GENERAL INTEREST Quick Takes
Ovintiv to sell Eagle Ford assets for $880 million
Ovintiv Inc., Denver, agreed to sell its Eagle Ford assets to Validus Energy for $880 million, exceeding its target of $1 billion by 2022 with over $1.1 billion in asset sales year-to-date. The deal follows one signed in February in which the company agreed to sell Duvernay assets for $263 million.
According to its 2020 annual report, as of Dec. 31, 2020, the company held 44,000 acres (gross) and 531 (gross) producing wells (437 oil, 94 natural gas) in the Eagle Ford with an average 95% working interest. Full year 2021 volumes from the Eagle Ford assets were expected to average 21,000 boe/d, including 14,000 b/d of crude and condensate.
In 2014, Ovintiv—then Encana Corp.—agreed to acquire 45,500 net acres in Karnes, Wilson, and Atascosa counties, part of the Eagle Ford shale in South Texas, from Freeport-McMoRan Oil & Gas LLC for $3.1 billion (OGJ Online, May 7, 2014; June 20, 2014).
Total company crude and condensate volumes in this year’s first quarter are expected to average 196,000–200,000 b/d following restored production after winter storms in Texas and Oklahoma.
Based on expected second-quarter closures for both the Eagle Ford and Duvernay deals, full-year 2021 crude and condensate production is expected to average 190,000 b/d, inclusive of about 10,000 b/d from divested assets.
Planned capital investments for 2021 remain unchanged at $1.5 billion, and the company expects to reach its target debt of $4.5 billion by mid-2022. This year, Ovintiv plans to run 3 rigs and 1-2 completion crews in the Permian basin with total capex of $600-650 million. In the Anadarko basin, 2 rigs are planned with 1-2 completion crews and total capex of $300-325 million. In the Montney, 3-4 rigs with 1-2 completion crews are planned with total capex of $375-425 million.
PGNiG to acquire Ineos Norwegian assets for $615 million
PGNiG Upstream Norway has agreed to acquire all assets of Ineos Group’s Norwegian subsidiary Ineos E&P Norge AS for $615 million. The deal includes all Ineos Oil & Gas interests in production, licenses, fields, facilities, and pipelines on the Norwegian continental shelf.
Ineos E&P Norge produces some 33,000 boe/d from the Norwegian Sea with interests in 22 licenses (6 operated) and the Nyhamna gas terminal in northern Europe (8%). With a 93% gas ratio, the assets include Ormen Lange (14%), Alve (15%), and Marulk (30%) fields.
With the deal, the volume of natural gas production by PGNiG on the Norwegian Continental shelf will increase by about 1.5 billion cu m/year (bcmy), resulting in potential total production of 4 bcm in 2027.
The deal ensures a significant volume of gas for the 10-bcmy Baltic Pipe natural gas pipeline, said Paweł Majewski, PGNiG management board president in a release Mar. 25. From 2022, gas from Norwegian fields will be transported to the country via the 36-in. OD natural gas pipeline (OGJ Online, June 29, 2020).
Currently, PGNiG Upstream Norway holds interests in 36 licenses and produces crude oil and natural gas from nine fields. Six more are undergoing investment and analytical work. Last year, PGNiG mined some 500 million cu m on the Norwegian continental shelf.
The sale, subject to approval by the Norwegian Ministry of Petroleum and Energy and the Norwegian Ministry of Finance, is expected to close later this year with all 52 employees of INEOS E&P Norge expected to transfer to PGNiG Upstream Norway AS.
Eni sells Pakistan assets to Prime International
Eni agreed to sell its shares in its entities in Pakistan to Prime International Oil & Gas Co., a newly established company formed by former Eni employees and Hub Power Co. Ltd., the largest independent Pakistani power producer.
The activities covered by the agreement include interests in eight development and production leases in Kithar fold belt, Middle Indus basins, and four exploration licenses in Middle Insud and Indus offshore basins.
