GENERAL INTEREST Quick Takes
Premier, BP cut consideration in revised North Sea deal
Premier Oil PLC has agreed, in principle, on revised terms of a January deal to acquire Andrew area and Shearwater assets in the North Sea from BP PLC. The structure of the consideration and phasing of payments are being adjusted to reflect the material developments in global commodity markets, Premier said in a June 5 release. Subject to debt and shareholder approvals, the deal is expected to close by Sept. 30.
BP currently operates the Andrew assets, comprising the Andrew platform, Andrew (62.75%), Arundel (100%), Cyrus (100%), Farragon (50%), and Kinnoull (77.06%) fields, and associated subsea infrastructure. The hub started production in 1996. Average daily production in 2019 was 25,000-30,000 boe/d.
BP holds a 27.5% stake in the Shell-operated Shearwater field—a high pressure, high temperature reservoir produced through a process, utilities and quarters platform 140 miles east of Aberdeen. Shearwater’s 2019 production was some 14,000 boe/d gross.
Revised terms include cash payable to BP at completion of $210 million, and reduced abandonment obligations of $240 million (pre-tax) from $600 million (pre-tax). BP would retain 100% of the existing Shearwater abandonment costs and 50% of the existing Andrew Area abandonment costs.
The original consideration of $625 million at the effective date of Jan. 1, 2019, would be set off by $300 million of estimated interim period cash flows to be retained by BP and a further $115 million would only become payable based on higher future oil and gas prices.
Premier is in discussions with certain creditors to waive financial covenants through to Sept. 30 and to provide continued access to its revolving credit facilities. If agreed and finalized, the terms will be put to the wider creditor group for approval. The company has agreed with Asia Research Capital Management, its largest creditor, to issue 82.2 million new shares to raise $27.5 million, the proceeds of which will be used to fund part of the proposed BP acquisitions and ongoing capital investments.
Tullow progresses Uganda asset sale
CNOOC Uganda Ltd. will not pre-empt the sale of Tullow Oil PLC’s assets in Uganda to Total.
In April, Tullow agreed to the sale, noting that CNOOC had rights of pre-emption to acquire 50% of the assets on the same terms and conditions as Total (OGJ Online, Apr. 23, 2020).
Under the terms of the deal, Total will acquire all of Tullow’s existing 33.3334% stake in each of the Uganda Lake Albert Blocks 1, 1A, 2, and 3A and the proposed East African Crude Oil Pipeline (EACOP) System that would run through Tanzania to the port of Tanga.
Tullow is operator of Block 2. Total Uganda is currently operator of Block 1 and Block 1A, and CNOOC Uganda Ltd. is operator of Block 3A (OGJ Online, Aug. 29, 2019).
There are no changes to the transaction or timeline and Tullow continues to expect the transaction to complete in this year’s second half, subject to conditions, including approval by Tullow’s shareholders, customary government and other approvals, and the execution of a binding tax agreement with the Government of Uganda and the Uganda Revenue Authority.
Exploration & Development Quick Takes
Strike Energy’s seismic work improves Perth basin outlook
Newly reprocessed 2D and reinterpreted 3D seismic data in onshore North Perth basin permits in Western Australia has improved the imaging of both the South Erregulla and Waylering gas prospects, Strike Energy Ltd. said.
At South Erregulla in EP469, reprocessing of 23 historical 2D seismic lines was done using a common datum and amplitude and phase balancing. The result is a marked improvement in data quality and the company’s structural interpretation of the prospect.
The new work immediately confirms the presence of a gross 4-way dip closure over the greater Erregulla South structure and increases confidence in the presence of a sealing fault up-dip of the northwest arm of the structure.
The company has put a P50 estimate of 1.6 tcf prospective resource on South Erregulla and says that the connectivity of the South Erregulla structure to West Erregulla field is well imagined, supporting a high confidence in finding an equivalent trap-seal combination that is likely to hold conventional, quality hydrocarbon-charged reservoir.
