GENERAL INTEREST Quick Takes
Union strike at Shell’s Prelude vessel ends
The strike by the Australian Workers’ Union and the Electrical Trades Union at Shell Australia’s Prelude floating LNG vessel in Browse basin offshore Western Australia has ended with the parties reaching agreement over a wage deal.
The industrial action which lasted 76 days and resulted in missed LNG cargos worth about $1.5 billion (Aus.), has been resolved with a new ‘in principle’ enterprise bargaining agreement.
“The process to formally lift the work bans in place under the Protected Industrial Actions is expected to be completed shortly, which will enable the (Prelude) [vessel] to commence the process to prepare for a hydrocarbon restart,” Shell said.
Mediation by the Fair Work Commission concluded earlier this week with an agreement that includes a job security clause that Shell cannot reduce the number of employees operating the vessel by employing contractors.
Shell will work to return Prelude FLNG to safe and stable production, although no date has been set for bringing the field back on stream.
Australia opens 2022 offshore exploration licensing round
The Australian government has opened the 2022 offshore exploration permit licensing round with the offer of 10 blocks across four offshore basins.
Bid closing is Mar. 2, 2023.
The new round comprises:
- Three blocks in Bonaparte basin (2 in Malita Graben subbasin, 1 in Vulcan subbasin).
- Three blocks in Browse basin (2 in Caswell subbasin, 1 in Barcoo subbasin).
- Three blocks in Carnarvon basin (2 in Dampier subbasin, 1 on Exmouth Plateau).
- One block in Gippsland basin.
Caswell subbasin areas include the Argus gas discovery, while the Dampier subbasin release contains small oil accumulations. Little work has been done in Malita or Barcoo subbasina, but the Gippsland basin release contains interest in untested potential in deep parts of the stratigraphic column.
INPEX-led JV wins storage assessment permit offshore Australia
The Bonaparte CCS Assessment joint venture of INPEX Corp., TotalEnergies SE, and Woodside Energy Ltd. has been awarded a greenhouse gas storage assessment permit off the northwest coast of Australia to carry out evaluation and appraisal work on Block G-7-AP for geological storage of carbon dioxide (CO2). Appraisal work will begin in 2023.
The block lies in Bonaparte basin off the northwestern coast of the Northern Territory. Water depth at the block is 30-75 m.
By enabling permanent CO2 sequestration in the region, this project complements existing solutions to avoid and reduce greenhouse gas emissions from the INPEX-operated Ichthys LNG, an 8.9-million tonne/year LNG plant near Darwin, Northern Territory,
INPEX is operator of the Bonaparte CCS Assessment joint venture (53%) with partners TotalEnergies (26%) and Woodside (21%).
Maha enters Oman farmout deal with Mafraq Energy
Maha Energy (Oman) Ltd. agreed to farm out 35% of its 100% operated interest in Block 70 onshore Oman to Mafraq Energy LLC. Maha will hold 65% and continue as operator of the oil-bearing block, which contains Mafraq oil field.
Mafraq Energy will reimburse Maha for its prorated share of all past costs including the signature bonus, Maha said in a release Aug. 8. Mafraq also will be required to pay its share of all future expenditures on Block 70.
Immediate plans for Mafraq field include drilling six wells to obtain reservoir information to aid in developing a field development plan. Mobilization of the drilling rig is scheduled for October.
The Mafraq structure is a delineated heavy oil field that was extensively tested by Petroleum Development Oman in 1988 and 1991. The field tested 15,700 bbl of 13° API oil over a period of 24 days using a progressive cavity pump (PCP) from a single well. The test well, MF-5, tested 100% oil for less than 1 day after which water production stabilized at around 25%.
According to Chapman Petroleum Engineering Ltd., the field may hold about 35 million bbl of recoverable oil.
The agreement is subject to Government approval in Oman.
Exploration & Development Quick Takes
Eni discovers gas offshore Cyprus
Eni SPA will drill another exploration well on Block 6 offshore Cyprus to investigate resource upside and evaluate development options following a gas discovery 160 km offshore in 2,287 m of water. Studies on fast-track development options are already ongoing, the company said in a release Aug. 22.
Cronos-1, the fourth exploration well drilled by Eni Cyprus and the second well in Block 6, encountered several good quality carbonate reservoir intervals and confirmed overall net gas pay of more than 260 m, the company said.
Calling the discovery significant, Eni assigned a preliminary estimate of about 2.5 tcf gas in place.
