GENERAL INTEREST Quick Takes
Kazakh company to acquire TotalEnergies Kazakhstan affiliate
Kazakh company Oriental Sunrise Corp. Ltd. agreed to acquire Total E&P Dunga GmbH, a TotalEnergies affiliate, for $330 million. Total E&P Dunga holds 60% operating interest in onshore Dunga oil field in the Mangystau region of western Kazakhstan.
Sale of the field, which produced about 7,400 boe/d net to TotalEnergies in 2022, is subject to Kazakhstan authority approval and waiver of the partners’ preemption rights.
In 2019, TotalEnergies and partners approved the launch of a $300-million, third phase development of the field. The plan included adding wells to existing infrastructure and upgrading the processing plant to increase capacity by 10% to 20,000 b/d of oil by 2022 under a 15-year extension of the license agreement that had been set to expire in 2024.
Total is operator of Dunga with 60% interest. Oman Oil Corp. Exploration & Production LLC and PTTEP each hold 20% interest.
PETRONAS, ADNOC sign unconventional oil concession deal
Malaysia’s national oil and gas company, PETRONAS, signed a deal with Abu Dhabi National Oil Co. (ADNOC) to operate Abu Dhabi’s Unconventional Onshore Block 1.
The agreement launches the Middle East’s first unconventional oil concession and marks the first time a Malaysian company will invest in and explore for hydrocarbons in Abu Dhabi, ADNOC said in a release Dec. 5.
Under the 6-year concession agreement, PETRONAS (100%) will explore for and appraise unconventional oil in the block, which covers more than 2,000 sq km in Al Dhafra region.
Following a successful appraisal phase, the parties can enter a 30-year production concession with ADNOC holding the option of a 50% interest.
PETRONAS will contribute financially to ADNOC’s ongoing 3D seismic survey, which has already acquired seismic data within the concession area. Terms were not disclosed.
Abu Dhabi’s unconventional recoverable oil resources are estimated at 22 billion bbl of very light and sweet crude.
Enbridge, Oxy to develop Corpus Christi CCS hub
Enbridge Inc. and Oxy Low Carbon Ventures (OLCV), an Occidental Petroleum Corp. subsidiary, intend to jointly develop a CO2 sequestration hub in the Corpus Christi, Tex. area.
The project envisaged in a letter of intent signed by the two companies would include development of a pipeline transportation system and sequestration site. Enbridge would develop, build, and operate the pipeline and OLCV the sequestration site. The companies would market transportation and sequestration services to third-party CO2 point-source emitters in the Ingleside, Tex., and Corpus Christi areas.
OLCV’s partnership with Enbridge follows carbon capture and sequestration (CCS) agreements with Natural Resource Partners LP to evaluate possible development of a 500-million tonne CO2 sequestration hub in southeast Texas and those with Enterprise Products Operating LLC and Weyerhaeuser Co. for sequestration projects on the Texas Gulf Coast and east of Baton Rouge, La., respectively.
Exploration & Development Quick Takes
Neptune adds reserves near Draugen field
Neptune Energy estimates that 6-22 MMboe of recoverable reserves were discovered at the Calypso exploration well on the Norwegian Continental Shelf, 14 km northwest of Draugen field and 22 km northeast of Njord A platform in PL 938. Initial analysis indicates commercial potential. The company will study development options using nearby infrastructure.
Well 6407/8-8S was drilled by Odfjell Drilling’s Deepsea Yantai semisubmersible rig to a vertical depth of 3,496 m. Reservoir targets were middle and lower Jurassic formations. The well encountered an estimated 8-m thick gas column and 30-m thick oil column in a 131-m thick Garn formation sandstone reservoir of good to very good quality. Calypso is Neptune Energy’s third discovery in 6 months on the Norwegian Continental Shelf.
Neptune Energy is operator (30%) with partners OKEA ASA (30%), Pandion Energy AS (20%), and Vår Energi ASA (20%).
Woodside advances Sangomar development
Woodside Energy Ltd. completed construction of the FPSO for Sangomar Phase 1 field development offshore Senegal. The vessel is now moving to Keppel Offshore & Marine Ltd.’s Tuas Shipyard in Singapore. Keppel will complete topsides integration and support pre-commissioning and commissioning activities.
The FPSO, a converted Very Large Crude Carrier, has been named after Senegal’s first president, Leopold Sédar Senghor. It will have a capacity to produce 100,000 b/d of oil.
Woodside let the FPSO supply contract to MODEC Inc. in 2020. Hull and marine works, external turret and topsides module installation, and conversion work on the vessel were completed by COSCO Shipping Heavy Industry (Dalian) Co. Ltd. Topsides modules were fabricated by both COSCO and by BOMESC Offshore Engineering Co. Ltd. in Tianjin. The external turret mooring system was fabricated by Penglai Jutal Offshore Engineering Heavy Industries Co. Ltd.