Eni’s main permits are in Bhit-Badhra (40% working interest) and Kadanwari (18.42% working interest). Other shares are Latif (33.3%), Zamzama (17.75%), and Sawan (23.7%).
Exploration & Development Quick Takes
PTTEP makes third discovery offshore Malaysia
PTT Exploration and Production Public Co. Ltd. (PTTEP), through its subsidiary PTTEP Sarawak Oil Ltd., discovered oil and gas in Sirung-1, the first exploration well in Block SK405B, about 137 km off the coast of Sarawak (Bintulu), Malaysia.
The well was drilled in January in shallow waters to a total depth of 2,538 m where it encountered an oil and gas column of more than 100 m in the clastic reservoirs. An appraisal well is scheduled soon to assess the upside resources, the company said in a release Mar. 29.
Sirung-1 is PTTEP’s third discovery offshore Malaysia following SK410B’s Lang Lebah and SK417’s Dokong (OGJ Online, Feb. 11, 2021; Feb. 24, 2021). PTTEP plans to explore nearby prospects in the area in 2022, said Phongsthorn Thavisin, chief executive officer, PTTEP.
PTTEP is operator at SK405B (59.5%) with partners Moeco Oil (Sarawak) Sdn. Bhd. (25.5%) and Petronas Carigali Sdn. Bhd. (15%).
Beach finds gas in Artisan-1 offshore Otway basin
Beach Energy Ltd., Adelaide, found gas in its Artisan-1 wildcat in permit Vic/P43 in the offshore Otway basin of western Victoria. The discovery is at the lower end of pre-drill expectations, but it is being cased and suspended as a future producer with potential tie-in to the offshore pipeline currently delivering gas from Thylacine and Geographe fields to the onshore Otway gas plant, said Matt Kay, Beach managing director.
Drilled by semi-submersible rig Ocean Onyx 30 km off the coast, the well reached a total depth of 2,205 m and encountered a gross gas column of 69.5 m in the primary upper Waarre formation target. This included 62.9 m of net pay. The gas-water contact was intersected at a well depth of 1,990 m.
A gross gas column of 20.9 m (net pay 4.6 m) was intersected in the underlying secondary target of the Flaxman formation.
The rig will now move to Geographe field to begin the first of two in-field development wells followed by an additional four in-field wells in Thylacine field.
Beach has a 60% interest and operatorship of Vic/P43. O.G. Energy has 40%.
Equinor makes development selection for field offshore Brazil
Equinor has approved development plans for BM-C-33, a gas-condensate field in Campos basin presalt offshore Brazil. The license lies about 200 km from shore in water depths up to 2,900 m.
Well streams will be sent to a floating production, storage, and offloading unit (FPSO) at the field. Gas and oil-condensate will be processed at the FPSO to sales specifications and exported.
Crude will be offloaded by shuttle tankers and shipped to the international market after ship-to-ship transfer. A new-build hull has been selected to accommodate a 30-year field lifetime.
Gas will be exported though an integrated offshore gas pipeline from the FPSO to a new dedicated onshore gas receiving facility inside the Petrobras TECAB site at Cabiúnas, before connecting to the domestic gas transmission network.
Gas export capacity is planned for 16,000 cu m/day with average exports expected to be 14,000 cu m/day. Daily oil processing capacity is 20,000 cu m.
Equinor is operator (35%) with partners Repsol Sinopec Brasil (35%) and Petrobras (30%).
Drilling & Production Quick Takes
Santos brings Van Gogh online, prepares Phase 2 drilling
Santos Ltd., Adelaide, has restarted oil production from Van Gogh fields in Carnarvon basin offshore Western Australia and is preparing a three-well Phase 2 drilling program.
The FPSO Ningaloo Vision has returned from a scheduled, but challenging, dry docking and maintenance program in Singapore. The maintenance work was delayed when the FPSO arrived in Singapore last year just as that nation went into a 3-month lockdown due to the COVID-19 pandemic.
