GENERAL INTEREST Quick Takes
Saudi Arabia, Russia prolong voluntary oil production cuts to yearend
Saudi Arabia and Russia will extend voluntary oil production cuts—a combined 1.3 million b/d—until yearend 2023, the countries said Sept. 5. The move comes despite a recent rally in the oil market and expectations of tight supply conditions in the coming quarters.
“The Saudis previewed such an outcome last month with their longer, deeper statement but today’s move still managed to catch many market participants by surprise. Once again proves that Prince Abdulaziz (Saudi Energy Minister Prince Abdulaziz bin Salman) remains firmly in whatever-it-takes mode,” said RBC Capital Markets analyst Helima Croft.
Saudi Arabia began to voluntarily cut oil production by an additional 1 million b/d in July this year, subsequently evaluating extensions to the reduction plan on a monthly basis. Saudi Energy Minister Abdulaziz bin Salman previously emphasized the nation’s commitment to enacting required measures to stabilize the crude oil market. Moreover, it is widely acknowledged that the kingdom relies on oil prices hovering around $80/bbl to sustain its extensive budget and finance economic transformation initiatives.
In response to the news, oil prices surged with Brent crude surpassing $90/bbl for the first time since November 2022.
Ecuador initiates bidding process for largest gas field
State-owned EP Petroecuador has started an international search for an oil and gas company to continue development of Block 6, also known as Campo Amistad, Ecuador’s largest natural gas field. The field lies in the Gulf of Guayaquil, 55 km from Puerto Bolívar.
Petroecuador foresees a contract duration of 15 years, during which an awardee will invest more than $173 million to drill four exploratory wells, refurbish three wells currently in production, and construct new infrastructure. Petroecuador will continue as field operator and the State would pay a fee for the incremental extracted gas.
Ahead of the Aug. 18 registration deadline, Petroecuador said it had received 14 requests from interested companies. A contract award is expected in October 2023, with a contract signing expected in early November.
Petroecuador’s general manager, Ramón Correa, said private investment could lead to an increase in production to 73 MMcfd from the current 21 MMcfd to help meet a portion of Ecuador’s current demand.
Natural gas would be directed to the Termogas de Machala power plant, about 60 km from the wells, as well as the industrial sector.
Since 2002, Campo Amistad has been the country’s sole offshore development, consisting of four platforms, three wells, a dehydration plant, a helipad, and a 12-in. OD gas pipeline.
Certified proven and probable reserves at the field total 167.3 bcf, with prospective resources of 241 bcf, according to Petroecuador data.
INPEX, TotalEnergies acquire permit for long-term supply of Ichthys LNG
INPEX Corp. and TotalEnergies agreed to acquire 100% interest in the AC-RL7 permit off the northern coast of Western Australia from PTTEP with the aim of increasing long-term supply to the Ichthys LNG plant, in which both companies hold interest.
AC-RL7 covers about 418 sq km in the Timor Sea in water depth of 120-240 m. It lies about 250 km northeast of the Ichthys gas-condensate field, which supplies natural gas to the INPEX-operated Ichthys LNG project.
The permit to be acquired includes Cash and Maple gas and condensate fields, discovered in 2002 and 1989 respectively, and subsequently appraised by several wells. Field development is expected to contribute to the long-term supply of the Ichthys LNG plant, in which TotalEnergies is a 26% partner while INPEX and other Asian minority shareholders hold the remaining 74%.
The Cash-Maple project, which lies in the Ashmore Cartier territory about 680 km west of Darwin and 700 km northeast of Broome, contains an estimated 3.5 tcf of resources, according to PTTEP.
INPEX, through a newly established group company, INPEX Cash Maple Pty Ltd., will acquire operatorship and 74% of the participating interest held by PTTEP Australasia (Ashmore Cartier) Pty Ltd. in the block, the companies said in separate releases Aug. 21. TotalEnergies Exploration Australia Pty Ltd. will acquire the remaining 26% interest, in line with its equity in Ichthys LNG.
Exploration & Development Quick Takes
TotalEnergies launches second phase of Absheron gas field development
TotalEnergies has launched the second phase of Absheron gas field in the Caspian Sea, which is expected to increase the field’s production to 5.5 billion cu m/year (bcmy), in line with Azerbaijan’s ambition to supply the European market, TotalEnergies said in a release Sept. 1.
The news comes as part of the field’s inauguration ceremony, during which Patrick Pouyanné, chairman and chief executive officer of TotalEnergies, met in Baku His Excellency Ilham Aliyev, president of the Republic of Azerbaijan, as well as Mikayil Jabbarov, Minister of Economy and chairman of State Oil Co. of the Republic of Azerbaijan’s (SOCAR) supervisory board; Parviz Shahbazov, Minister of Energy; and Rovshan Najaf, president of SOCAR.
