OGJ Newsletter

June 14, 2021


Victorian onshore conventional gas exploration to restart

A restart of the onshore conventional gas industry in Victoria, Australia, is expected July 1, 2021 following 3 years of detailed scientific investigations by the State government which found that such industry would not compromise the state’s environment or the agricultural sector.

However, the restart of exploration and development does not include coal seam gas or hydraulic fracturing, both of which are permanently banned in Victoria. The fracturing ban was added to Victoria’s Constitution in March.

The hiatus on all onshore gas exploration and development began with an administrative moratorium in 2012 in response to community concerns. The government passed a fracturing ban amendment to its resources legislation in 2017 and halted all conventional exploration and development activities until June 30, 2020.

During this time, a research program was implemented to understand the potential for new onshore conventional gas discoveries and the risk, benefits, and impacts of allowing the industry to continue.

Commercially feasible conventional gas resources yet to be discovered are likely in the onshore Otway and Gippsland basins and their development would not compromise the Victorian groundwater supplies of the agricultural sector, the study concluded.

The industry will proceed under a new regime of best practice, the hallmarks of which include stronger provisions for community engagement and a strict code of practice for well management.

The regulatory impact statement consultation period for the new regulations is expected to open early this month to enable assessment and feedback from stakeholders.

Diversified looks to expand new central focus area with Barnett asset deal

Diversified Energy Co. PLC has conditionally agreed to acquire certain Barnett shale upstream assets from Blackbeard Operating LLC, Midland, Tex., for a gross purchase price of $180 million.

Diligence work is continuing prior to confirming final terms. Currently, Diversified expects to close the deal in June.

The deal would offer Blackbeard entry into the Barnett shale and an extension of the company’s presence in its newly identified central regional focus area where it aims to build scale, it said in a May 29 release. 

The deal would add 96 MMcfed (82% natural gas, 17% NGL, 1% oil) of net production, 840 net wells (98% operated), and an average working interest of 65% on 123,000 net acres.

The conditional agreement comes on the heels of the close of its acquisition of certain Cotton Valley upstream assets from Indigo Minerals LLC, also in its new focus area (OGJ Online, May 4, 2021).

Through both acquisitions, Diversified would hold more than 300,000 net acres in its Central RFA, generating 192 MMcfed of net production.

Colgate expands Permian portfolio with Luxe Energy deal

Colgate Energy Partners III LLC, Midland, Tex., has grown its Permian basin footprint with a deal to acquire most of the assets owned by Luxe Energy LLC.

Luxe will continue to own and manage certain assets including a portion of the non-operated leasehold interests that are operated by MDC Reeves Energy LLC and its affiliates.

Colgate acquires from Luxe 22,000 net acres adjacent to its existing position in Reeves and Ward counties, Tex., current average net daily production of 17,000 boe/d, some 5,000 gross surface acres, and 1 rig running on Luxe’s existing Ward County position.

The combination holds about 57,000 net acres, some 45,000 boe/d, and 4 rigs running as of June 1.

Luxe Energy was formed in 2015 with an equity commitment from NGP Natural Resources XI LP and management.

Closing of the all stock deal occurred simultaneously with signing of a definitive agreement on June 1.

 Exploration & Development Quick Takes

ExxonMobil makes Stabroek discovery offshore Guyana

ExxonMobil Corp. has made a discovery at Longtail-3 in Stabroek block offshore Guyana, encountering 230 ft (70 m) of net pay, including newly identified, high-quality hydrocarbon bearing reservoirs below the original Longtail-1 intervals. The well is about 2 miles south of Longtail-1 and was drilled in more than 6,100 ft of water by Stena DrillMAX. Longtail-1 was drilled in 2018, encountering 256 ft of high-quality, oil-bearing sandstone.

Stena DrillMAX is one of two additional drillships ExxonMobil has deployed offshore Guyana since first-quarter 2021, Noble Sam Croft being the other. As the company advances its 15-well campaign in Stabroek block, DrillMAX will move to Whiptail-1, while Noble Sam Croft supports development drilling for Liza Phase 2. ExxonMobil now has six drillships operating off Guyana.

Earlier this year, topsides lifting for the 220,000-b/d Liza Unity floating production, storage, and offloading (FPSO) vessel occurred at Keppel Shipyard in Singapore. First oil from the FPSO, the development’s fourth, is expected in 2022 (OGJ Online, Mar. 19, 2021).