Ningaloo Vision has now begun ramping up production from Van Gogh, Coniston, and Novara fields, expecting to reach a flow of 10,000 b/d of oil within a few weeks.
The return to production coincides with Santos’ moves to begin a second phase of infill drilling in Van Gogh field which is expected to start in April.
The new wells will be drilled using the Valaris MS1 semisubmersible rig targeting about 10 million bbl of reserves. Oil is expected on stream in fourth-quarter 2021.
Production from Van Gogh, which lies in production license WA-35-L, began in 2010, while nearby Coniston and Novara fields were tied back to Ningaloo Vision in 2015 and 2016, respectively.
Phase 1 of the infill project began in September 2018 with two subsea wells connecting to the existing infrastructure. These wells were brought on stream in January 2019.
Santos has a 52.5% interest and operatorship of the three fields. Inpex holds the remaining 47.5%.
Devon expects 8% Q1 production decrease from winter storm
Devon Energy Corp. updated its first-quarter and full-year 2021 production guidance adjusted for severe winter weather and a minor asset sale.
While production has been restored to pre-storm levels, an 8% drop in first-quarter production is expected due to the impact of severe winter weather, the company said Mar. 29. Adjusting for the downtime, Devon expects first-quarter 2021 oil production of 261,000-265,000 b/d and total production of 485,000-499,000 boe/d.
Guidance excludes WPX results prior to the acquisition close date of Jan. 7, 2021, limiting production by an incremental 3% for the first quarter (OGJ Online, Sept. 29, 2020).
The company’s full-year 2021 guidance was also adjusted for the sale of the company’s Wind River asset in Wyoming which closed Mar. 3. This sale is expected to reduce oil production by 2,000 b/d for full-year 2021.
Bass Oil plans drilling activity in south Sumatra basin
Bass Oil, Melbourne, has identified expansion opportunities west of Indonesia’s onshore Bunian oil field in south Sumatra basin and plans to start a drilling program later this year with one firm well and an additional two contingent wells.
As part of its first major new work in the area since the beginning of the COVID-19 pandemic, the company plans to drill the Bunian-6 well in the undrilled southwest part of the field and a third well to appraise the Bunian 3P extension area.
The company expects to hold production steady through 2021 with drilling aimed at boosting production in 2022.
The expansion drilling program is aimed at building daily output from about 500 b/d from four production wells within the Tangai Sukananti KSO license which hosts Bunian and Tangai oil fields and follows a comprehensive integrated reservoir study over the past year updating static and dynamic reservoir models following drilling of the Bunian-5 development well.
The study identified a number of production and reserve growth opportunities, including drilling the Tangai-5 development well updip of existing producers, identifying major extension of Bunian field to the west, possible extension of Bunian field with appraisal and development drilling, and modelling K reservoir in Bunian to improve recoveries and reduce development costs through application of horizontal drilling techniques.
Bass is operator in the license with 55% working interest.
PROCESSING Quick Takes
Petrobras executing hydrotreater upgrade at REDUC refinery
Petróleo Brasileiro SA (Petrobras) is undertaking a project involving the revamp of an existing hydrotreater to improve the quality and quantity of low-sulfur diesel production at its 239,000-b/d Duque de Caxias (REDUC) refinery in the Baixada Fluminense area of Brazil’s Rio de Janeiro state.
Alongside reducing sulfur content of diesel to 10 ppm from 500 ppm to meet domestic and international market specifications, the hydrotreating unit upgrade also will nearly double Diesel S10 (10 ppm sulfur) production at the site to 9,500 cu m/day from its current 5,000 cu m/day output, the operator said.
Scheduled to be completed by second-half 2023 at a proposed investment of 140 million Brazilian real, the unit revamp comes as part of the company’s broader strategic objective of producing cleaner, higher-quality, more efficient fuels that have less impact on the environment, according to Petrobras.
