GENERAL INTEREST Quick Takes
Consortium to back North Sea Greensand carbon storage pilot project
INEOS Energy, Wintershall Dea, and a consortium of 29 companies, research institutes and universities signed an agreement to support the next phase of the Greensand pilot project to demonstrate the safe and permanent storage of CO2 in the Danish North Sea, INEOS said in an Aug. 17 statement.
The Greensand consortium will now file a grant application with the Energy Technology Development and Demonstration Program in Denmark. If the application is successful, the consortium plans to begin work by yearend, with the offshore injection pilot expected in late 2022. The consortium will demonstrate that CO2 can be injected into the offshore Nini West reservoir in a cost-effective and environmentally safe manner, Wintershall Dea said in a separate statement Aug. 17.
Emissions will be captured at the Danish cement producer, Aalborg Portland, and transported to the Nini West reservoir by ship, it continued.
A full-scale project final investment decision could come after proof of concept, in second-half 2023, with storage in Nini West field by 2025, subject to funding and regulatory conditions.
The reservoir lies in the Siri area where Paleocene sandstone fields lie at a depth of 1.5-2.2 km and are encased “in one of the most competent cap rocks in the North Sea,” INEOS said.
Overall, the area is expected to hold storage potential of 0.5-1 million tonnes/year (tpy) of CO2 by 2025, increasing to a potential 4-8 million tpy of CO2 by 2030, Wintershall said.
Surge Energy acquires Howard County assets from Apache
Moss Creek Resources Holdings Inc., Houston, a wholly owned subsidiary of Surge Energy US Holdings Co., has acquired leasehold interest and wells from Apache Corp. in Howard County, Tex. for an aggregate purchase price of $37.5 million.
The acquired assets include some 4,000 net leasehold acres (100% held-by-production) adjacent to existing leasehold position in Howard County, about 800 net boe/d of production, and 14 net drilling locations primarily through increased lateral lengths and working interests. The deal includes saltwater disposal infrastructure and about 960 surface acres.
Fourth-quarter net production from Surge’s Moss Creek assets was 42,000 boe/d with about 455 net wells online, according to the company website. The company’s horizontal development program is targeting Wolfcamp A, Wolfcamp B, Middle Spraberry, and Lower Spraberry. Assets include 52,000 net mineral acres in Borden County and 53,000 net mineral acres in Howard County with a 78% average working interest.
PNG PM: Any Santos-Oil Search merger should maintain high local presence
Papua New Guinea Prime Minister James Marape said any merged entity of Santos Ltd. and Oil Search Ltd. should continue a significant local presence in the country and satisfy national interest.
Among other conditions, any merger agreement will be subject to PNG government approval.
“It is important that the merged entity ensures significant local influence on decisions affecting Papua New Guinea assets, jobs, and the broader community,” he said.
Any merger involving Oil Search will need to consider the timing of the development of PNG’s gas resources, the employment and training of PNG nationals, and the retention of in-country corporate offices and management, Marape said.
Oil Search’s operations in PNG constitute a large portion of the country’s GDP.
The Prime Minister said the government’s top priority is to ensure that projects like Papua LNG (Elk-Antelope) and P’nyang gas (PNG-LNG extension) proceed as soon as possible. He said he recognizes that the proposed merger can provide higher capacity and value to those projects as well as being a positive statement of investor confidence in PNG’s operating environment.
Current PNG LNG project joint venture interests are ExxonMobil (operator) with 33.2%, Oil Search 29%, Kumul Petroleum Holdings 16.8%, Santos 13.5%, JX Nippon Oil and Gas Exploration 4.7%, and Mineral Resources Development Co. 2.8%. A merger of Santos and Oil Search would see the new entity holding 42.5% interest.
Current Papua LNG joint venture interests are Total (operator) 40.1%, ExxonMobil 37.1%, and Oil Search 22.8%. A merger of Santos and Oil Search would result in a new entity holding Oil Search’s current 22.8%. These interests are prior to a PNG State back-in right of 22.5%.
Exploration & Development Quick Takes
Senex Energy sanctions Atlas CSG expansion
Senex Energy Ltd., Brisbane, has taken final investment decision (FID) for the proposed $40 million (Aus.) expansion of its Atlas coal seam gas project in southeast Queensland.
Atlas gas production is to be expanded by 50% to 18 petajoules/year from the current 12 petajoules/year.
The investment will be spent on new gas wells along with gas gathering and water management infrastructure and funded from existing cash reserves.
Drilling is expected to begin in September in conjunction with the company’s Roma North program to the west and gas sales will begin increasing in the next 12 months.
Senex is finalizing arrangements with Jemena to construct and fund the Atlas processing facility expansion under an extension of the existing tolling arrangements with commissioning expected during the first quarter of the 2023 financial year.
