in 2023 for anticipated startup in 2025.
TRANSPORTATION Quick Takes
Clearfork expanding Haynesville gas gathering, treatment capacity
Clearfork Midstream LLC is expanding its Haynesville shale natural gas gathering, treatment, and compression capacity in northern Louisiana by 700 MMcfd to 1.3 bcfd. Work is expected to be completed first-quarter 2023.
Expansion of Clearfork’s Holly System includes building a 24-in. OD pipeline to the east side of the Red River in northeast Red River Parish, La. Clearfork also is building a 16-in. OD pipeline on the west side of the Red River in the Spring Ridge area of Caddo Parish. As part of these expansions, Clearfork plans to build new interconnects for additional takeaway capacity and downstream market optionality for shippers.
Clearfork also will increase the Holly System’s overall gas treatment and compression capacity. Treatment capacity at the Holly 3 plant will increase with installation of new contactor towers, optimization projects, and additional compression, which will provide lower-pressure service while still meeting pressure requirements of downstream pipelines. Clearfork will install a recently acquired amine unit to increase treatment capacity at its Holly 6 plant.
The company also owns idle amine treating assets that could, based on market demand, further increase the Holly System’s treatment capacity to 1.8 bcfd by end 2023.
Several new commercial agreements underpin the expansion, including two with minimum producer volume commitments in connection with a long-term acreage dedication finalized in August 2022.
Clearfork acquired Haynesville-focused Azure Midstream Energy LLC in February 2022.
Petronas declares force majeure at MLNG Dua
Malaysian-state Petronas in early October declared force majeure on gas supply to its 9.6-million tonne/year (tpy) MLNG Dua plant due to a pipeline leak caused by Sept. 21, 2022, soil movement near kilometer post KP201 of the 7.7-billion cu m/year Sabah-Sarawak Gas Pipeline (SSGP). MLNG Dua is part of the eight-train, 25.7-million tpy Petronas LNG Complex (PLC) in Bintulu, Sarawak.
Gas fields in the Central Luconia area, offshore Bintulu, supply PLC. Petronas noted that the force majeure only affected supply to MLNG Dua and that the other PLC plants—Malaysia LNG and MLNG Tiga—continue normal operations.
Petronas is in discussions with MLNG Dua contract customers regarding suitable mitigation of any missed deliveries. It also reports conducting a comprehensive evaluation of SSGP.
Sabah Energy Corp. Sdn Bhd (SEC) and Petronas, meanwhile, agreed on terms for the supply of 120 MMscfd of natural gas to SEC and the sale of seven onshore gas pipelines in Sabah, Malaysia, by Petronas Gas Bhd and Petronas Carigali Sdn Bhd to SEC. Also included in the deal were the sale to SEC of gas supply agreements between Petronas and five independent power producers in Sabah.
The State Government of Sabah said SEC’s purchase of the Petronas contracts made it the largest domestic supplier and transporter of natural gas in Sabah, moving more than 250 MMscfd.
MidOcean Energy to acquire four Tokyo Gas LNG stakes in Australia
EIG Global Energy Partners entity MidOcean Energy agreed to acquire Tokyo Gas Co. Ltd.'s interest in four LNG projects in Australia. Interests include 5% of Woodside-operated Pluto LNG, 2.5% of Train 2 in Shell-operated Queensland Curtis LNG, 1.575% of Inpex-operated Ichthys LNG, and 1% of Chevron-operated Gorgon LNG.
Pluto, Gorgon, and Ichthys lie offshore Western Australia. The Queensland Curtis project is on Curtis Island near Gladstone on Queensland’s central east coast. All supply LNG to Asian markets.
The portfolio, acquired for $2.15 billion, is expected to generate around 1 million tonnes/year of LNG net to MidOcean.
The transaction is expected to close first-half 2023 subject to customary Australian regulatory approvals and preemption rights of respective LNG project joint venture members.
Venture Global, EnBW increase supply partnership
Venture Global LNG and European energy supplier EnBW have expanded their existing LNG partnership to 2 million tonnes/year (tpy). Under the 20-year agreements signed in June 2022, EnBW has increased the quantity of its long-term LNG offtake from Venture Global by an additional 0.5 million tpy from Plaquemines and CP2 LNG.
The two agreements in June called for 1.5 million tpy of LNG from the two liquefaction plants, starting 2026 (OGJ Online, June 21, 2022).
“To become less dependent on Russian natural gas and to strengthen diversification and security of supply, EnBW is supporting the German government by increasing further access to LNG supplies,” said Georg Stamatelopoulos, chief operating officer, generation and trading at EnBW. “With the help of LNG, we can secure Germany’s gas supply to enable the energy transition, while not losing sight of our climate neutrality targets,” he continued.