Strike will now reprocess additional 2D lines to generate further information on the target and surrounding areas. The new data will be coupled with the Trieste 3D seismic survey that is being fast-tracked through its processing workflows.
At Waylering in permit EP447 to the south of the Erregulla prospects, final, post-stack 3D data has been fully interpreted. Good quality data indicates the presence of a high confidence wet gas accumulation up-dip of the earlier Waylering-4 well.
The new data shows Waylering structure is comprised of several fault blocks that are linked to form a grossly antiformal structure with 4-way dip closure. Direct hydrocarbon indicators have been observed across the Waylering data from spatial and optical stacks.
Tests of the Cattamarra sands in three wells (Waylering-1, -2, and -3) have shown the presence of a sweet liquids-rich gas estimated 25.4 bbl condensate per million cu ft of gas.
Strike has 100% of EP 447 and shares EP469 50-50 with Warrego Energy Ltd.
Gazprom, RusGazDobycha reach FID on Semakovskoye development
Gazprom and RusGazDobycha expect construction of the first horizontal development well on Semakovskoye gas field in the Yamal-Nenets Autonomous Area of Russia to be complete by the end of June. The companies are moving forward with the project after reaching final investment decision for field development, Gazprom said in a release June 4.
The field, in the waters of Taz Bay and partly on land in the Taz Peninsula, is classified as large with recoverable gas reserves over 320 billion cu m.
During the preparatory stage, operator RusGazAlyans—formed in 2016 to assess development of three natural gas fields in the region—carried out a set of design and survey works, drew up the design documentation, and obtained permits from governmental authorities to start construction and installation operations as part of the first stage of field pre-development (land) (OGJ Online, Sept. 6, 2016).
Development configuration is fully defined, including the priorities for the construction and commissioning of production and transmission facilities, the procedure for recording and purchasing extracted gas, and the ongoing efforts for attracting project financing from Russian credit organizations.
As part of the first stage of pre-development, RusGazAlyans began development drilling. Construction is underway for the first horizontal development well with a vertical deviation of more than 2,000 m. The well is designed to have a measured depth of about 2,700 m, with a vertical depth of 830 m. Its construction, which includes geological studies, is expected to be finished by the end of June. Construction of the first six development wells is expected to be complete no later than first-quarter 2021.
Motorways and sites for production facilities are being built at the field, and logistical resources are being brought to the area.
The active phase of construction and installation will begin in this year’s second half with commercial field production expected to start in 2022 when 19 wells are expected to have been built. Extracted gas will be fed into Gazprom’s gas transmission system.
Final investment decision on the development of Parusovoye and Severo-Parusovoye fields will be made at a later, unspecified date.
New oilfields discovered in Belarus
Belorusneft discovered two new oilfields, Izbynskoye and North Omelkovichi, in Khoiniki district, Gomel region, southeast Belarus.
Reserves of light, sweet, low-viscosity oil with high light fraction yield are estimated in excess of 2.5 million tons. The discoveries increase prospects and resource potential of the central structural zone of the Pripyat trough.
In the next 2 years, geologists will study commercial potential of the trough. Seven exploration wells are planned from 2020 to 2023.
Belorusneft produces oil and gas in 61 fields in Belarus through its Rechitsaneft production department. Total stock is more than 1,000 wells, including 793 producing wells. About 90% are operated by artificial lift.
Ineos completes Norwegian Sea farm-out to Rex unit
Ineos E&P Norge AS closed a deal May 29 to transfer 15% interest in two Norwegian Sea licenses to Lime Petroleum AS (LPA), a 90% subsidiary of Rex International Holding Ltd., LPA said June 1.
The farm-in agreement, signed in March, is for Ineos-operated licenses PL937 and PL937B in Froya High in water depth of 325 m. Njord field is 30 km to the north.
Exploration drilling of the Far Canyon prospect in a Jurassic reservoir is expected in early 2021.