Phase 1 of Sangomar field development—Senegal’s first offshore oil project—is currently about 70% complete. Development includes the FPSO, 23 wells, and supporting subsea infrastructure to tie-in subsequent phases.
Sangomar field, formerly known as SNE field, was discovered by FAR in November 2014 in 1,100 m of water about 100 km south of Dakar. Recoverable oil reserves are estimated at nearly 630 million bbl.
Woodside is operator with 82% interest. Société des pétroles du Sénéga (PETROSEN) holds the remaining 18%.
Equinor to tieback Verdande to Norne FPSO
Equinor Energy AS submitted a plan to the Norwegian Ministry of Petroleum for tieback of Verdande field in the Norwegian Sea to the nearby Norne FPSO.
The field is about 300 km southwest of the city of Bodø in North Norway and includes Cape Vulture and Alve North-East discoveries in 350-280 m of water. It will be developed with three wells connected via subsea tieback to the FPSO at Norne field. Oil will be transported by a tanker and the gas will be piped via Åsgard Transport to Kårstø.
According to the plan for development and operation (PDO), drilling is expected to start in fourth-quarter 2024, and production will launch a year later. The development start is dependent upon approval of the PDO.
Verdande has estimated recoverable reserves of 36.3 MMboe. Total investment at Verdande will be NOK 4.7 billion.
Equinor is operator of the Verdande license (59.3%) with partners PGNiG Upstream Norway (0.8%), Petoro (22.4%), Vår Energi (10.5%), and Aker BP (7%).
Drilling & Production Quick Takes
Central Petroleum’s Palm Valley-12 brought on line
Central Petroleum Ltd., Brisbane, has brought on stream its Palm Valley-12 development well in Palm Valley gas field in Amadeus basin of the Northern Territory.
The well did not reach its intended deep exploration target, but the fallback strategy of converting to a production well in the main P1 Pacoota sandstone reservoir has been justified, the company said.
PV-12 has now flowed at a stable rate of about 10 terajoules/day, which is 40% above pre-drill expectations.
Results from the PV-12 and PV-13 lateral wells provide confidence that the company can continue to convert 2C contingent resources into reserves and additional sales into the Northern Territory pipeline grid with connections into Eastern Australia, the company said.
Palm Valley field capacity is expected to approach the maximum plant capacity of 15 terajoules/day in mid-December when a scheduled compressor overhaul is completed.
PV-12 was drilled and connected under a joint venture of Central (50%), New Zealand Oil & Gas Ltd. (35%), and Cue Energy Resources Ltd. (15%).
Palm Valley field is a large anticlinal structure about 29 km long and 14 km wide about 100 km west of Alice Springs. The main Pacoota sandstone reservoir straddles the Cambrian-Ordovician age boundary.
Palm Valley-1 discovery well was drilled in 1965. Isolation and protracted land rights negotiations delayed production start. The field was brought on stream in 1983.
CNR targets 4% production growth in 2023
Canadian Natural Resources (CNR), Calgary, is targeting year-over-year production growth of 56,000 boe/d in 2023, or 4%, over 2022 targeted levels, based on the midpoint of production guidance of 1.330-1.374 MMboe/d.
The 2023 production mix is expected to consist of 44% light and synthetic crude oil, 29% heavy crude oil, and 27% natural gas based on the midpoint of its production guidance and a budget of $5.2 billion ($4.2 billion base capital, $1 billion strategic growth capital).
Liquids production, including synthetic crude oil, is targeted at 969,000-1,001,000 b/d. The company’s long life low decline production represents about 78% of its total targeted liquids production. Thermal and oil sands mining and upgrading production is targeted at 705,000-729,000 b/d, with the midpoint representing a 5% increase over 2022 targeted levels. Conventional exploration and production liquids production is targeted at 264,000-272,000 b/d, with the midpoint representing a 4% increase over 2022 targeted levels. Natural gas production is targeted at 2,170 MMcfd-2,242 MMcfd, with the midpoint representing a 5% increase over 2022 targeted levels.
Equinor to modify Oseberg to increase gas production
Equinor Energy AS and Oseberg license partners will invest NOK 10 billion in infrastructure upgrades to increase gas production and reduce CO2 emissions from the North Sea field. A plan was approved by the Ministry of Petroleum and Energy Dec. 1.
The plan calls for two new compressors to be installed on Oseberg Field Center to lower process pressure on the platform and increase remaining recoverable gas and oil reserves by 54%. The modifications will make Oseberg Norway’s third largest gas field after Troll and Snøhvit, measured in remaining reserves, the company said in a release Dec. 1.
Oseberg production emissions will be decreased through partial electrification of the field center and Oseberg South platform. The modifications are expected to reduce CO2 emissions by about 320,000 tonnes/year, the operator said.
