GENERAL INTEREST Quick Takes
Woodside to withdraw drilling team from Myanmar
Woodside Petroleum decided to withdraw its workers from its drilling program offshore Myanmar in response to suspected human rights violations following the military coup in the country.
Woodside initially continued drilling after the coup in early February but said Feb. 27 that reports of violence against Myanmar people participating in peaceful protests are deeply distressing.
“Until we see the outlook for Myanmar and its political stability has improved, Woodside will keep all business decisions under review,” the statement said.
The company has begun reducing its staff presence and expects full demobilization of its drilling team within weeks. The company has about 100 workers in the country.
The drilling is exploration only and did not generate revenue in the country nor did it have any direct commercial arrangements with the Myanmar military-connected organizations.
Oasis sets 2021 E&P capex of $225-235 million
Oasis Petroleum Inc., Houston, plans to direct 65-70% of its 2021 capital to the Williston basin and 30-35% of its capital to the Permian basin. About 80-85% of its exploration and production (E&P) and other capex is to be invested in drilling and completions activities, including completing 23-25 gross operated wells with a working interest of 86% in the Williston basin, and completing 6-8 gross operated wells with a working interest of 100% in the Permian basin.
E&P capex for 2021 is expected to be $225-235 million. Additionally, the company’s portion of midstream is expected to be $6-8 million. First-quarter 2021 capex is expected to be roughly 20% of full-year guidance.
First-quarter 2021 total volumes are expected to be 54,000-57,000 boe/d (65% oil cut), impacted by deferred activity and weather impacts. Full year volumes are expected to be 57,000-60,000 boe/d (66% oil cut).
Fourth-quarter 2021 volumes are expected be 62,000-65,000 boe/d (67% oil cut), as normalized capital activity supports production volumes, the company said.
Full-year 2022 volumes are expected to be flat to slightly higher with similar E&P capex levels as 2021.
The company said 74% of expected 2021 oil production is hedged at an average swap price of $42/bbl WTI, and that it has secured alternative outlets for about one-third of its expected April through September Williston crude to mitigate risk associated with any potential Dakota Access Pipeline (DAPL) disruption.
For fourth-quarter 2020, the company produced 59,200 boe/d, with oil volumes at 38,600 b/d. E&P capex for the quarter was $12.6-16.6 million, about 61-71% below guidance. Full-year 2020 E&P capex was $207-211 million, some 64% below the original budget.
Neptune increases German production portfolio with Wintershall deal
Neptune Energy has agreed to acquire interests in several oil and gas fields in the Emsland and the Grafschaft Bentheim region of Germany from Wintershall DEA, thus increasing its existing interests in Adorf, Apeldorn, and Ringe gas fields and in Adorf-Scheerhorn, Georgsdorf, and Ringe oil fields.
The deal, subject to partner approvals and expected to close in this year’s first half—will add 1,800 boe/d to Neptune’s production portfolio in Germany—a 10% increase.
Neptune operates all fields in the transaction except for Georgsdorf. The company acquired interests in various other fields of the Grafschaft Bentheim and Emsland region from Wintershall in 2019, adding 600 boe/d to the German production portfolio (OGJ Online, July 30, 2019).
Currently, Adorf Carboniferous gas field is under development after discovery in 2020 (OGJ Online, Nov. 2, 2020). The next development well is expected to be drilled in this year’s first half.
Grayson Mill to acquire Bakken assets from Equinor
Grayson Mill Energy LLC, backed by EnCap Investments, acquired Bakken interests in North Dakota and Montana from Equinor ASA for $900 million.
The transaction covers Equinor’s operated and non-operated acreage totaling 242,000 net acres. It also covers associated Bakken midstream assets. Entitlement production from these assets in fourth-quarter 2020 was 48,000 boe/d (net of royalty interests).
In parallel with the transaction, Equinor Marketing and Trading will enter into a term purchase agreement for crude offtake with Grayson Mill Energy.
As part of the agreed transaction, all Equinor field employees and a significant number of the support teams working on the Bakken assets will have the opportunity to transfer to Grayson Mill Energy, Equinor said.
Closing is subject to customary conditions, including authority approvals.
Exploration & Development Quick Takes
PTTEP discovers gas offshore Malaysia
PTT Exploration and Production Public Co. Ltd. (PTTEP), through subsidiary PTTEP HK Offshore Ltd. (Malaysia Branch) (PTTEP HKO), discovered gas in Block SK417, 90 km off the coast of Sarawak, Malaysia.
Dokong-1, the first exploration well in the block, was drilled in November 2020, targeting gas in the sandstone reservoir. The well was drilled to 3,810 m TD and encountered over 80 m of gas column. The second exploration well will be drilled in the middle of this year as part of the exploration campaign.