Drilling & Production Quick Takes
Baker Hughes: International rig count down 110 units in May
The international rig count for May reached 805, a decrease of 110 units from April and down 321 units from the 1,126 counted in May 2019, according to Baker Hughes data (OGJ Online, May 1, 2020).
The international offshore rig count for May was 195, down 33 units from April, and down 45 units from the 240 counted in May 2019.
The worldwide rig count for May was 1,176, down 338 units from the 1,514 counted in April, and down 1,006 units from the 2,182 counted in May 2019.
The average US rig count for May was 348, down 218 from April, and down 638 from the 986 counted in May 2019.
Europe was down 1 unit with 111 in May and down 75 units year-over-year. Effective June 7, 2019, Ukraine has been added to the Baker Hughes International Rig Count.
Latin America is down 27 units from the previous month with 62 units and down 117 units year-over-year.
The Asia-Pacific region is up 5 with 196 units month-over-month and down 32 units from its year-ago average.
The Middle East down 45 units month-over-month at 375 and down 35 8 units year-over-year.
The average Canadian rig count for May was 23, down 10 units from the 33 counted in April, and down 47 units from the 60 counted in May 2019.
Tethys advances well tests in Kazakhstan
Tethys Petroleum Ltd. has completed testing the Klymene exploration well, KBD-02, in the Kul-Bas block, Kazakhstan (OGJ Online, Mar. 19, 2020). The well has produced 20,000 bbl of oil to date and has averaged over 400 b/d for the last week on a 9-mm choke with good oil quality and no water cut. The test to date has focused on the Jurassic zone as the widest of three potential zones. The current plan is to test this zone until July 7, followed by testing of the next zone. At present, the service provider is under quarantine but expected to be on location by July.
Tethys plans to drill 3 more gas wells later this year, assuming relaxation of quarantine restrictions.
Kul‐Bas block is a large exploration area of about 7,632 sq km northwest of the Aral Sea. A wildcat well was previously drilled into the Jurassic zone and Permo-Carboniferous limestones. Klymene prospect estimated gross unrisked mean prospective recoverable oil is about 422 million bbl.
PGNiG drills first horizontal well in Paproc field
Polish Oil and Gas Company (PGNiG) completed drilling and testing Paproc 66-H, the first horizontal well in Paproc gas field, Boruja Koscielna, Nowy Tomysl municipality.
The well was drilled under license 102/94 and was designed based on a digital model of the deposit. The initial development called for three wells, but only one horizontal well was drilled following digital oilfield system analysis. Total well length is 3,105 m, and well depth is 2,612 m. Expected annual production is about 45 million cu m of high-methane gas, about five times higher than average capacity of wells operated in the field.
PROCESSING Quick Takes
Tatneft installs deisobutanizer column at Tatarstan complex
PJSC Tatneft, Almetyevsk, Russia, has installed a new deisobutaziner column for a gas fractionation unit at the more than 10 million-tonnes/year refinery of subsidiary JSC Taneco’s multiphase integrated refining and petrochemical complex in Nizhnekamsk, 250 km from Tatarstan’s capital city of Kazan.
Installation of the 70.4 m-high deisobutanizer column—now the tallest Taneco’s complex—was started on May 31 and completed as of June 2, Tatneft said.
The new deisobutanizer column will be used to separate isobutane from depropanized fraction from an associated 350,000-tpy gas fractionation unit, which separates light hydrocarbons into close-cut fractions to produce propane-butane, stable gas naphtha, butane, and isobutane.
The isobutane will be transported to Tatneft subsidiary OOO Tolyattikauchuk’s petrochemical complex in Tolyatti, Samara Region, Russia, to be used as fresh feedstock, Tatneft said.
Installation of the deisobutanizer column follows the operator’s start of sales of RMD-80 ultralow-sulfur marine fuel—which complies with the International Marine Organization’s (IMO) new regulations requiring ships to use marine fuels with a sulfur content below 0.5%—and Euro 6-quality gasoline grades AI-92, AI-95, AI-95, AI-98, AI-100 from Taneco’s refining complex last month, Tatneft said in releases on May 26 and May 28.