So far, Oseberg has produced about 80% oil and 20% gas, but gas production has outweighed oil production since 2021. Annual gas exports from Oseberg have increased to about 8 billion cu m (bcm) in 2022 from about 3 bcm up to 2018. Gas accounts for about 80% of remaining recoverable reserves. The field is expected to produce 100 bcm of gas between 2022 and 2040.
Primary contracts have been let to Aibel for new modules and upgrades to Oseberg and to Nexans for delivery and installation of the subsea cable. The project is expected to be complete in 2026.
Equinor is operator at Oseberg (49.3%) with partners Petoro AS (33.6%), TotalEnergies EP Norge AS (14.7%), and ConocoPhillips Skandinavia AS (2.4%).
PROCESSING Quick Takes
ExxonMobil starts up polypropylene unit at Baton Rouge
ExxonMobil Corp. has completed and officially commissioned a new unit to double polypropylene production of the polyolefins plant at its more-than 500,000-b/d integrated refining and petrochemical complex in Baton Rouge, La. (OGJ Online Mar. 1, 2019).
At a total capital investment of more than $500 million, the new 450,000-tonne/year (tpy) polypropylene unit comes as part of the company’s plan to meet growing demand for high-performance, light-weight, and durable plastics, particularly for automotive parts that can help improve fuel efficiency and reduce vehicle emissions, ExxonMobil said on Dec. 6.
Announced ahead of the global pandemic outbreak and progressively completed amid the related economic downturn, the project started up according to planned cost and schedule, the operator said.
Last year, ExxonMobil also took final investment decision to proceed with its Baton Rouge Refinery Integrated Competitiveness (BRRIC) suite of projects, a 3-year initiative to modernize the complex by improving processing capability, increasing flexibility for meeting energy market demand, advancing overall site competitiveness, and installing technology for a voluntary 10% reduction of volatile organic compound emissions (OGJ Online, June 9, 2021).
According to the operator’s most recent update on the project issued in February 2022, all major equipment for BRRIC was ordered and deliveries under way, with engineering design on schedule and major portions already completed to enable ongoing construction activities, including structural, mechanical, and electrical installations.
Upgrades to refinery docks to allow loading of larger marine cargoes for export also were nearly completed as of February 2022, the company said.
According to an economic impact report for BRRIC completed by the Kathleen Blanco Public Policy Center at the University of Louisiana at Lafayette, the proposed $240-million investment in initiative projects would position the Baton Rouge refinery to better withstand global market challenges, support job retention, and help other regional ExxonMobil sites compete for additional capital investment.
In February, David Oldreive—ExxonMobil Baton Rouge’s refinery manager—said the BRRIC also aims to enable the Baton Rouge site to increase its competitiveness and flexibility while preparing its plants for future energy transition opportunities.
To date, the BRRIC remains on schedule to conclude construction activities by yearend 2023 or early 2024.
Aramco, PKN Orlen seal deal for Gdan´sk refinery partnership
Saudi Aramco has completed its purchase of a joint ownership stake in Polski Koncern Naftowy SA’s (PKN Orlen) 10.5-million tonnes/year (tpy; 210,000-b/d) refining complex in Gdan´sk, Poland.
As part of the transaction finalized on Nov. 30, Aramco acquired a 30% equity interest in the Gdan´sk refinery and a 100% stake in the site’s associated wholesale business, the joint-venture partners said in separate releases.
PKN Orlen will retain a 70% stake in Gdan´sk and remain the refinery’s operator.
Alongside finalizing the refinery partnership, the companies also signed an agreement under which PKN Orlen, Aramco, and Aramco’s majority-held Saudi Arabian Basic Industries Corp. (Sabic) will assess the technical and economic feasibility of jointly developing a potential petrochemical project at Gdan´sk that—first revealed in July 2022—would involve construction of an integrated chemical complex at the refinery consisting of a large-scale mixed-feed steam cracker and downstream derivatives units.
The companies additionally finalized a crude oil sales agreement under which Aramco will supply about 45% of PKN Orlen’s total crude oil feedstock requirements for its overall refining system that—following the operator’s merger with Grupa Lotos in August 2022—includes seven refineries with a combined crude processing capacity of 46 million tpy.
On Jan. 12, 2022, Mohammed Al-Qahtani—senior vice-president of Aramco’s downstream business—said the then-proposed supply agreement would involve delivery of about 400,000 b/d of Arabian crude into PKN Orlen’s system.
Ongoing partnership
The late-November transactions between the companies follows PKN Orlen’s earlier announcements of proposed future cooperation agreements with Aramco, all of which were contingent upon official completion of the PKN Orlen-Grupa Lotos merger.
In a June presentation to investors, PKN Orlen confirmed a series of planned undertakings with Aramco that—in addition to the Gdan´sk refining-petrochemical plans and crude supply agreements—were to include:
- Implementation of Aramco technology to optimize refining and logistics at PKN Orlen manufacturing sites.
