GENERAL INTEREST Quick Takes
SilverBow expands Eagle Ford portfolio in all-stock deal
SilverBow Resources Inc., Houston, has agreed to acquire assets in the Eagle Ford shale in South Texas from an undisclosed seller, expanding the company’s gas portfolio in the Western Eagle Ford and adding oil acreage in three new counties. The all-stock deal is valued at $33 million, consisting of about 1.5 million shares of SilverBow common stock.
SilverBow gains 45,000 total net acres in the Eagle Ford, adding to its gas position in McMullen and Live Oak counties, while adding new oil positions in Atascosa, Lavaca, and Fayette counties.
April 2021 net production was about 1,580 boe/d (39% liquids). Net oil production was 569 b/d.
The deal follows a $24 million cash and stock acquisition of Eagle Ford and Austin Chalk locations, as well as incremental working interest in producing wellbores in the company’s La Mesa position, said Sean Woolverton, chief executive officer.
The deal has an effective date of June 1, 2021 and is expected to close on or about Oct. 1, 2021, subject to customary closing conditions.
Prior to the announcement, as part of the company’s second-quarter results, the company guided third-quarter 2021 estimated production of 200-215 MMcfed, with natural gas volumes expected to comprise 156-168 MMcfd or 78% of total production at the midpoint. The majority of the company’s remaining full-year drilling and completions spend is expected to occur in this year’s third quarter.
For full-year 2021, the company guided production of 200-210 MMcfed, an 8% increase at the midpoint compared to prior guidance. That guidance was inclusive of the incremental working interest acquired at La Mesa.
Full year capital budget as of August was guided at $115-130 million.
The company’s operations as of June 30 span about 130,000 net acres in the Eagle Ford.
bp relinquishes A1 block offshore Gambia
bp PLC will relinquish the A1 block offshore Gambia, after failing to meet contract obligations.
bp was awarded the block in 2019 and required to obtain and reprocess 2D and 3D seismic data, conduct an environmental impact assessment, and drill one exploration well. bp performed all prerequisites except drilling the exploration well.
In early 2020, the slowdown due to COVID-19 lead bp to suspend drilling plans. In July 2020, bp informed the Ministry of Petroleum and Energy that it would not be able to drill a well in the block due to a change in its corporate strategy towards low carbon energy.
bp paid $29.3 million to the government to cover relevant outstanding amounts as well as balances of training, resources, and rentals. Consequently, bp has fulfilled all license obligations.
The block will revert to the government free of all encumbrances and will be on the market for licensing.
Petronas advances offshore Malaysia CCS plans
Petronas Carigali Sdn. Bhd. awarded a conceptual engineering design contract to Xodus for the Kasawari carbon capture and storage (CCS) project offshore Malaysia. This will be Petronas’ first complete CCS project.
The project will comprise capture and processing of CO2 from the sour gas field development, which will then be injected into a depleted gas field.
The work with Petronas was secured as part of Xodus’ contract to provide engineering services for the operator’s Malaysian and international developments. Under the agreement, Xodus is delivering feasibility studies and conceptual design.
Kasawari’s offshore central processing platform—which will produce from five subsea wells—should reach startup in first-quarter 2023. Its gas purification plant, which will remove CO2 from the gas stream, is expected to be one of the largest offshore gas treatment systems in the world (OGJ Online, Jul. 27, 2020).
Surge reenters southeast Saskatchewan with Astra acquisition
Surge Energy Inc., Calgary, closed the acquisition of Astra Oil Corp., combining the company’s existing conventional crude oil asset base, including its Sparky play in Alberta, with light oil assets primarily in southeast Saskatchewan from Astra.
Surge said it targeted southeastern Saskatchewan as a new core area based on its high light oil netbacks, low-cost production efficiencies, and quick drilling payouts. With the deal, Surge gained more than 4,100 boe/d (90% liquids) of operated, light oil production.
The assets also include in-progress construction of a 45-km gas gathering infrastructure system to conserve gas at area infrastructure, reducing emissions from several operating fields. The project is estimated to cost $12 million and will be partially funded by Natural Resources Canada’s Emissions Reduction Fund.
The combine is expected to exit 2021 with production over 20,200 boe/d (85% liquids weighted), while the deal results in over 2.5 billion bbl of net combined, internally estimated, conventional OOIP1 - with a 6% recovery factor to date; combined proven plus probable yearend 2020 reserves of over 95 MMboe (85% liquids); a development drilling inventory of over 850 net locations (internally estimated); and development drilling inventory of more than 13 years, Surge said.
All the issued and outstanding common shares of Astra were acquired for 229 million common shares of Surge and about $13.5 million in assumed debt.