In addition to reducing emissions of particulate matter, use of Diesel S10—which has a higher cetane number than Diesel S500 (500 ppm sulfur)—promotes improved fuel performance of vehicle engines in line with Brazil’s stricter air pollution control program for on-road heavy-duty and utility vehicles.
“We are preparing for the new refining market that will be formed in Brazil in the coming years, and this project is of great relevance for us to remain competitive [by] providing [high-quality products and] operating in a sustainable manner and in synergy with our [production] assets in deep and ultradeep waters,” said Alexandre Coelho, REDUC’s general manager.
Petrobras said it also plans to undertake similar unit upgrades in the coming years to expand Diesel S10 production at its 434,000-b/d Refinaria de Paulínia (REPLAN) refinery in Paulínia, São Paulo, and 252,000-b/d Refinaria Henrique Lage (REVAP) refinery in São José dos Campos, São Paulo. While the operator disclosed no further details regarding the REPLAN and REVAP project, the company did confirm implementation of these two projects would increase overall Diesel S10 production up to 16,500 cu m/day.
MOL Group adds biodiesel production at Danube refinery
Hungary’s MOL Group has started production of renewable diesel at its 8.1-million tonnes/year Duna refinery along the Danube River in Százhalombatta, near Budapest.
Produced via coprocessing of biofeedstocks—including vegetable oils, used cooking oils, and animal fats—with conventional crude oil, biodiesel production from the refinery will result in up to a 200,000-tpy reduction in carbon dioxide (CO2) emissions, advancing MOL Group’s goal under its 2030+ Strategy to achieve net-zero CO2 emissions by 2050, the operator said on Mar. 16.
Initiated as a research and development undertaking in 2012 and launched as a formal investment in 2018, MOL Group said the Duna coprocessing project—which entered trial operation in March 2020 and began regularly operating in May 2020—required additional infrastructure and equipment for storage and processing of biofeedstocks.
The operator, however, revealed no further details regarding either specific structures added as part of the project or current production capacity of renewable diesel at the site.
With commissioning of the new Danu project, MOL Group—which historically has purchased more than 500,000 tpy of biofuels such as bioethanol and biodiesel for blending into its conventional fuel production to meet the European Union standards—now plans to expand biofuel production capacity within its refining system to 100,000 tpy, said Gabriel Szabó, executive vice-president of MOL Group’s downstream business.
Within the next 5 years, MOL Group said it will spend about $1 billon on projects aimed at transforming its traditional fossil-based operations into a low-carbon, sustainable business model.
In the downstream, MOL Group’s plan entails a fuels-to-chemicals transformation that will involve converting 1.8 million tpy of fuels from its refining system into higher-value, sustainable petrochemical feedstock by 2030, according to a Feb. 24 release from the operator.
Proposed within a framework of two investment cycles to be completed in 2027 and 2030, respectively, MOL Group said capital expenditures on the downstream transformation program could reach up to $4.5 billion within the next 10 years.
Gazprom JV replacing EPC contractor for Ust-Luga plant
PJSC Gazprom and RusGasDobycha have terminated an earlier contract let to Sibur Group subsidiary Nipigaz for delivery of engineering, procurement, and construction (EPC) services on the natural gas processing portion of the planned gas processing, liquefaction, and chemical complex to be operated by RusKhimAlyans—a 50-50 special-purpose venture of Gazprom and RusGazDobycha—on the Gulf of Finland near the seaport of Ust-Luga, Leningrad Oblast, Russia.
Cancellation of the June 2020 contract—under which Nipigaz was to provide EPC services covering the complex’s gas processing and off-site installations, as well as startup and commissioning works—comes as part of a decision by the partners to trim project costs, Gazprom said in a Mar. 15 release.