Apart from SK417, PTTEP’s portfolio in Malaysia includes Block H, Block K, SK309, SK311, and Malaysia–Thailand Joint Development Area, all under production. Also included are SK410B, SK314A, SK438, SK405B, PM407, and PM415, all under exploration.
PTTEP HKO is operator in the block (80%). PETRONAS Carigali Sdn. Bhd holds the remaining share.
Providence gains consent for Barryroe site survey
Providence Resources PLC will begin work required to complete environmental and regulatory approvals for appraisal and development of Barryroe oil and gas field now that approval for a site survey has been granted by the Irish government.
The company received the green light to undertake a seabed and shallow geophysical survey and an environmental baseline and habitat assessment survey at the K-Site location, Barryroe, North Celtic Sea, within Standard Exploration License 1/11.
The offshore survey, the third in a series, is expected to be completed later this year. Its completion will enable the company to apply for any potential further works on the K site. Further regulatory approvals are required before drilling can take place on the field.
Barryroe lies about 50 km off the south coast of Ireland in 100 m of water and is one of the largest undeveloped oil and gas fields offshore Europe. Providence and its license partner Lansdowne Oil & Gas PLC agreed in December 2020 to farm-out 50% working interest in Barryroe field to Spoton Energy Ltd. and a consortium of international service providers (OGJ Online, Dec. 1, 2020).
Spoton and the consortium are expected to fund 100% of the early development program and full field development. Early development includes four wells and floating production facilities designed to appraise and produce the field. The campaign is expected to begin late-2022.
Petronas discovers oil offshore Indonesia
Petronas will assess well results to determine potential of an oil discovery made by subsidiary PC North Madura II Ltd. at Hidaya-1 within the North Madura II production sharing contract (PSC) area offshore East Java, Indonesia.
The well was spudded Jan. 7 and drilled to a depth of 2,739 m. It encountered an oil-bearing carbonate buildup with good reservoir qualities in the Ngimbang carbonate formation and tested at about 2,100 b/d with good crude quality.
PC North Madura II Ltd. is operator with 100% participating interest in the PSC. Petronas is also operator of Bukit Tua oil and gas field, offshore East Java, and is a joint venture partner in six other PSCs located both onshore and offshore Sumatera, Natuna Sea, East Java as well as Kalimantan.
Energean JVs let EPCI contract for subsea tieback offshore Egypt
NIpetco and PetroAmriya, two joint ventures between Energean and Egyptian Natural Gas Holding Co. (EGAS) and Egyptian General Petroleum Corp. (EGPC), awarded TechnipFMC an integrated engineering, procurement, construction and Installation contract for a subsea tieback offshore Egypt on the North El Amriya and North Idku concession (NEA/NI).
TechnipFMC will design, manufacture, deliver, and install subsea equipment including the subsea production system, subsea trees, production manifolds, umbilicals, flexible pipelines, jumpers, and associated subsea and topside controls. The contract is valued by the service provider at $75-250 million.
Energean made a final investment decision on the subsea tieback project in January (OGJ Online, Jan. 21, 2021). The NEA concession contains two discovered and appraised gas fields (Yazzi, Python) while the NI concession contains four discovered gas fields, one of which is readied for development. NEA/NI is due to deliver first gas in second-half 2022 with 49 MMboe of 2P reserves, 87% of which is gas. Peak production is expected at 90 MMscfd plus 1,000 b/d of condensates.
TechnipFMC is currently partnering with Energean to develop Karish gas field in the Mediterranean Sea offshore Israel.
Drilling & Production Quick Takes
Empire increases Beetaloo project prospective gas resource
Empire Energy Ltd. increased the prospective 2C gas resources for its 100%-owned permit EP187 in the Beetaloo subbasin of the Northern Territory, Australia, to 3.5 tcf—an increase of 47%.
The company also booked a maiden best estimate of prospective condensate resources of 27 million bbl.
The update, prepared by Netherland, Sewell & Associates Inc., used the technical results of last year’s Carpentaria-1 drilling program.
The reservoir properties and shale pay thicknesses encountered in the well exceeded pre-drill expectations, driving material increases in assessed gas and condensate resources.
The analysis was restricted to Empire’s current operations in EP187 and did not incorporate further assessment of the company’s northern properties targeting the Barney Creek or other McArthur basin shale units.
The Kyalla shale was deemed too shallow or not present and has been reduced to zero for prospective resource assessment.
Empire has received Northern Territory government approvals to carry out hydraulic stimulation and flow testing of the vertical Carpentaria-1 well. The company plans to begin the flow test program in this year’s second quarter to assess which zones within the Velkerri formation reservoir are likely to provide the optimal flow rates and gas-liquids contributions.