Exploration & Development Quick Takes
BW Energy makes oil discovery at Hibiscus North offshore Gabon
BW Energy Ltd. has made an oil discovery in the Hibiscus North exploration well (DHBNM-1) in the Dussafu block offshore Gabon. After reaching total depth, logging operations and evaluation of the oil discovery will be undertaken, followed by drilling of a sidetrack to delineate the field.
The discovery is expected to add to the previously announced gross discovered recoverable resource estimate of 105 million bbl for the block.
The well lies about 6 km north-northeast of Hibiscus discovery well DHIBM-1 in about 115 m of water. It will be drilled to a planned total depth of about 3,500 m.
The well, part of a three-well campaign on the license, was spudded on July 28. During drilling operations, the Gamba reservoir was encountered at a depth of 2,794 m and encountered about 13.5 m of oil-bearing reservoir in the Upper Gamba sandstone. Determination of the overall hydrocarbon column is pending open hole wireline logging operations which will be conducted after drilling to planned total depth.
The Borr Norve jack up rig is continuing drilling operations to intersect the secondary targets in the deeper Dentale formation.
BW Energy is operator of the 850-sq km Dussafu block with 73.5% interest. Panoro Energy holds 17.5% and the Gabonese Oil Co. holds 9%.
Vali-3 appraisal confirms viable gas development
Vintage Energy Ltd., Adelaide, confirmed the viability of Vali gas field in permit ATP 2021 in the Cooper basin of Southwest Queensland with success in the Vali-3 appraisal.
Taking into consideration initial exploration well Vali-1 ST1, the recent Vali-2 appraisal, and the gas discovery in the nearby Odin prospect, the wells have delivered the necessary gas fields and volumes for Vintage to move forward with commercializing the Southern Flank province in the basin, said Neil Gibbins, managing director.
A bonus from Vali-2 and Vali-3 is the increase in reservoir quality sand and resultant net pay in the Permian-age Patchawarra formation compared to the discovery well, he continued.
Analysis of wireline logging data estimates a total of 165 m of conventional and lower deliverability net gas pay within the Patchawarra in Vali-3 made up of 101 m of conventional net gas pay with a porosity equal to or greater than 8% plus 64 m of lower deliverability net gas pay with porosities from 6-8%.
In addition, 13 m of conventional and lower deliverability net gas pay was identified in the deeper Tirrawarra sandstone.
Gas found in the Epsilon and Toolachee formations has yet to be quantified.
All data from the successful wells will be sent to ERC Equipoise Pty Ltd. for an update of the reserves certification for Vali field. The new certification is expected before end September.
In the meantime, discussions are advanced with a number of interested parties regarding pre-sales of gas and potential flow-line infrastructure funding to connect Vali field to the Moomba gas gathering network, the company said.
Vintage is operator of ATP 2021 with 50% interest. Metgasco Ltd. and Bridgeport Cooper Basin Pty Ltd. each have 25%.
Aker BP installs Hod B topsides for 2022 production
Aker BP and fixed facilities alliance partners Aker Solutions and ABB advanced the operator’s plan to bring Hod field on stream in first-quarter 2022 with the installation of the 2,000-tonne topsides on the Hod B jacket, which was installed in July (OGJ Online, Jul. 8, 2021).
Hod field lies in Block 2/11 in the southern part of the Norwegian sector of the North Sea, about 12 km south of Valhall and 6 km south of the Valhall Flank South platform. The platform will be remotely operated from Valhall, and the field will have low CO2 emissions due to power from shore.
Hod, expected to produce 40 MMboe, is part of the company’s goal to produce 2 billion bbl from the Valhall area through new projects and ongoing modernization, said Ole Johan Molvig, Valhall asset manager.
Several subsea campaigns will be conducted in the Hod project leading up to production start in 2022, such as installation and connection of the gas lift pipelines, production flowlines, and umbilicals. Modification work is under way at Valhall field center, and the Maersk Invincible drilling rig is expected to arrive this autumn to drill production wells.
Aker BP is operator at Hod B (90%) with partner Pandion Energy (10%).
Drilling & Production Quick Takes
Pertamina takes over Rokan block operations from Chevron
PT Pertamina (Persero), through subsidiary PT Pertamina Hulu Rokan (PHR), expects to maintain the current production program and initiate new drilling in Indonesia’s Rokan block now that it has officially replaced Chevron Corp. as operator.
In August 2018, Indonesia’s energy ministry said Pertamina would become operator when the production-sharing contract expired in 2021 (OGJ Online, Aug. 1, 2018).