Gazprom—which, along with partner RusGasDobycha, will select a new contractor for delivery of EPC on gas processing operations soon—said development activities on the entirety of the Ust-Luga complex remain ongoing, with replacement of Nipigaz to have no impact on the project’s overall implementation schedule.
The RusKhimAlyans complex, which will have 13 million-tonnes/year liquefaction capacity, will receive 45 billion cu m/year (bcmy) of wet natural gas from Gazprom’s Achimov and Valanginian deposits in the Nadym-Pur-Taz region of the Yamal Peninsula. Gas remaining after processing (including ethane extraction) and LNG production, about 18 bcmy, will go into Russia’s gas transmission system. The complex will produce as much as 4 million tpy of ethane, and more than 2.2 million tpy of LPG.
LNG and LPG produced at the Ust-Luga complex will be exported, while ethane from the site will feed nearby RusGazDobycha subsidiary Baltic Chemical Complex LLC’s (BCC) proposed $13-billion ethane cracking project, which—once in operation—will produce more than 3 million tpy of polymers (OGJ Online, Nov. 9, 2020).
TRANSPORTATION Quick Takes
Chevron stops funding Kitimat LNG
Chevron Canada Ltd. has stopped funding feasibility work for the proposed 18-million tonne/year (tpy) Kitimat LNG plant. In December 2019, Chevron announced plans to divest its 50% share in the project but has not found a buyer.
Kitimat LNG is a 50-50 joint venture between Chevron and Woodside Energy International (Canada) Ltd. The Chevron-operated project comprises upstream resources in Liard and Horn River basins in northeast British Columbia, the proposed 471-km Pacific Trail pipeline, and the LNG plant at Bish Cove near Kitimat, BC.
Woodside intends to continue to advance the project. The company recorded a $720-million after-tax writedown on it against its 2019 earnings (OGJ Online, Feb. 12, 2020).
Kitimat LNG would use three 6-million tpy trains and be powered by hydroelectricity supplied by BC Hydro.
Mountain Valley Pipeline receives FERC affirmation
Mountain Valley Pipeline LLC (MVP) received US Federal Energy Regulatory Commission (FERC) affirmation that it could resume work on a 17-mile stretch of the pipeline near Jefferson National Forest in Virginia. Work elsewhere on the 303-mile, 2-bcfd natural gas pipeline, however, remains suspended pending new permits for work in waterways and wetlands.
Sierra Club and other environmental groups had requested both a stay on work near the national forest and a rehearing of FERC’s December 2020 action lifting previous stop-work orders. FERC rejected these requests on a 3-2 vote, ruling that work could continue despite missing permits because those permits had been vacated after work had begun.
MVP received its original certificate from FERC in October 2017. A condition of that certificate—Environmental Condition 9—required it to show that it had all permits required under federal law before it could begin construction. On Jan. 22, 2018, FERC authorized MVP to begin construction after finding it had satisfied that condition. The US 4th Circuit Court of Appeals subsequently vacated some of those permits.
The pipeline is a joint venture of EQM Midstream Partners LP, NextEra Capital Holdings Inc., Con Edison Transmission Inc., WGL Midstream, and RGC Midstream LLC.
Excelerate, ExxonMobil study LNG-to-power terminal in Albania
Excelerate Energy LP, ExxonMobil LNG Market Development Inc., and the Republic of Albania have signed a memorandum of understanding (MOU) to conduct a feasibility study for the potential development of an LNG terminal in the Port of Vlora, southern Albania. The integrated LNG-to-power project would include an LNG regasification terminal, converting or expanding the existing Vlora thermal power plant, and establishing small-scale LNG distribution in Albania and surrounding Balkans nations.
Home to eight major river systems, Albania relies on hydropower, which can become unreliable during droughts, to supply energy to its 2.8 million residents.
Excelerate expects a prefeasibility to be delivered third-quarter 2021, with a targeted start-up for the project as early as 2023.
The terminal would be Albania’s first.