Norway production increased in January, NPD says
Norway’s liquids production averaged 2.137 million b/d in January, the Norwegian Petroleum Directorate reported. Norway’s daily liquids production averaged 2.135 million b/d in December (OGJ Online, Jan. 22, 2020).
Oil production in January is equal to the NPD’s forecast.
The average daily liquids production in January consists of 1.804 million b/o, 321,000 bbl of NGL, and 12,000 bbl of condensate.
The total petroleum production in January is about 20.9 million standard cu m oil equivalents. The total volume is 700,000 standard cu m oil equivalents higher than in January 2020.
Neptune starts Dugong appraisal drilling
Neptune Energy and partners began drilling the Dugong appraisal well in the Norwegian sector of the North Sea.
The objective is “to collect the data necessary to help provide certainty related to the reservoir, structure and recoverable resources, so the partnership can optimize the development solution,” said Steinar Meland, Neptune Energy’s director of subsurface, Norway. Data will also provide information “to help de-risk additional exploration and development opportunities in the license and in the surrounding area,” he said.
The Dugong license is 158 km west of Florø, Norway, at a water depth of 330 m, and is close to the existing production facilities of Snorre field. The reservoir lies at a depth of 3,250-3,400 m.
The discovery, in production license 882, was one of the largest on the Norwegian Continental Shelf in 2020 (OGJ Online, Jun. 18, 2020). Neptune estimates recoverable resources to be 40-120 MMboe.
The appraisal well is being drilled by the Deepsea Yantai, a new semisubmersible rig owned by CIMC and operated by Odfjell Drilling.
Neptune and the Dugong partners plan to drill an exploration well in the license in this year’s third quarter targeting the Dugong Tail prospect.
Neptune Energy is operator of the license (45%). Partners are Petrolia NOCO (20%), Idemitsu Petroleum Norge (20%), and Concedo (15%).
Canacol Energy progresses 2021 drilling program with tie-in
The onshore Colombia Oboe 2 development well is being tied into the Jobo gas processing plant after being completed as a successful gas producer, Canacol Energy Ltd., Calgary, said Mar. 2.
In the VIM 5 block, the well targeted the gas-charged Cienaga de Oro reservoir sandstones 55 ft (TVD) structurally up-dip, and 600 m laterally displaced from the Oboe-1 well.
The Flauta 1 exploration well, which completed drilling in February, did not encounter commercial gas and has been plugged. The well targeted a 3-way fault dependent closure, with potentially stacked gas charged reservoir sandstones over the reservoir.
The rigs are now being moved to drill the Cañahuate 4 development well and the Milano 1 exploration well on the Esperanza block. Both are expected to spud the second week of March and will take 5 weeks to drill and test.
The wells are part of the company’s 2021 drilling program in which it expects to drill 12 wells (9 exploration, 3 development), all operated with 100% working interest.
PROCESSING Quick Takes
Egypt’s Sidpec advances expansion of Alexandria petrochemicals complex
Egyptian Petrochemicals Holding Co. (ECHEM) subsidiary Sidi Kerir Petrochemicals Co. (Sidpec) has implemented process automation improvements from Honeywell International Co.’s Honeywell Process Solutions (HPS) to upgrade production capabilities as part of the previously announced expansion of Sidpec’s petrochemical complex in the El-Amerya—El-Nahda Territory of Alexandria (OGJ Online, Dec. 12, 2019).
As part of the 10-day automation upgrade, HPS migrated Sidpec’s existing Honeywell TotalPlant Solution (TPS) production system with the latest version of the service provider’s Experion Process Knowledge system, HPS said on Feb. 9.
The automation improvements are specifically intended to support collective production at the site following startup of Sidpec’s proposed expansion, which will add 450,000 tonnes/year of polypropylene production from propane feedstock (OGJ Online, Sept. 25, 2018).
Based on the latest information available from ECHEM and Sidpec, the new polypropylene plant is scheduled for commissioning in first-quarter 2022.
Sidpec’s Alexandria complex currently produces 300,000 tpy of ethylene, 225,000 tpy of polyethylene, 50,000 tpy of LPG, and 10,000 tpy of butene-1. Sidpec also plans to expand ethylene and polyethylene production capacities at the site to 470,000 tpy and 350,000 tpy, respectively, according to ECHEM’s website.
Thailand’s PTTGC lets contract for new Map Ta Phut olefins project
PTT Global Chemical PCL (PTT GC) has let a contract to a subsidiary of Samsung Engineering Co. Ltd., Seoul, for a recently approved project to expand use of propane as a feedstock at PTT GC’s existing olefins operations at Map Ta Phut Industrial Estate in Thailand’s Rayong Province, about 150 km southeast of Bangkok.