Pertamina, in a statement Aug. 9, said it will maintain production by following through on predetermined drilling plans in August through December 2021. As many as 161 wells are in the project including 84 new wells and 77 ex-Chevron wells. An additional 500 wells are planned for 2022, the company said.
PT Chevron Pacific Indonesia had been operator with 100% interest in the Rokan production sharing contract (PSC), which expired in August. Net daily production averaged 99,000 bbl of crude oil and 19 MMcf of natural gas in 2019, according to Chevron.
Duri is the largest producing field in the Rokan PSC. Duri has been producing under steamflood since 1985 and is one of the world’s largest steamflood developments. In 2019, net daily production averaged 40,000 bbl of crude oil.
“Pertamina will continue the program that has been running so far, including enhanced oil recovery (EOR), which has significantly supported oil and gas production. Pertamina has set an investment budget until 2025 of more than $2 billion. Considering the Rokan block area also has unconventional potential oil and gas that can support the increase in national oil and gas production,” said Nicke Widyawati, president director of PT Pertamina (Persero).
PHR manages a working area of some 6,453 sq km with 10 main fields: Minas, Duri, Bangko, Bekasap, Balam South, Kotabatak, Farmers, Pematang, Petapahan, and Pager. The Rokan block stretches across five regencies in Riau Province: Bengkalis, Siak, Kampar, Rokan Hulu, and Rokan Hilir. This block is Indonesia’s second largest, with a 2021 oil production target of about 165,000 b/d, Pertamina said.
Norway production increased in July, NPD says
Norway’s liquids production averaged 2.035 million b/d in July, the Norwegian Petroleum Directorate reported Aug. 19.
Norway’s liquids production averaged 1.883 million b/d in June (OGJ Online, July 21, 2021).
Oil production in July is equal to the NPD’s forecast, and 0.4% higher than the forecast so far this year.
The average daily liquids production in July consists of 1.753 million b/o, 272,000 bbl of NGL, and 10,000 bbl of condensate.
The total petroleum production for the first 7 months in 2021 is about 132.3 million standard cu m oil equivalents.
US Energy, Atlantic Energy form Permian JV
US Energy Development Corp. and Atlantic Energy Partners LLC, Midland, have entered a joint venture to develop and operate three horizontal wells within the Permian basin in Ward County, Tex.
The wells, which target oil producing zones in the Wolfcamp shale, are projected to be online in first-quarter 2022 and will carry a total project development cost of about $28 million, US Energy said Aug. 11.
Over the past year, US Energy has closed $86 million worth of Permian basin projects, and expects to invest more than $150 million over the next 12 months. Earlier this year, US Energy completed and put online a three well pad in Ward County at a developmental cost of about $30 million.
ReconAfrica plans additional Kavango basin wells
Reconnaissance Energy Africa Ltd. (ReconAfrica) plans additional wells in Kavango basin, northeast Namibia, based on recent well results.
Well 6-2 was drilled to a final depth of 2,294 m (7,526 ft) and was left in a state to re-enter to run a vertical seismic profile (VSP) and test potential zones of interest. A total of over 250 m (820 ft) of conventional migrated light oil, natural gas, and natural gas liquids were encountered over three zones (OGJ Online Apr. 16, 2021). The VSP and 2D seismic data will delineate potential structures in and around the well, the company said.
Mbambi 6-1 well was drilled to a final depth of 2,780 m (9,121 ft) with casing set to total depth. The well will be left in a state to re-enter to run a VSP and potentially test possible production zones at a later date. A preliminary total of 350 m (1,148 ft) of oil and natural gas shows were encountered over seven potential zones. Well logging data, cuttings, and cores are being prepared for shipment to the US for further analysis.
With the confirmation of a working conventional hydrocarbon system within the first of potentially five sub basins, ReconAfrica will use drilling and 2D seismic data to determine planning and execution of future drilling locations. Once seismic data is acquired, an additional one or two wells will be drilled in 2021 and a further two to four wells drilled in first-half 2022.
ReconAfrica holds 90% working interest in petroleum licenses in northeast Namibia comprising 6.3 million contiguous acres.
PROCESSING Quick Takes
Mothballed refinery slated for new life as renewables plant
Slate Energy Marketing LLC subsidiary Slate Refining LLC has entered an agreement with Starwood Energy Group Global Inc. to convert a 3,800-b/d mothballed refinery in Douglas, Wyo., in the heart of the Powder River basin, into a renewable fuels production plant.
The refinery, once reconfigured, will be able to produce a mix of more than 100 million gal/year of renewable fuels, including renewable diesel, sustainable aviation fuel, and arctic diesel for both US and Canadian markets, Starwood Energy said.