The parties discussed TotalEnergies’ projects in Azerbaijan, which, in addition to the launch of the second phase of Absheron development, include plans to participate in development of the country’s renewable energy potential under a memorandum of understanding signed in June to assess and develop 500 Mw of renewable wind and solar energies and energy storage systems for the national grid.
Production from the first phase of Absheron development began in early July and is currently producing 1.5 bcmy, TotalEnergies said.
Wintershall advances Maria Phase 2 development with template installation
Wintershall Dea Norge AS has advanced work on the second phase of Maria field development with installation of an additional subsea template on the seabed at Haltenbanken on the west coast of Norway.
By extending Maria field, installation of a new template supports Wintershall’s strategy of using nearby infrastructure to produce new volumes in Norway. Maria is one of four offshore fields currently operated by Wintershall Dea in the country, with more under development, the company said in a release Sept. 1.
The new six-slot template will accommodate three producing wells and one water injector for pressure support. The two spare slots will be available for future field development.
Maria, which was originally developed with two templates, came on stream in 2017. This next phase of the project is expected to add around 27 MMboe to the total field reserves. Maria Phase 2 is planned for start-up in 2025, extending life of the field to 2040.
TechnipFMC’s heavy subsea construction vessel, North Sea Atlantic, transported the 330-tonne template from Vestbase in Kristiansund in mid-Norway about 200 km to Maria field in the Norwegian Sea, where it was installed 300 m below the sea surface. TechnipFMC was awarded the integrated engineering, procurement, construction, and installation (iEPCI) contract for Maria Phase 2 in April 2022.
The Maria well stream goes to the Kristin platform. Water injection comes from Heidrun, while lift gas is provided from Åsgard B via Tyrihans subsea field. Processed oil is sent to Åsgard field for storage and export. Gas is exported via the Åsgard Transport System to Kårstø.
Wintershall is operator of Maria field with a 50% interest. Petoro AS has 30% and Sval Energi AS owns 20%.
Sonangol to start exploration work onshore Angola
Sonangol has started prep work to begin drilling and appraisal on Block KON11 in the Kwanza onshore basin in Cabo Ledo Commune, Luanda, Angola’s National Agency for Petroleum, Gas, and Biofuels (ANPG) said in a late August release.
The initial workplan, subject to the results of the first well, is expected to include one or more new wells with the primary focus being on the consortium moving directly to early oil production should the drilling program be successful, Corcel PLC said in a separate release. Corcel acquired 90% interest in Atlas Petroleum Exploration Worldwide Ltd. (APEX), and with it, working interests in KON 11/12/16 blocks onshore Angola (OGJ Online, May 24, 2023).
ANPG said, depending on the drilling outcome, the consortium could proceed with geological and geophysical data surveys with the aim of improved mapping of the block’s structures, without jeopardizing the preliminary development aimed at restarting production.
KON11 is considered a brownfield development and includes the historically producing Tobias field, drilled and developed by Petrofina in the 1960s and 1970s, and inactive since the late 1990s. Work on the field included 12 vertical wells. Revised interpretation of the existing structures along with the application of modern drilling and completion technology, possibly including horizontal drilling, could lead to a higher original oil in place in the reactivated field, according to the operator and Corcel.
The traditional Tobias field reservoir is in the Binga limestone, with 4-14% porosity at a depth of about 700 m. Historic peak production was 17,500 b/d with 29 million bbl produced over the life of the field, Corcel said. The company estimates unproduced contingent oil resources of 65 million bbl.
Operations on the block are led by a consortium of Sonangol Pesquisa e Produção (operator, 30%), Brite’s Oil & Gas (25%), Grupo Simples Oil (20%), APEX (20%), and Omega Risk Solutions Angola (5%). The concession was awarded in 2020.
Drilling & Production Quick Takes
Eni starts oil, gas production from Baleine field
Eni has started oil and gas production from Baleine field, offshore Ivory Coast.
Initial phase production is through the Baleine FPSO, a refurbished and upgraded vessel (formerly Firenze) capable of handling up to 15,000 b/d of oil and around 25 MMscfd of associated gas (OGJ Online, Apr. 6, 2023).
The start of Phase 2 is expected by end-2024, also through a renovated FPSO. This second phase is expected to increase field production to 50,000 b/d of oil and about 70 MMscfd of associated gas. The third development phase aims to elevate field production up to 150,000 b/d of oil and 200 MMscfd of gas.
Production comes less than 2 years after the discovery from the NFW Baleine 1X well in Block CI-101 in September 2021, and about a year and a half after the final investment decision. This marks the first emissions-free Scope 1 and 2 production project in Africa, the company said.