In other drilling activity in Stabroek, the Mako-2 evaluation well confirmed the quality, thickness, and areal extent of the reservoir. When integrated with the previously announced discovery at Uaru-2, data supports a potential fifth FPSO in the area east of the Liza complex. The Koebi-1 exploration well in Stabroek block has shown evidence of non-commercial hydrocarbons.

Stabroek encompasses 6.6 million acres. ExxonMobil last year increased its estimated recoverable resource base in Guyana to 8 billion boe.

ExxonMobil affiliate Esso Exploration and Production Guyana Ltd. is Stabroek’s operator and holds 45% interest. Hess Guyana Exploration Ltd. holds 30% and CNOOC Petroleum Guyana Ltd. 25%.

BP enters risk sharing contract for Clair development

BP has entered into an agreement with Baker Hughes and Odfjell Drilling for drilling and completions activity at the North Sea Clair field.

The scope of work initially targets a 15% increase in average annual production on Clair Ridge, the second phase development of the field. The 5-year agreement has an option to extend an additional 4 years and includes a new commercial relationship that will share risk and reward.

Offshore work and onshore support will use integrated operations level (IO3), moving tasks onshore from offshore. The Clair alliance will have a new governance structure with a project management team onshore and BP, Baker Hughes, and Odfjell Drilling personnel managing day-to-day drilling and completion operations offshore. The Clair alliance will be overseen by a steering group of representatives from all three companies.

With an estimated 7-8 billion bbl of oil in place, Clair field, 75 km west of the Shetland Islands, has an estimated production life extending beyond 2050. Phase one production began in 2005.

Clair Ridge is the second phase of development. The bridge-linked platforms, which delivered first oil in November 2018, are designed to recover an estimated 640 million bbl of oil and ramp up to 120,000 bo/d and 100 MMcfd at peak production (OGJ Online, Nov. 26, 2018).

Three additional wells were completed during 2020. Clair South, the third development phase, is under consideration in pre-FEED.

BP is operator at Clair (28.6%) with partners Shell (28%), ConocoPhillips (24%), and Chevron (19.4%).

Vintage Energy readying wireline evaluation at Odin-1

Vintage Energy Ltd. reported extensive gas shows in its primary target after reaching a total depth of 3,140 m in the Odin-1 well in the Cooper basin of northeast South Australia.

The company is conditioning the hole prior to running a wireline evaluation program to investigate the shows.

Odin-1 has been drilled into a fault-bounded Permian-age Patchawarra formation closure that is up-dip from a 1987 wildcat, Strathmount-1, that made what was then deemed a non-commercial hydrocarbon discovery.

More recent work suggests Strathmount-1 has conventional gas pay in the Permian-age Toolachee formation as well as conventional and tight gas pay in the Patchawarra.

Both the Toolachee and Patchawarra contain the gas shows found in Odin-1.

The Odin prospect trends northeast across the state border into Vintage’s ATP2021 permit in southwest Queensland and is about 10 km from the company’s recently discovered Vali gas field.

Vintage is operator at Odin with 42.5% interest. Parnters are Metgasco Ltd. 21.25%, Bridgeport (Cooper Basin) Pty Ltd. 21.25%, and Impress (Cooper Basin) Pty Ltd. 15%.

Okea to develop Hasselmus gas discovery

Draugen license operator Okea ASA and partners Petoro AS and Neptune Energy Norge AS have made the decision to develop the Norwegian Sea Hasselmus gas discovery. Hasselmus will be the first tie-back to the Draugen production platform and will add over 4,000 boe/d to production, Okea said in a June 1 statement.

The Hasselmus project is expected to recover some 10.6 MMboe as fuel and export gas and will also make possible the restart of export of associated gas including NGL which is currently being injected into the reservoir.

The development concept is a single subsea well with direct tie-back to the Draugen platform. Production start-up is planned for fourth-quarter 2023 with plateau gas production of more than 4,400 boe/d gross. Expected gross total investment for the project is 2.4 billion kroner.

The Hasselmus gas discovery lies on the western edge of the Trøndelag platform, 7 km northwest of the Draugen platform, in Production License 093. A single well (6407/9-9 T2) was drilled on the Hasselmus structure by A/S Norske Shell in 1999 which encountered a 16-m gas column and a 6.8-m oil column in high quality sands at a depth of 1,700 m.