Eni is operator at of the block with 50% interest. TotalEnergies SE holds the remaining 50%.The discovery comes on the heels of the Calpyso-1 gas discovery in 2018.
Santos takes FID at Pikka oil project, Alaska
Santos Ltd. has taken a positive final investment decision to proceed first phase development of the Pikka oil project on the North Slope of Alaska.
The $2.6 billion project is expected to produce 80,000 b/d of oil when it comes on stream in 2026.
Santos gained the Pikka asset along with its acquisition of Oil Search Ltd. in December 2021.
The development will comprise a single small footprint drilling pad with electrified field operations and will use the existing Kuparuk transportation pipeline and the Trans-Alaskan pipeline system.
Pikka reserves have been estimated at 397 million b/o.
Development is supported by the State of Alaska, the North Slope Borough, landowner company Kuupik Corp., and the Arctic Slope Regional Corp.
Santos has entered memoranda of understanding with Alaska Native corporations to deliver carbon offset projects, including an alliance with ASRC Energy Services on leading technology development for carbon solutions in the Arctic.
Santos is operator of the Pikka Unit with 51% interest. Repsol holds 49%.
LLOG lets contract for Salamanca project
LLOG Exploration Offshore LLC has let a contract to Audubon Engineering Co. LP to support its Salamanca floating production system (FPS) project in the US Gulf of Mexico. LLOG is project manager for Salamanca FPS Infra LLC.
Work scope includes detailed design services as well as procurement, vendor equipment management, construction, pre-commissioning, and offshore commissioning support.
LLOG will repurpose the decommissioned Independence Hub semisubmersible production unit.
The hull, topside truss, cranes, and lifeboats will be reused with modifications. Other topside equipment, including piping, instrumentation, and electrical systems, will be new.
In July, LLOG let a contract to Exterran Corp. for technology to support the Salamanca project floating production unit.
The column-stabilized Salamanca FPS will sit in Keathley Canyon block 689 in 6,400 ft of water to tap the Lower Tertiary Leon and Castile discoveries. The platform will have processing capacity of 60,000 b/d of oil, 25,000 b/d of water, and 40 MMscfd of natural gas. Three initial development wells are planned, two on Leon field and one on Castile field. Initial production from the joint development is expected mid-2025.
LLOG will obtain ABS A1 notation for the platform to comply with CG-ENG Policy Letter No. 01-13, Alternate Design and Equipment Standard for Floating Offshore Installations.
LLOG is operator. Partners include Repsol and Beacon Offshore Energy.
Aker BP submits PDO for Trell, Trine offshore Norway
Aker BP submitted a plan for development and operation (PDO) for Trell & Trine field to the Ministry of Petroleum and Energy.
The PDO is the third submission in the Alvheim area of the North Sea in 1 year, following those of Frosk and Kobra East & Gekko, the company said in a release Aug. 10. Trell and Trine discoveries lie 24 km east of the Alvheim FPSO in production licenses 102 F/G, and 036E/F, respectively.
Trell & Trine development is planned with three wells and two new subsea installations (manifolds) to be tied back to existing infrastructure on East Kameleon and further on to the Alvheim FPSO. One of the three wells is Trell Nord, which although not yet proven, has a high likelihood of discovery, the operator said. When the Trell production well is drilled, the plan is to first prove hydrocarbons in Trell Nord, then drill the wells in Trell and Trine. The program will conclude with the production well in Trell Nord, the company continued.
A contract has been awarded to Subsea 7 SA for field development. Work scope includes engineering, procurement, construction, and installation (EPCI) of the pipelines, spools, protection covers, and tie-ins using vessels from Subsea 7. The production pipeline is a pipe-in-pipe design.
Project management and engineering will begin immediately at Subsea 7’s offices in Stavanger, Norway. Fabrication of the pipelines will take place at Subsea 7’s spoolbase at Vigra, Norway, and offshore operations are expected to take place in 2023 and 2024.
Subsea 7 values the contract at $50-150 million.
Total investment from Aker BP for the development is estimated at $700 million. Production start is expected in first-quarter 2025.
Recoverable resources in Trell & Trine are estimated to be 25 MMboe. When Trell and Trine are approved, the Alvheim area is expected to surpass 750 million bbl either produced or sanctioned for development, according to Aker BP.
Aker BP is operator. License partners are Petoro and LOTOS Exploration & Production Norge.