Production of high-grade, low-carbon fuels from the repurposed refinery comes as part of commitments by Starwood Energy and Slate to deliver viable renewable fuel options to conform with increased demand from consumers for industry efforts to accelerate decarbonization initiatives to help achieve carbon neutrality.
While neither Starwood Energy nor Slate indicated a timeframe for when the repurposed refinery might enter service, Slate said the project to convert the former conventional-crude processing plant into a renewables production site is now under way, according to the operator’s website.
Details regarding the types of renewable feedstocks to be processed at the converted refinery have yet to be released.
Purchased by Slate in 2019 and since operated as terminal, the Douglas refinery—formerly owned by Antelope Refining LLC—officially ceased crude oil processing activities in early 2015 before its formal shutdown in December 2016, according to the US Energy Information Administration.
LUKOIL adding catalytic cracking capacity at Perm refinery
PJSC LUKOIL is advancing construction of a grassroots catalytic cracking complex at subsidiary LLC LUKOIL-Permnefteorgsintez’s 13.1-million tonnes/year (tpy) refinery in Russia’s North Urals region, on the north bank of the Kama River.
Alongside its 1.8-million tpy catalytic cracking unit, the proposed complex also will include construction of a unit for production of high-octane gasoline components and associated off-site installations, LUKOIL said on Aug. 20.
The complex additionally will feature a high flexibility to adjust its yield of propylene, according to the operator.
Part of LUKOIL’s ongoing program to upgrade and modernize its Russian refining system to ensure long-term competitiveness and improve production qualities, the planned Perm catalytic cracking complex specifically aims to increase production of high-octane motor gasoline, as well as to begin production of polymer-grade propylene, which will be used as feedstock at the operator’s petrochemical production sites.
Scheduled for startup in 2026, the new complex follows the Russian Ministry of Energy’s agreement to an incentive plan granting LUKOIL an investment premium to the refundable excise tax on crude oil until Jan. 1, 2031, that will support completion of the project.
The Perm refinery currently has a catalytic cracking capacity of 9,300 b/d, according to the latest data available on the operator’s website.
In addition to commissioning new units earlier this year as part of its broader upgrading program at subsidiaries OOO LUKOIL-Volgogradneftepererabotka’s 14.8-million tpy Volgograd refinery in southern Russia and LLC Lukoil-Nizhegorodnefteorgsintez’s (NNOS) 17-million tpy Kstovo refinery in central Russia’s Nizhny Novgorod region, LUKOIL said it also remains on schedule to fully commission NNOS’ long-planned deep conversion, delayed coking at Nizhny Novgorod by yearend.
TRANSPORTATION Quick Takes
AG&P awards CB&I second Philippines LNG tank EPC contract
Atlantic Gulf and Pacific Co. of Manila Inc. (AG&P) has awarded McDermott International Ltd.’s CB&I Storage Solutions business a contract for engineering, procurement, and construction (EPC) of a second LNG storage tank and double-wall LNG bullet for AG&P’s 3-million tonne/year Philippines LNG (PLNG) terminal in Batangas Bay, Philippines.
AG&P awarded CB&I the contract for the first LNG storage tank earlier in 2021. The additional scope includes a 1,200-cu m double-wall LNG bullet and a second 60,000-cu m full containment steel LNG tank along with geotechnical investigation, soil improvement, foundation and topside platform structure, precommissioning, purging, and commissioning activities.
Mechanical completion of the LNG bullet is slated for first-quarter 2022, with second-quarter 2024 planned for the second tank.
AG&P earlier in August awarded Acteon Integrated Solutions a contract for local transportation and installation of jacket structures for the berth at Philippines LNG (OGJ Online, Aug. 3, 2021).
Qatar Petroleum lets EPC contract for North Field expansion project
Qatar Petroleum has let an engineering, procurement, and construction (EPC) contract for its North Field expansion project to Técnicas Reunidas SA.
Técnicas Reunidas will act as the EPC contractor for the expansion of both existing liquid products (condensate, propane, and butane) storage and loading and infrastructure for mono-ethylene glycol within Ras Laffan Industrial City, as well as pipelines serving the project.
The expansion will be used to handle liquid products from the four new LNG trains comprising the North Field East (NFE) project, which is scheduled to start up before end 2025. It also will support two new LNG trains comprising the North Field South (NFS) project.
When completed, the NFE project will increase Qatar’s LNG production capacity to 110 million tonnes per year (tpy) from 77 million tpy, while the NFS project will further increase Qatar’s LNG production capacity to 126 million tpy from 110 million tpy.
Técnicas Reunidas will perform the detailed engineering work in Qatar.