Okea is operator of the license and the project with 44.56% working interest. Partners are Petoro AS (47.88%) and Neptune Energy Norge AS (7.56%).

 Drilling & Production Quick Takes

Talos to add Tornado field production with sidetrack

Talos Energy Inc., Houston, will bring online its recent Tornado well in the Green Canyon area of the Gulf of Mexico following an accelerated completion timeline expected to begin immediately. With existing infrastructure in place, production is expected by this year’s third quarter, ahead of initial expectations.

The company drilled the Tornado 3 sidetrack well (Tornado Attic well), which discovered pay in-line with pre-drill expectations. It is expected to produce 8,000-10,000 boe/d gross (80% oil) once online.

The Tornado Attic well was designed to optimize recovery and was drilled some 4,500 ft from the Tornado water flood injection well and 1,550 ft from the closest existing producer well. Drilling operations were conducted from the Seadrill West Neptune rig and encountered about 85 gross (63 net) ft of true vertical thickness pay in the B6 Upper Zone with rock properties and reservoir consistent with internal modeling and pre-drill expectations.

Tornado field was discovered in 2016 and lies about 3 miles south of the company’s Phoenix complex, which was acquired in 2013 and utilizes the HP-I floating production unit. To date Tornado field has produced 34 MMboe gross, about 80% of which is oil.

In 2020, Talos initiated the intra-well waterflood project, drilling an injection well which sources water from a large aquifer above the producing B-6 Sand. Known as a “dump flood,” the project is one of the first of its kind in a subsea, deepwater environment, Talos said. The higher-pressured aquifer naturally injects over 20,000 b/d of water into the lower-pressured producing reservoir at the downdip boundary of the geological formation, creating reservoir energy to help maintain production and increase ultimate recovery throughout the field.

Talos is operator of the field with 65% working interest. Kosmos Energy holds 35%.

President Energy adds three new wells in Rio Negro, Argentina

President Energy PLC completed and tested natural gas wells EV-1001, EV-1002, and LB-1002 in Las Bases and Estancia Vieja concessions, Rio Negro Province, Argentina.

Well EV-1002 has been successfully completed and tested after perforation of an 8.5-m interval in the Vaca Muerta reservoir. During testing, the well flowed at over 100,000 cu m/d (3.53 MMscfd or 580 boe/d) with an 8-mm choke and a wellhead pressure of 1,750 psi.

Unlike EV-1002, which has original pressure in a virtually undrained fault block, EV-1001 is in a producing block with more pressure depletion. Due to this and reservoir quality, the well was both perforated and fracture treated, requiring longer cleanup time. To assist in the cleanup of the near well bore, a treatment with CO2 is anticipated to take place in the next 21 days.

Combined with LB-1002—the first in the three-well drilling program—aggregate production is expected to reach 170,000 cu m/d (6 MMscfd or 1,000 boe/d). This is in line with expectations and translates into an equivalent 6,000 MMbtu/d.

EV-1002’s high wellhead pressure compared with the other EV wells requires balancing production from the field to optimize wells of varying pressure being online simultaneously. Due to high pressure, new wells in the same fault block as EV-1002 are being considered for later this year or the first part of 2022.


Chevron Phillips Chemical adding new unit at Old Ocean

Chevron Phillips Chemical Co. LP (CPChem), a joint venture of Chevron Corp. and Phillips 66, has undertaken a project to expand production of alpha olefins with addition of a grassroots on-purpose 1-hexene plant near its Sweeny petrochemical complex in Old Ocean, Tex.

The project, which broke ground on May 25, will include construction of a new 1-hexene unit equipped with CPChem’s proprietary technology that, once in operation, will use a feedstock of ethylene to produce 266,000 tonnes/year of high-purity, comonomer-grade 1-hexene, a critical component used in producing polyethylene (PE), the operator said.

Scheduled to begin official construction during third-quarter 2021 for targeted startup 2023, the planned Old Ocean 1-hexene project comes as part of CPChem’s program to help meet customers’ needs as global PE demand continues to grow, according to Mitch Eichelberger, executive vice-president of CPChem’s polymers and specialties business.