Drilling & Production Quick Takes
VAALCO Energy reduces 2022 production guidance
VAALCO Energy Inc. reduced 2022 guidance based on results from the South Tchibala 1HB-ST well in Etame field, offshore Gabon.
The well discovered two potential Dentale producing zones, Dentale D1 and Dentale D9. The Deep Dentale D1 sand interval was completed with a small frac pack.
This sand interval has good quality oil with low gas oil ratio that has produced an average of 150-200 b/d. Production rates have been below the minimum recommended operating range of the electrical submersible pump (ESP), which has required more frequent well cycling to prevent damage. Due to low flow volumes below the minimum recommended operating range of the ESP, the well will be intermittently flowed using well cycling to determine if production improvements will occur and to project future reserve recovery expectations.
Plans are to evaluate and recomplete the D9 interval during the next drilling campaign which should yield higher oil production rates based on analogy to the North Tchibala sands currently on production.
The well penetrated a thin section of the Gamba sand that is not economically viable to complete in this wellbore.
The Dentale D9 interval has an estimated original oil in place of 4-15 million bbl.
Primarily due to the South Tchibala 1HB-ST well performance, VAALCO’s full year 2022 net production guidance is being reduced by a net 750 b/d at the midpoint to a range of 9,000-9,500 net b/d.
VAALCO plans to drill additional wells in the 2021-2022 drilling campaign that could positively impact production toward yearend and into 2023.
VAALCO is operator in Etame Marin block (63.6%) with partners Addax Petroleum Co. (33.9%) and PetroEnergy Resources Corp. (2.5%).
COPL advances Wyoming drilling operations
Canadian Overseas Petroleum Ltd. (COPL) plans to drill one horizontal Frontier 1 well and two horizontal Frontier 2 wells as part of its 2022-23 drilling campaign in Converse and Natrona counties, Wyoming.
COPL will evaluate three Frontier 1 sands through coring and open hole testing in the first horizontal well in the Barron Flats Federal Deep Unit targeting the Frontier 2 Formation during fourth quarter 2022. Following the completion of this well, the company will drill and complete a horizontal well in the Frontier 1 in the Barron Flats Federal Deep Unit. In addition, the COPL has identified suitable well bores at its Cole Creek Unit to recomplete in the Frontier 1 for production in fourth-quarter 2022. As such, the current resource estimates as outlined are likely to be revised or reclassified after this evaluation program.
The company plans to drill two Frontier 2 horizontal wells in its 2022-23 drilling campaign starting in this year’s fourth quarter. The first Frontier 2 horizontal well will be in the Barron Flats Federal Deep Unit offsetting its 2021 BFU Fed 14-30VF discovery well drilled in third-quarter 2021 which intersected Frontier 1, Frontier 2, and Lower Cretaceous Dakota formation sands. The second Frontier 2 horizontal well will be drilled on an existing permitted location in the Cole Creek Unit targeting proven 1P and probable 2P undeveloped reserves.
A report from Ryder Scott estimates 0.99 billion bbl OOIP for Frontier 1, Frontier 2, and Dakota, which is less than the 1.275-1.64 billion bbl COPL originally estimate based on results from the 14-30V discovery well.
COPL’s current working interest on its operated leasehold block ranges from 55-85%.
Neptune Energy spuds Rhine Valley well
Neptune Energy Group Ltd. has spudded a new production well at Römerberg oil field in the Rhine Valley of southwestern Germany.
The well, the ninth production well in the field, is being drilled with a rig operated by Drilltec, with final expected vertical depth of about 2,180 m. TD is expected to be reached in October, and production is expected to come onstream in fourth quarter this year.
Average production from the field is about 2,000 boe/d. An application to increase production from the field, currently limited to 500 tons/day of crude oil, is in the final stages. Once approved, Neptune intends to progress plans to drill additional production wells to develop the reservoir further.
Neptune Energy is operator at Römerberg (50%) with partner Palatina GeoCon (50%).
Shell plans Crux drilling for gas backfill to Prelude
Shell Australia Pty. Ltd. has submitted an environment plan (EP) to the National Offshore Petroleum Safety and Environment Management Authority (NOPSEMA) for development drilling on Crux natural gas field in production license AC/L10 in Browse basin off Western Australia. The EP is inclusive of drilling template and docking pile installation, the use of a mobile offshore drilling unit, in-field support vessels and helicopters, remote operated vehicles and well suspension, and contingent sidetrack and plugging and abandonment activities. It will be the first significant infield work on Crux.