As part of the $120-million contract, Samsung Engineering (Thailand) Co. Ltd. will provide engineering, procurement, and construction (EPC) services for PTTGC’s proposed Olefins 2 modification project at the Map Ta Phut complex, Samsung Engineering said in a post to its official Facebook account.
The EPC contract award follows PTT GC’s final investment decision to move forward with the project taken at an October 2020 meeting of the operator’s board of directors, PTT GC said in a Jan. 26 filing to the Stock Exchange of Thailand.
Alongside increasing propane usage as a feedstock, PTT GC said the Olefins 2 modification project also aligns with the operator’s broader strategy of enhancing overall feedstock flexibility to ensure long-term competitiveness of the complex.
In addition to awarding the EPC contract to Samsung Engineering on Jan. 22, PTT GC said Thailand’s Office of Natural Resources and Environmental Policy and Planning (ONEP) has already approved the project’s environmental impact assessment report.
Currently scheduled to enter commercial operation during first-quarter 2023, the Olefins 2 modification project will require a total investment of about $165 million, according to PTT GC.
Lukoil’s Sicilian refinery lets contract for hydrotreater revamp
ISAB SRL, a subsidiary of PJSC Lukoil of Russia, has let a contract to DuPont Clean Technologies, a division of E.I. DuPont de Nemours & Co., to provide technology licensing for the upgrade of an existing processing unit to enable production of ultralow-sulfur fuel at its 320,000-b/d Priolo refinery in Sicily’s eastern province of Syracuse.
DuPont Clean Technologies will license its proprietary IsoTherming hydroprocessing technology to revamp the refinery’s trickle-bed diesel hydrotreater as part of a project to increase unit capacity to 31,000 b/sd as well as extend catalyst-cycle length, DuPont said on Feb. 23.
Alongside enabling production of low-sulfur fuels and extended length of catalyst life, the IsoTherming technology revamp also will allow ISAB the opportunity to process more-difficult cracked feedstock without sacrificing product quality or additional catalyst volume, according to the service provider.
Startup of ISAB’s IsoTherming diesel hydrotreater at Priolo is scheduled to occur by 2024, DuPont said without disclosing further details of the project.
Lukoil assumed ownership of the Priolo refinery—which consists of three production sites interconnected via a system of pipelines—from former joint-venture partner ERG SPA in late 2013 (OGJ Online, Jan. 2, 2014).
TRANSPORTATION Quick Takes
Papua LNG project advances with signed agreement
The proposed Total-operated Papua LNG project in the eastern highlands of Papua New Guinea has advanced step with the signing of a Fiscal Stability Agreement (FSA) between the joint venture participants and the government of Papua New Guinea.
Oil Search Ltd. said the FSA is the final step envisioned under the Papua LNG gas agreement (signed in April 2019) to guarantee Papua LNG fiscal stability. It follows amendments to acts passed by the PNG parliament in November 2020.
PNG Prime Minister James Marape said the FSA gives full effect to the Papua LNG gas agreement and the project will go ahead as a two-train development independent of the proposed P’nyang one-train project.
Marape said the FSA enables a focused development of Elk-Antelope gas fields in retention license PRL 15 which lies near the Purari River and about 360 km northwest Port Moresby.
The two-train facility will be built within the boundaries of the existing PNG LNG project operated by ExxonMobil at Caution Bay, enabling incorporation of some technical synergies into the design and a reduction in the environmental footprint.
Marape said he expects Total to conduct negotiations about redesign of the facility for a two-train development (not three-train as would have been the case with the addition of P’nyang) as well as commercial and other matters.
Once negotiations are complete, Papua LNG can advance to front-end engineering and design stage and an application can be made for a development license.
Papua LNG participants are Total, ExxonMobil, and Oil Search.
Sardinia LNG terminal nears completion
Construction of Higas SRL’s LNG terminal at the port of Oristano, western Sardinia, Italy, is in its final phase. The terminal, Sardinia’s first, is expected to enter service first-half 2021, operated and maintained by Reganosa.
The terminal includes a jetty capable of receiving LNG vessels up to 20,000 cu m, an unloading arm, six 1,500-cu m horizontal cryogenic holding tanks, two LNG truck loading bays, and a natural gas power generation system. The terminal will be able to load more than 8,000 LNG trucks each year (~180,000 tonnes) for subsequent distribution to satellite stations across the island.
Sardinia currently lacks a system of access to natural gas and only a small number of industrial customers receive LNG by truck brought to the island by ferry.
Reganosa will also operate the 1.7-million tpy Tema LNG terminal 6 km offshore Ghana. Tema took delivery of its floating regasification unit in January 2021 and is expected to enter service this quarter.