Atlas has existing 2P reserves of 270 petajoules, sufficient for 15 years life, Senex said.
Buru finds oil in Currajong-1
Buru Energy Ltd., Perth, found oil in its Currajong-1
wildcat in permit EP391 in the onshore Canning basin of Western Australia.
Wireline logs indicate porous zones with interpreted oil saturations at the top of the Ungani Dolomite equivalent section. Potential oil-bearing zones are also present in a lower dolomite section equivalent to the porous dolomite interval recorded in the nearby Praslin-1 well.
The log interpretation in these vugular dolomites needs flow testing validation. Buru has run 7-in. casing in preparation for a cased-hole test of the interpreted reservoir sections which will take place following regulatory approvals.
The well also detected a zone of up to 6% hydrogen in mudgas over an interval about 6 m from the measured depth of 2,014 m, validating the company’s view that the Canning basin could hold a future hydrogen resource, it said.
The next well site, Rafael-1, is expected to spud soon. The prospect is a geologically distinct formation to Currajong and has significantly larger potential resources, the company said.
Approvals for the third well in the program—Ungani-8 in production license L21—have been obtained. The well will be drilled after Rafael-1.
Buru is operator of all three wells with 50% interest. Origin Energy holds 50% in both the Currajong and Rafael wells. Roc has 50% interest in Ungani.
Petrogas lets contract for North Sea development
Petrogas E&P Netherlands has let a FEED contract to Enersea for development of A15 and B10 gas field as part of the AB Stage 2+ project. Both fields lie in the northern sector of the Dutch North Sea.
The assignment includes the basic design for the development of the two gas fields including a tie back to A12 field via existing pipelines through the installation of a hot tap. Gas from the new fields will be able to enter the current pipeline while the pipeline remains in operation. Two control umbilicals will be connected to the A12CPP host platform.
Both new platforms will be based on a tripod design with a minimum facilities topside.
In 2016, Petrogas E&P Netherlands granted concept development for both fields to Enersea.
In addition to the full FEED-scope of A15 and B10 gas field, Enersea also is responsible for the subsea scope and the brownfield modifications on the A12CPP platform.
Enersea is partnering with Cathie Associates for soil calculations on the foundations and Versatec will assist in the technical safety analysis.
Drilling & Production Quick Takes
Santos Bayu-Undan infill well exceeds expectations
Santos Ltd. said production from the first well in an infill drilling program on Bayu-Undan gas-condensate field in the Timor Sea has exceeded pre-drill expectations.
The well, the first in a three-well program, was brought on stream at 178 MMcfd of gas along with 11,350 b/d of liquids.
“We have seen a better-than-expected reservoir outcome with this first well of the campaign with successful results across both the primary and secondary targets in the well and a much higher initial gas production rate than expected,” said Kevin Gallagher, managing director and chief executive officer.
Bayu-Undan, 250 km west of Suai in East Timor and 500 km northwest of the Northern Territory in Australia, was discovered by ConocoPhillips in 1995 in a permit originally within the Zone of Cooperation (Timor Gap) between East Timor and Australia. Since the redrawing of the maritime boundary, it is now in East Timor’s jurisdiction and governed by a production sharing contract.
The field supplies gas to the Santos-operated LNG plant in Darwin and is recognized to be in its declining years. Nevertheless, success with the first well in the current Phase 3C infill program has increased gas supply capacity to the LNG operation and increased overall liquids production from the field to more than 25,000 b/d.
The Noble Tom Prosser jack up rig has started drilling the second of the three wells with the program scheduled for completion early in 2022.
Santos is operator of the field with 40% interest. Partners are E&S has 25%, Inpex 11.4%, ENI 11%, Jera 6.1%, and Tokyo Gas 3.1%.
DNO Norge spuds Gomez well near Tor
DNO Norge ASA spudded the Gomez exploration well on production license PL006C, offshore Norway. The well is close to Tor and Ekofisk complexes. Drilling is expected to take 45 days. Pre-drill estimates are 26-80 MMboe.
The well will be drilled by the Borgland Dolphin rig to a depth of about 3,300 m below sea level, targeting Paleocene age formations. The rig arrived on location Aug. 7 following completion of plugging and abandonment of three wells at Oselvar field on DNO-operated PL274.
Gomez is one of three exploration wells scheduled in 2021. The first, Røver Nord (DNO 20%), resulted in a likely commercial discovery, according to operator Equinor Energy AS. Mugnetind is expected to spud in this year’s fourth quarter.
DNO also is participating in two appraisal drilling campaigns covering previous discoveries made since 2019, namely Bergknapp (DNO 30%) and Black Vulture (DNO 32%).
DNO is operator of PL006C (65%). Aker BP holds 35%.