Shell took final investment decision (FID) on Crux in May 2022. The company intends to use Crux gas as backfill for the Prelude floating LNG (FLNG) vessel 160 km to the southwest. The first environmental approval for overall development of Crux was granted by NOPSEMA in August 2020.
The company expects drilling template installation to occur second-quarter 2023 about 3 months ahead of arrival of the drilling unit. Drilling of an initial five wells will take about 10 months with an additional 10-month contingency drilling period. Wells will then be temporarily suspended, and subsequent completions will follow topside installation. Well completion activity will be the subject of a separate EP, Shell said.
The Crux development will have capacity to supply Prelude with up to 550 MMcfd of gas via a linking pipeline. The Crux platform will be remotely operated from the Prelude FLNG vessel. First gas is expected in 2027.
Shell is operator of Crux with 82% interest, SGH Energy holds 15% and Osaka Gas 3%.
PROCESSING Quick Takes
Petrobras provides update on sales process for three refineries
Petróleo Brasileiro SA has officially started the nonbinding phase in its program to sell three of its Brazilian refineries and associated logistics assets, the sales of which were previously delayed to accommodate revisions to divestment plans.
As of Aug. 19, Petrobras began notifying potential buyers that they have been approved to participate and submit nonbinding proposals in the sale process for the refineries and related assets, including the 130,000-b/d Refinaria Abreu e Lima (RNEST) refinery; 208,000-b/d Refinaria Presidente Getulio Vargas (REPAR) refinery; and 208,000-b/d Refinaria Alberto Pasqualini (REFAP) refinery, the operator said.
A definitive timeframe for the nonbinding phases for the proposed sales, however, was not revealed.
Restart of sale processes for the refineries follows a series of delays to the divestment cycle in 2021 resulting from a mix of issues involving unqualified buyers expressing interest in the assets, qualified buyers failing to submit binding bids for the sites, and initial binding proposals falling short of Petrobras’ economic-financial evaluation for the assets.
Located in Ipojuca, Pernambuco, in northeast Brazil and representing 5% of the country’s total refining capacity, the RNEST refinery —which has the potential to double its capacity to 260,000 b/d with startup of a second 130,000-b/d processing train—includes a terminal with crude and product storage capacities of 4.706 million bbl and 5.496 bbl, respectively, as well a 101-km set of short pipelines.
Located in Araucária, Paraná, in southern Brazil and representing 9% of the country’s total refining capacity, the REPAR refinery—which caters mainly to the local markets of Paraná, Santa Catarina, São Paulo, and Mato Grosso do Sul—includes five terminals equipped to store 3.472 bbl of crude and 6.034 bbl of finished products. Logistics infrastructure assets involved in the sale also will include a 476-km pipeline network.
Located in Canoas, Rio Grande do Sul, in southern Brazil and representing 9% of the country’s total refining capacity, the REFAP refinery—which caters mainly to the local markets of Rio Grande do Sul, Santa Catarina, and Paraná—includes two terminals with crude and product storage capacities of 3.652 million bbl and 5.820 million bbl, respectively, as well as a set of pipelines totaling 260 km.
Despite its divestment program to shed nearly 50% (1.1 million b/d) of Brazil’s national refining capacity, Petrobras—as part of its portfolio management strategy and improved allocation of its capital—said it will continue to concentrate investments on assets with lower greenhouse gas (GHG) emissions that have proved more competitive over the years.
The investments come as part of the planned $6.1 billion Petrobras intends to spend on its refining business under the company’s 2022-26 strategic plan.
Alongside expanding existing refining capacity, refining-related investments will focus on initiatives to increase efficiency and operational performance of Brazilian refineries not involved in operator’s divestment portfolio, which include the:
- 434,000-b/d Refinaria de Paulínia (REPLAN) refinery in Paulínia, São Paulo, Brazil.
- 239,000-b/d Duque de Caxias (REDUC) refinery in the Baixada Fluminense area of Brazil’s Rio de Janeiro state.
- 252,000-b/d Refinaria Henrique Lage (REVAP) refinery in São José dos Campos, São Paulo.
- 170,000-b/d Refinaria Presidente Bernardes (RPBC) refinery in Cubatão, São Paulo.
- 57,000-b/d Refinaria de Capuava (RECAP) in Mauá, São Paulo (OGJ Online, Mar. 9, 2021).