Production of IMO 2020-compliant marine fuel began after the refinery’s mid-April commissioning of a new 850,000-tpy heavy coking gas oil hydrotreating unit, which has an annual marine fuel production capacity of 750,000 tpy, Tatneft said.
Taneco also commissioned a new sulfolane plant in April to produce raw materials for production of high-octane gasoline components to enable increasing Euro 6 gasoline output at the site by 30,000 tpy, according to an Apr. 17 release from Tatneft. The sulfolane plant also has allowed the refinery to begin production of up to 45,000 tpy of benzene-toulene fraction for use as petrochemical feedstock at the complex.
As of April 17, unidentified construction and commissioning activities also were under way at the refinery’s middle distillate and delayed coking units, Tatneft said.
The recently commissioned units come as part of an ongoing program Tatarstan launched in 2005 to strengthen the republic’s refining industry, as well as in accordance with basic provisions of a quadripartite agreement on modernization of Russia’s processing industry between oil companies; the Federal Antimonopoly Service of the Russian Federation; the Federal Service for Environmental, Technological, and Nuclear Supervision (Rostechnadzor); and the Federal Agency for Technical Regulating and Metrology (Rosstandart) to reequip and upgrade processing capacities at Russian Federation refineries.
Tatneft’s modernization program—which aims to boost nameplate crude oil processing capacity at Nizhnekamsk to 14 million tpy—is scheduled to be fully completed in 2023.
Turkmengaz, Mitsubishi discuss infrastructure
Turkmengaz State Concern, the national gas company of Turkmenistan, and representatives of Japan’s Mitsubishi Corp. discussed via videoconference May 22 prospects for cooperation in the oil and gas industry, the Ministry of Oil & Gas Industry & Mineral Resources in Ashgabat reported May 26.
In a statement, the company said priority aspects of cooperation are “diversifying industry, creating a vast infrastructure of export ‘blue fuel’ and innovative industrial complexes specializing in the processing of natural gas, to produce polymers and other chemical products.”
During the online negotiations, issues of preparing a preliminary technical project for the construction of a plant to produce 10 billion cu m/year of commercial gas were discussed. The plant is planned to be built as part of the next stage of industrial development of the 16-tcf Galkynysh gas field in eastern Mary province.
GCEH lets contract for Bakersfield refinery conversion
Global Clean Energy Holdings Inc. (GCEH) has let a contract to Haldor Topsoe AS to provide process technology for GCEH’s previously announced plan to convert its recently purchased 70,000-b/d Bakersfield, Calif., refinery into a renewable diesel production plant (OGJ Online, May 11, 2020).
As part of the contract, Haldor Topsoe will license its proprietary HydroFlex renewable fuel technology as well as supply basic engineering, proprietary equipment, and catalysts for the refinery revamp, which—once completed—will enable the plant to produce 15,000 b/d of renewable diesel from proprietary camelina oil and other traditional biofuel feedstocks, the service supplier said on June 9.
Fuel production from the retooled refinery will meet the California Low Carbon Fuel Standard, as well as comply with ASTM D975 diesel specifications, resulting in major reductions of carbon dioxide emissions due to a lower carbon index, Haldor Topsoe said.
Alongside processing GCEH’s patented proprietary fallow-land crop varieties of camelina, the HydroFlex unit will process a slate of additional nonpetroleum renewable feedstocks, such as used cooking oil, soybean oil, and distillers’ corn oil, among others.
The contract award—a value for which was not disclosed—follows GCEH’s May 7 purchase of the idled Bakersfield refinery from Delek US Holdings Inc. subsidiary Alon Bakersfield Property Inc. for $40 million.