LUKOIL spuds exploration well in Gulf of Mexico
LUKOIL PJSC has spudded the Yoti West-1Exp well in Gulf of Mexico Block 12, 50 km off the coast of Tabasco, Mexico. The exploration well—the first in the block—is expected to provide geological and geophysical data needed to decide on further exploration.
The well is being drilled by the Valaris 8505 semisubmersible rig in 207 m of water. Exploration will focus on turbidite deposits of Upper and Lower Miocene.
The 521-sq m block has water depths of 150-400 m. LUKOIL Upstream Mexico is operator with 60% interest. Eni SPA holds 40%.
PROCESSING Quick Takes
Rompetrol targets September restart of Petromidia refinery
Rompetrol Rafinare SA—jointly owned by Kazakhstan’s state-owned JSC NC KazMunayGas subsidiary KMG International NV (54.63%) and Romania’s Ministry of Economy, Energy & Business Environment (44.69%)—plans to resume operations at its 5-million tonne/year Petromidia refinery in Na˘vodari, Romania, on the Black Sea, by the end of third-quarter 2021 following an early July explosion and subsequent fire that led to the plant’s sitewide shutdown (OGJ Online, July 7, 2021).
Based on the current work plan and pending delivery of equipment necessary for repairs and inspections of units affected by the July 2 incident, Rompetrol intends to restart production activities by the end of September, it said Aug. 16.
The proposed restart, however, remains contingent on verification and testing of equipment, as well as approval and certification of processing installations by regulatory authorities, according to Rompetrol.
In a separate release on Aug. 17, Rompetrol said it has now submitted its application to the Romanian Ministry of Environment’s National Agency for Environmental Protection for approval of the repair project. While the notice confirmed the project will involve works to repair and upgrade installations impacted by the incident—including the refinery’s catalytic reformer, diesel hydrotreating unit and reactor, and gas fractionator—the operator did not indicate an anticipated timeframe for the application’s approval.
In the meantime, Rompetrol said it currently is carrying out electrical, engineering, and other unidentified repair works in areas affected by the July event.
Announcement of the refinery’s planned restart follows the Aug. 13 release of the operator’s first-half 2021 financial report to investors in which Felix Crudu-Tesloveanu—Rompetrol Rafinare’s general manager—said he expects the Petromidia refinery to return to normal operational capabilities in the fourth quarter.
With an investigation into the incident presumably still under way, Rompetrol has yet to reveal a cause of the July explosion and fire, which originated in the refinery’s diesel hydrotreating plant.
ZPC commissions new alkylation unit at Zhoushan complex
Zhejiang Petroleum & Chemical Co. Ltd., also known as Zhejiang Petrochemical Co. Ltd. (ZPC), has completed startup of a second alkylation unit as part of the second phase of its 800,000-b/d integrated refining and petrochemical complex in Zhoushan, Zhejiang Province, China.
Equipped with Lummus Technology LLC’s proprietary CDAlky technology, ZPC’s new alkylation unit processes C4s from the complex’s upstream refining and petrochemical units to produce 45,000 b/sd of alkylate, which also results in in a very high concentration of isobutylene in the total olefins blend, Lummus said on Aug. 12.
Lummus confirmed startup of the new unit marks the second CDAlky unit now in operation at ZPC’s complex, which together have a combined alkylate production capacity of 59,000 b/sd.
The first 400,000-b/d phase of ZPC’s complex was commissioned in late 2018, while Phase 2—which will nearly double processing and production capabilities at the site—was scheduled for commissioning during first-quarter 2021.
ZPC—a joint venture of China-based Rongsheng Holding Group Co. Ltd. 51%, Juhua Investment Co. Ltd. 20%, Tongkun Investment Co. Ltd. 20%, and Zhoushan Marine Comprehensive Development and Investment Co. Ltd. 9%—previously said it would invest about 160 billion yuan to complete both phases of the project.
Kazanorgsintez lets contract for Kazan complex
PJSC Kazanorgsintez has let a contract to Maire Tecnimont SPA to deliver engineering and procurement (EP) for a new polyolefins production unit to be installed at the operator’s existing 1.7-million tonne/year (tpy) petrochemical complex in Kazan, Tatarstan, Russia.
As part of the Aug. 5 contract, subsidiaries Tecnimont Planung & Industrieanlagenbau GMBH and MT Russia LLC will provide EP services for a grassroots 100,000-tpy low-density polyethylene (LDPE)-ethylene vinyl acetate (EVA) plant, Maire Tecnimont said.
Awarded under a lump-sum scheme for EP services and a reimbursable scheme for the equipment and material supply, the €130-million will run for about 40 months from contract signing date to project completion, the service provider said.