TRANSPORTATION Quick Takes
Alaskan LNG import project granted FERC extension
Trans-Foreland Pipeline Co., a Marathon Petroleum Corp. subsidiary, has received a 3-year extension from the US Federal Energy Regulatory Commission (FERC) for converting its Kenai, Alas., LNG plant into an import terminal. FERC’s initial December 2020 order authorizing the project called for it to be available for service by Dec. 17, 2022. It now must be ready by December 2025.
Trans-Foreland would import up to four cargoes of LNG per year and use its boil-off gas management system to deliver imported gas to the 68,000-b/d Kenai refinery. LNG has not been exported from Kenai since 2015. The plant has been maintained in a warm idle state since 2018.
The company stated that the “onset and duration” of the COVID-19 pandemic had created adverse economic and logistical conditions that slowed commercial progress and precluded Trans-Foreland from making its final investment decision (FID) for the terminal. Moreover, according to Trans-Foreland, the uncertainty and volatility in the LNG market have made it difficult to secure a supply arrangement providing the financial certainty necessary to make FID and move forward.
Trans-Foreland asserted that the project remains commercially viable and that it is actively seeking suitable supplies and monitoring LNG markets and that it will take FID once supplies have been secured. The company has not begun construction of the terminal.
Alaska Gasline Development Corp. (AGDC), meanwhile, is seeking feed gas suppliers for the 20-million tpy plant it is developing in Nikiski, Alas., while Gov. Mike Dunleavy talks with Japan-based potential customers regarding the plant’s output. AGDC expects FID by early 2024 to meet a targeted 2027 startup date.
Freeport lets contract for liquefaction plant reconstruction, plans November restart
Freeport LNG Development LP, Houston, updated restart plans for its 15-million tonne/year liquefaction plant on Quintana Island, Tex., and has contracted Kiewit Energy Group Inc. to perform the engineering, procurement, and reconstruction activities.
The company identified a recovery plan for reinstatement of partial operations, having completed a detailed assessment of alternatives for resuming operations at the LNG plant following a shutdown after a June 8 explosion at the site, the company said in a release Aug. 23.
Initial restart is expected to begin early to mid-November, with a ramp up to a sustained level of at least 2 bcfd (85% of export capacity) by the end of November.
The recovery plan will utilize Freeport LNG’s second LNG loading dock as a lay berth until loading capabilities at the second dock are reinstated in March 2023, at which time it anticipates being capable of operating at 100% capacity.
Woodside begins building Pluto LNG Train 2
Woodside Energy Group Ltd. and Bechtel Corp. have begun work on 5-million tonne/year (tpy) Pluto LNG Train 2 near Karratha, Western Australia. The train at Woodside’s existing 3-million tpy Pluto LNG onshore plant will process gas from its Scarborough offshore development in Carnarvon basin, 375 km offshore.
Bechtel will perform project engineering, procurement, and construction and has begun site preparation, with initial earthworks in laydown and storage areas to begin by yearend. Woodside expects loading of first cargo in 2026.
Construction of Train 2 will occur within existing Pluto LNG boundaries. A 225-terajoule/day gas plant will also be built to supply domestic customers.
Woodside last month let a contract to acquire a 4D baseline seismic survey over Scarborough and Jupiter natural gas fields on the Exmouth Plateau offshore Western Australia. The company estimates Scarborough dry gas reserves of 11.1 tcf. A 430-km pipeline will deliver gas to Pluto Train 2.
Development of Scarborough will include installation of a semisubmersible floating production unit (FPU) with eight wells drilled in the initial phase and 13 wells drilled over the life of the field. All wells will be tied back to the FPU, moored in 950 m of water.
TotalEnergies lets FEED contract for Papua LNG plant
TotalEnergies SE has let a front-end engineering design (FEED) contract to Technip Energies for the operator’s Papua LNG project upstream production infrastructure in Papua New Guinea.
The operator in 2021 remobilized project teams for work on the project after a pause due to the COVID-19 pandemic (OGJ Online, May 5, 2021). The project is targeting a final investment decision (FID) around the end of 2023, and a start-up at the end of 2027.
The 5.6-million tonne/year (tpy) Papua LNG plant will liquefy gas from the onshore Elk and Antelope fields in Block PRL-15. Gas produced by the fields is expected to be transported by a 320 km onshore/offshore pipeline to the Caution Bay site north of Port Moresby to be liquefied in two trains, which will be integrated into ExxonMobil’s existing 7.9 million tpy infrastructure in Caution Bay.
The project also incorporates a carbon capture and sequestration (CCS) scheme to remove field CO2 and reinject it into the reservoirs, the service provider said in a release Aug. 22.