- Implementation of Aramco and Sabic technologies at PKN Orlen refineries to achieve deeper conversion of crude volumes required for petrochemical operations.
- Additional, unidentified investments with Aramco into petrochemical production.
- Partnership with Aramco on projects involving production and transportation of green hydrogen and ammonia, as well as reduction of carbon footprints at refining and petrochemical sites.
- Increased partnership on technology research and development activities.
In 2016, Aramco began delivering PKN Orlen crude oil supplies under the operator’s first long-term supply agreement with a Mideast Gulf producer, Al-Qahtani said.
TRANSPORTATION Quick Takes
APA Group cancels plan for Western Slopes gas pipeline
APA Group and Santos Ltd. have abandoned plans to construct the Western Slopes pipeline project to carry gas from Santos’s proposed Narrabri coal seam gas project in northern New South Wales to the Australian domestic grid.
The mutual agreement was made following Santos’ August acquisition of Hunter Gas Pipeline Pty Ltd., a company that owns an approved route for a buried gas pipeline from Wallumbilla in southeast Queensland to Newcastle on the central New South Wales coast. The route passes close to the Narrabri project.
APA has informed landholders along the route of the proposed 460-km Western Slopes Pipeline of the decision.
Santos’ alternative, the proposed 820-km Hunter Gas Pipeline (HGP), is a longer distance, but will create a second north-south link by connecting the Wallumbilla hub near Roma in Queensland with Newcastle and further south to Sydney, Santos said.
Narrabri gas, which is 100% committed to the domestic market, would be linked via a short connection to the main line. Offtake points along HGP at regional towns are planned.
HGP has recived planning approval and construction is expected to begin early in 2024.
Appraisal drilling at Narrabri is expected to begin by yearend, pending native title and environmental management plan approvals.
Once fully operational, Narrabri could deliver more than half of New South Wales’ gas demand.
CNOOC completes Shen’an coalbed methane pipeline
China National Offshore Oil Corp. Ltd. (CNOOC) has fully connected its 5-billion cu m/year Shen’an coalbed methane pipeline and declared it ready for operation. The 623-km pipeline starts in Shenmu, Yulin City, Shanxi Province and ends at Anping County, Hengshui City, Hebei Province.
CNOOC says pipeline startup will help maximize natural gas production from Qinshui basin and the eastern edge of Erdos basin, both of which face relatively low well productivity and relatively high production costs. As of end-2021 the two production areas represented 1.5% of its total reserves and 2.0% of its production, according to CNOOC.
Zhonglian Huarui Natural Gas Co. Ltd. built and will operate Shen’an pipeline. China United Coalbed Methane Co. Ltd., a CNOOC subsidiary, holds 51% interest in Zhonglian Huarui. Huasheng Xinneng Gas Group Co. Ltd. holds 49%.
Coastal GasLink costs increase, end-2023 completion targeted
TC Energy Corp.’s 1.7-bcfd Coastal GasLink pipeline in Western Canada continues to face cost pressures relate to its labor costs and the shortage of skilled labor, along with contractor underperformance and disputes, the company said in advance of its annual investor day meeting. It also cited drought conditions and erosion and sediment control issues as factors leading to an expected increase in project costs.
The 670-km, 48-in. OD pipeline will carry Western Canadian Sedimentary Basin natural gas to LNG Canada’s planned 14-million tonne/year plant in Kitimat, BC. It is 80% complete, according to TC Energy, which is targeting end-2023 mechanical completion.
Enterprise receives MARAD record of decision for GOM offshore oil terminal
Enterprise Products Partners (EPP) LP’s 85,000-bbl/hr Sea Port Oil Terminal (SPOT) has received its record of decision (ROD) from the US Department of Transportation’s Maritime Administration (MARAD). The terminal, for which EPP hopes to receive a license by 2023, is designed to load tankers up to 2-million bbl in capacity (VLCC), which would take 1 day at SPOT’s designed loading rate.
SPOT consists of a fixed-platform, deepwater port in the Gulf of Mexico about 30 nautical miles off the coast of Texas in 115 ft of water. It will be connected to 4.8 million bbl of onshore crude oil storage in Brazoria County, Tex., by two 36-in. bidirectional pipelines.
EPP said SPOT’s design will reduce carbon dioxide and volatile organic compound (VOC) emissions by 65% and 94%, respectively, compared with current industry practices.
MARAD and the US Coast Guard led the 4-year environmental review of this project. ROD includes reviews by more than a dozen Federal agencies, including the Army Corps of Engineers and Environmental Protection Agency, as well as reviews and approvals by the State of Texas. Remaining conditions include routine construction, operating, and decommissioning guarantees, submission of public outreach, wetland restoration and VOC monitoring plans, and other state approvals.