To be based on technology licensed by Sumitomo Chemical Co. Ltd. of Japan that enables flexible production of LDPE and EVA from a single plant, the new LDPE-EVA unit—which will replace an existing but outdated unit at the complex—will use a specially designed autoclave reactor that increases efficiency of feedstock consumption and utilities to help reduce production costs and negative environmental impacts, Kazanorgsintez said in a Feb. 19 release.
Currently Russia’s sole EVA producer, Kazanorgsintez—which meets about 20% of EVA demand on the domestic market—said the new LDPE-EVA plant will increase the complex’s EVA production by more than sevenfold, allowing the operator to eliminate current EVA imports as well as provide additional volumes for export abroad.
TRANSPORTATION Quick Takes
bp completes sale-lease back of Tortue Ahmeyim FPSO
bp PLC has completed sale and lease back of the Greater Tortue Ahmeyim (GTA) floating, production, storage, and offloading (FPSO) vessel with an affiliate. The transaction secures additional funding for partner Kosmos Energy’s future GTA development costs. The FPSO is being built in China by Technip Energies NV. Delivery is expected late third-quarter 2022.
So far in 2021, Keppel Shipyard Ltd. has installed the four remaining sponsons on the 2.5-million tonne/year Gimi floating LNG plant being built in Singapore also to be deployed as part of GTA development. FPSO living quarters also have been installed, seven breakwater caissons have been transported offshore and three installed, and all four subsea trees have been built.
bp, as GTA operator (bp operator), with the consent of the GTA unit participants and the respective countries, agreed to sell the GTA FPSO to an affiliate. The FPSO will be leased back to bp operator under a long-term lease agreement, for exclusive use in the GTA project. bp operator will continue to manage and supervise the construction contract with Technip. Delivery of the FPSO to the affiliate will occur after construction is complete and the FPSO has entered international waters, with the lease to bp operator effective on the same date.
Capital expenditures associated with the GTA project in 2021 net to Kosmos had been estimated at $350 million. With completion of the sale and lease back, Kosmos’ 2021 capital expenditures associated with the GTA project dropped to about $190 million, with remaining cash calls on the project for 2021 covered through the proceeds of the sale. The balance of sale proceeds, as well as additional savings from the transfer of remaining FPSO construction payments to bp, are expected to be largely realized in 2022. The company expects to refinance national oil company loans later this year, providing some $100 million in additional financing for the GTA project. Kosmos will reimburse bp operator for its pro rata share of cost under the lease agreement, which will be classified as an operating expense.
Tortue Ahmeyim field development is on the C-8 block offshore Mauritania and the Saint-Louis Profond block offshore Senegal. The field holds estimated gas resources of 15 tcf. The integrated gas value chain and near-shore LNG development will export LNG to global markets and supply gas to Senegal and Mauritania (OGJ Online, Oct. 1, 2020).
bp operates Tortue with 61%. Partners are Kosmos 29%, Senegal-state Petrosen 5%, and Mauritania state firm SMHPM 5%.
Ksi Lisims FLNG begins public comment period
Nisga’a Nation, Rockies LNG LP, and Western LNG LLC on Aug. 10, 2021, began the 45-day public comment period on their proposed 12-million tonne/year Ksi Lisims floating LNG (FLNG) liquefaction plant at Wil Milit on Pearse Island on the northwest coast of British Columbia. Project partners expect commercial operations to begin late 2027 or early 2028. Expected project life is at least 30 years.
Ksi Lisims FLNG will convert natural gas from the Western Canadian Sedimentary Basin of northeastern British Columbia and northwest and central Alberta to LNG. Natural gas will be transported to the site via a pipeline originating in northeastern British Columbia. The project will select either TC Energy Corp.’s proposed Prince Rupert Gas Transmission system or Enbridge Inc.’s proposed Westcoast Connector Gas Transmission system to deliver gas to the plant. Both pipeline projects currently have valid British Columbia environmental assessment certificates and approved routes from northeastern British Columbia to its northwest coast.
At full build-out, Ksi Lisims FLNG will receive 1.7-2.0 bcfd of natural gas. Its proponents are targeting net-zero carbon operations within 3 years of start-up. This will be achieved, according to developers, once the project connects to the BC Hydro and Power Authority renewable power grid, in combination with a monitoring and measurement program, design elements intended to reduce greenhouse gas emissions, an operating culture focused on low emissions, purchase of carbon offsets, and the potential for carbon capture and sequestration.
The project is subject to a federal impact assessment process under Canada’s Impact Assessment Act and a provincial environmental assessment under British Columbia’s Environmental Assessment Act. The Impact Assessment Agency of Canada and British Columbia’s Environmental Assessment Office are working cooperatively for the initial phase of the project’s review.
The public comment period ends Sept. 24, 2021.