Scheduled to begin immediately and take 18-20 months to complete, the revamp and conversion project will be executed primarily by local trade unions through Primoris Services Corp. subsidiary ARB Inc., which is serving as engineering, procurement, and construction contractor.
With the former oil refinery already equipped with a large portion of necessary equipment in place for production of renewable diesel, the conversion project will involve a full turnaround and refurbishment of existing equipment to enable production from renewable feedstocks.
Due for startup in late 2021, the refinery will no longer process petroleum of any kind.
TRANSPORTATION Quick Takes
Delek advancing W2W, Red River pipeline projects
Delek US Holdings Inc. expects the 650-mile Wink-to-Webster (W2W) joint-venture crude oil pipeline to be completed in 2021 and expansion of its Red River joint-venture crude line to be done second-half 2020. The company updated the status of both projects as part of its June 2020 investor presentation.
W2W, in which Delek holds a 15% stake, will use 36-in. OD pipe to transport as much as 1.5-million b/d of crude from the Permian basin to the Texas Gulf Coast. The pipeline will be integrated with Delek’s Big Spring gathering system.
Delek is also expanding its Red River pipeline between Cushing, Okla., and Longview, Tex., to 235,000 b/d from 150,000 b/d. The expansion will allow Delek to reduce its dependence on Midland, Tex.-sourced crude at its Tyler, Tex. (75,000 b/d), El Dorado, Ark. (80,000 b/d), and Krotz Springs, La. (74,000 b/d), refineries. The company will increase its shipment on the pipeline to 100,000 b/d from 65,000 b/d following the expansion.
W2W is a joint venture among ExxonMobil, Plains All American (PAA) Pipeline LP, Enterprise Products Partners LP, Lotus Midstream LLC, MPLX LP, Delek, and Rattler Midstream LP.
Delek owns 33% of Red River with PAA holding the balance.
Nakilat starts Phase 2 of Shell fleet transition
Nakilat has begun the second phase of its fleet management transition from Shell International Trading and Shipping Co. Ltd., with Q-Max (266,000-cu m) LNG carrier Al Mayeda being the first vessel transitioned as part of several vessels under the phased management transition agreement. The technical management of Al Mayeda will be undertaken by Nakilat’s in-house ship management arm, Nakilat Shipping Qatar Ltd.
Wholly-owned by Nakilat and chartered by Qatargas, Al Mayeda has completed 88 voyages since it was delivered in February 2009.
Nakilat also took delivery of newbuild 173,400-cu m LNG carrier Global Energy which will be managed in-house by Nakilat. Built by Daewoo Shipbuilding & Marine Engineering, this is the first of four LNG carrier newbuilds to be delivered to Global Shipping Co. Ltd., a joint venture of Nakilat (60%) and Maran Ventures Inc. (40%). The delivery of all four newbuild LNG carriers by end-2021 will bring Nakilat’s fleet to 74 vessels, just under 12% of current global LNG fleet carrying capacity.
In 2019 Nakilat tendered for 60-100 new LNG carriers to serve its North Field Expansion project.
Golden Pass LNG awards compression contract
The joint venture building the 15.6-million tonne/year (tpy) Golden Pass LNG liquefaction plant awarded Siemens Gas and Power the contract to supply three cryogenic boil-off gas (BOG) compressor trains. CCZ JV, a joint venture between Chiyoda International Corp., McDermott International, and Zachry Group, is EPC contractor of the plant in Sabine Pass, Tex., at the site of Golden Pass’ existing import terminal. The plant will use three 5.2-million tpy trains.
Siemens’ scope of supply covers engineering, manufacturing, and testing of the three, single-shaft centrifugal BOG compression packages, along with installation and commissioning. Each of the compressor packages will be driven by a 6.8-Mw electric motor. Manufacturing, testing, and packaging will take place in Duisburg, Germany.
In addition to the BOG compressor trains, Siemens will provide steam turbine generator sets for the Golden Pass LNG plant. Golden Pass is a joint venture between affiliates of Qatar Petroleum and ExxonMobil.