Baleine field is the largest hydrocarbon discovery in Ivory Coast, with 2.5 billion bbl of estimated oil in place and 3.3 tcf of estimated associated gas. Gas is delivered to shore via a newly built export pipeline.
Baleine field extends over Blocks CI-101 and CI-802. Eni serves as operator with partner PetroCi Holding.
SDX Energy spuds Moroccan well
SDX Energy PLC spud the Ksiri-21 well in Sebou Central, Gharb basin, Morocco.
The vertical development well will be drilled to a planned total depth of about 1,950 m. Using existing 3D seismic, the well is targeting a well-defined prospect within the main Hoot formation, which is the main producing sand in the area.
SDX has drilled over 20 production wells in the same basin. As such, this new well presents a low-risk step-out location and could be immediately brought into production, the company said.
SDX holds a 75% operated working interest across a Moroccan portfolio which includes the Sebou Central, Gharb Occidental, Moulay Bouchta Ouest, and Lalla Mimouna Sud exploration permits, plus several exploitation concessions containing producing wells.
OGDCL increases hydrocarbon production from Baratai block well
Oil & Gas Development Co. Ltd. (OGDCL) in Pakistan has increased hydrocarbon production from the Siab-1 well in the Baratai block of Kohat district, Khyber Pakhtunkhwa province.
Since its production start in January 2022, the well has recorded flow rates of 125 b/d of condensate and 6.2 MMscfd of gas at a well head flowing pressure (WHFP) of 1,700 psi. It is connected to OGDCL-operated Dhok Hussain gas field.
The company has applied a rigless intervention in the Lockhart formation and increased the well’s output by 14.3 MMscfd of gas and 265 b/d of oil at a WHFP of 4,300 psi. The additional gas is being supplied to the Sui Northern Gas Pipelines Ltd. (SNGPL) network. The well’s total production as of Aug. 28 is 20.5 MMscfd of gas and 390 b/d of oil.
OGDCL is operator of the well with 97.5% interest in the joint venture, while the Khyber Pakhtunkhwa Oil & Gas Co. Ltd. (KPOGCL) holds the remaining 2.5%.
PROCESSING Quick Takes
bp lets contract for unit at Kwinana biorefinery
bp PLC has let a contract to Technip Energies NV to supply a new hydrogen production unit in support of subsidiary bp Australia Pty. Ltd.’s proposed project to produce renewable diesel and sustainable aviation fuel (SAF) at its former oil refinery in Kwinana, south of Perth, on Australia’s western coast.
Technip Energies will deliver engineering, procurement, and fabrication (EPF) of a modularized unit equipped with its proprietary steam methane reformer (SMR) technology for production of 33,000 cu m/hr of hydrogen based on a feedstock of either natural gas or biogas produced by the planned Kwinana biorefinery, the service provider said on Aug. 29.
Hydrogen produced by the unit will be returned to the biorefinery for use in production of renewable fuels such as SAF and biodiesel using a feedstock of yet-to-be specified renewable materials.
While it did not reveal a timeframe, Technip Energies valued the EPF contract between €50 million and €250 million.
The proposed hydrogen production unit comes as part of bp’s ongoing plan to repurpose the site of its 2021-idled conventional refinery into a biorefinery that will be integrated with Kwinana’s existing import terminal and plans for green hydrogen production, H2Kwinana, currently under evaluation.
Designed to support the operator’s broader aim to achieve net-zero emissions by 2050, bp recently said environmental and social impact studies remain under way for the proposed Kwinana energy hub, which would house both the biorefinery and H2Kwinana.
In the latest project descriptions on the operator’s website, bp said it planned to begin leveraging the idled refinery’s infrastructure and repurposing some redundant processing units to advance the biorefinery project, as well continue sharing and developing project plans with regulators, stakeholders, and the surrounding community, including the Watji Nyoongar People, traditional owners of the land hosting the Kwinana operations.
AltaGas to acquire gas processing, natural gas storage from Tidewater Midstream
AltaGas Ltd. has agreed to acquire from Tidewater Midstream and Infrastructure Ltd. certain natural gas processing plants and natural gas storage infrastructure in Canada for $650 million.
Through the deal, AltaGas would acquire the Pipestone Natural Gas Processing Plant Phase I and Phase II expansion project; the adjacent Dimsdale natural gas storage; the Pipestone condensate truck-in/truck-out terminal; and the associated gathering pipeline systems.
Pipestone Phase I is a modern sour deep-cut natural gas plant with 110 MMcfd of processing capacity and 20,000 b/d of liquids handling capacity in the Alberta Montney. It is 100% contracted with about 85% of the volumes coming from long-term take-or-pay contracts. The plant includes 67 km of natural gas gathering pipelines tied into key production regions and provides egress connections to the NGTL and the Alliance pipeline systems.
Pipestone Phase II is a fully permitted, shovel-ready expansion project expected to provide an additional 100 MMcfd of sour deep-cut natural gas processing capacity and an additional 20,000 b/d of liquids handling capabilities. Pipestone Phase II is expected to come onstream in 2025.
The Pipestone transaction expands AltaGas’s footprint in the Alberta Montney and de-risks global exports by adding long-term LPG supply, including 3,500 b/d in 2024, 6,500 b/d in second-half 2025, and the potential for 11,500 b/d over the long-term through incremental processing capacity additions beyond Pipestone Phase II, AltaGas said in a release Aug. 31.
Dimsdale storage, which lies east of Pipestone I and II, has current working gas capacity of 15 bcf, which can be increased to 69 bcf.
The deal is contingent on Tidewater and AltaGas making a positive final investment decision (FID) for the Pipestone Phase II project. To help reach FID, the companies will create a new joint venture to advance final steps required to develop and construct the project. JV terms permit the parties to continue to collaborate on Pipestone Phase II, even if the acquisition does not proceed, AltaGas said.
TRANSPORTATION Quick Takes
All Woodfibre LNG export production now committed to bp
bp Gas Marketing Ltd. (BPGM), a wholly owned indirect subsidiary of bp plc, has entered its third long-term liquefied natural gas (LNG) offtake contract from the 2.1-million tonne/year (tpy) Woodfibre LNG plant in British Columbia, Canada.
With the additional contract to offtake 0.45 million tpy of LNG for 15 years on a free on board (FOB) basis, all the LNG production from the Woodfibre LNG export plant is now committed for sale to bp, with firm offtake totaling 1.95 million tpy and the remainder on a flexible offtake basis, the company said in a release Sept. 5.
bp, which aims to build an LNG portfolio of 30 million tonnes by 2030, also has committed to providing transportation of natural gas to the Woodfibre LNG export plant during the 15-year contact term.
Woodfibre LNG is scheduled to begin construction in September with operations expected to begin in 2027.
The Woodfibre LNG project is owned by Woodfibre LNG LP, owned 70% by Pacific Energy Corp. (Canada) Ltd. and 30% by Enbridge Inc. (OGJ Online, Aug. 2, 2022; Nov. 23, 2021).
Woodfibre LNG will source its natural gas from Pacific Canbriam Energy, a subsidiary of Pacific Energy Corp. Ltd., and expects to achieve net zero status by 2027 in part through use of electric compressors using renewable hydroelectricity from BC Hydro.
Venture Global to expand long-term LNG production
Venture Global LNG plans to increase its nameplate LNG export capacity to more than 100 million tonnes/year (tpy) from 70 million tpy across its current and future projects in and outside of Louisiana.
To support the long-term expansion plan, Venture Global has expanded its master equipment supply agreement with Baker Hughes for the delivery of additional liquefaction train systems and power island systems for future LNG export projects, the service provider said Sept. 5.
Venture Global continues to advance projects. Cargoes originating from its Calcasieu Pass project have been delivered to 24 countries and accounted for about 10% of the LNG exported from the US to Europe in 2022 and 2023.
The company has taken final investment decision (FID) on both phases of its 20 million tpy nameplate Plaquemines LNG plant, which is on target to produce first LNG in 2024. By early September, Plaquemines LNG will have received the first four liquefaction train modules (Blocks 1 and 2) and the roof will be raised on its third LNG storage tank.
Construction of the CP2 LNG plant is expected to begin later this year following receipt of FERC authorization. To date, 9.25 million tpy of CP2 LNG’s 20 million tpy nameplate capacity has been sold under 20-year agreements.
Baker Hughes provided LNG technology solutions to the Calcasieu Pass LNG plant, which began production in January 2022, and will provide the same to the currently under-construction Plaquemines LNG plant, the company said.
Berkshire Hathaway Energy completes acquisition of additional Cove Point LNG stake
Berkshire Hathaway Energy has completed a $3.3-billion deal to acquire Dominion Energy’s 50% limited partnership stake in Cove Point LNG LP, resulting in a total ownership interest of 75%. The ownership interest is held within BHE GT&S LLC, a Berkshire Hathaway Energy business unit.
A subsidiary of BHE GT&S is the general partner and operator of the Cove Point natural gas pipeline and natural gas liquefaction plant in Lusby, Md. A subsidiary of Brookfield Infrastructure Partners holds the remaining 25% limited partnership interest in Cove Point LNG LP.
The Cove Point LNG plant has a storage capacity of 14.6 bcf and a daily send-out capacity of 1.8 bcf, according to BHE GT&S. The terminal connects, via its own pipeline, to the major Mid-Atlantic gas transmission systems of Transcontinental Gas Pipeline, Columbia Gas Transmission, and Eastern Gas Transmission and Storage.
The deal was announced in July, and closed Sept. 1.