To be equipped with the latest advances in process design for maximum production, optimized resource efficiency, and reduced emissions in line with the company’s long-term sustainability strategy, the Old Ocean unit will join CPChem’s current operation of the world’s largest on-purpose 1-hexene plant at its Cedar Bayou chemical complex in Baytown, Tex. (OGJ Online, June 13, 2014).

Following commissioning of the Old Ocean plant, CPChem said it will have a total US 1-hexene capacity of 650,000 tpy.

The proposed Old Ocean expansion follows CPChem’s 2018 completion of the second and final phase of its $6-billion US Gulf Coast petrochemical project, which included startup of two 500,000-tpy PE plants in Old Ocean and a 1.5-million tpy ethane cracker at Cedar Bayou to help meet global demand for ethylene and ethylene derivatives based on abundant, cost-advantaged shale gas feedstock produced from US shale resources (OGJ Online, Mar. 12, 2018; Sept. 20, 2017).

Zeeland Refinery lets contract for decarbonization project

Dutch refiner Zeeland Refinery NV, a joint venture of TotalEnergies SE and PJSC Lukoil, has let a contract to a division of Air Liquide SA to deliver carbon capture and liquefaction technology for a new plant to be built as part of a decarbonization project at the operator’s 148,000-b/d refinery in Vlissingen, the Netherlands.

As part of the contract, Air Liquide Engineering & Construction (E&C) will license its proprietary Cryocap Flue Gas (FG) technology for a Cryocap FG plant that, once in operation, will capture more than 90% of emissions on the Vlissingen refinery’s existing hydrogen production units and have capacity to liquefy 2,400 tonnes/day of carbon dioxide (CO2), Air Liquide said.

Alongside technology licensing, Air Liquide E&C also will deliver the process design package and technical services for the proposed plant.

Proved in an existing unit now entering its sixth year of operation at Air Liquide’s site in Port-Jérôme, France, the new solvent-free Cryocap FG technology will enable the plant’s capture and liquefaction of CO2 contained in concentrated flue gases via a combination of adsorption and cryogenics technologies. Based on electricity rather than thermal energy, the Cryocap FG plant will allow Zeeland Refinery to further reduce its environmental footprint by providing flexibility to use a renewable-based energy source to power operation, according to the service provider.

Pure, liquefied CO2 captured as part of the decarbonization project—which aims to reduce total CO2 emissions from the Vlissingen site by more than 800,000 tonnes/year—will be transported for storage in the Dutch North Sea, Air Liquide said.

Application of carbon capture and storage to reduce CO2 emissions at Vlissingen comes as part of Zeeland Refinery’s broader, long-term carbon-reduction and sustainability initiatives at the site, according to the operator’s website.

Additional details regarding the proposed project have yet to be confirmed by Zeeland Refinery.


Tellurian signs 10-year supply deal with Vitol

Tellurian Inc. has finalized a 10-year, 3-million tonne/year (tpy) LNG sales agreement with Vitol Inc. Pricing will be free on board from Tellurian’s proposed 27.6-million tpy Driftwood LNG plant near Lake Charles, La., indexed to a combination of two indices: the Japan Korea Marker (JKM) and the Dutch Title Transfer Facility (TTF), each netted back for transportation charges.

The agreement follows a similar deal reached last week between Tellurian and Gunvor Singapore Pte. Ltd., also for 3 million tpy over 10 years (OGJ Online, May 27, 2021).

Telllurian estimates that at today’s prices, the agreement will generate $12 billion in revenue. It hopes to reach final investment decision by first-quarter 2022.

WBI gets FERC certificate for North Bakken pipeline expansion

WBI Energy Inc., the pipeline subsidiary of MDU Resources Group Inc. has received a US Federal Energy Regulatory Commission certificate of public convenience and necessity for its North Bakken Expansion project, a 250-MMcfd natural gas pipeline expansion.

The North Bakken expansion includes construction in western North Dakota of 62 miles of 24-in. and 20 miles of 12-in. OD natural gas pipeline, as well as a new compressor station and additional associated infrastructure.

The line will start near Tioga, ND, and extend to a new interconnect with TransCanada PipeLines Ltd.’s Northern Border pipeline in McKenzie County, ND. Northern Border runs 1,412 miles from Western Canada Sedimentary basin to consumers in the midwestern US.

WBI expects to complete the project by end-2021 at a cost of about $260 million. It can be expanded to 375-MMcfd if warranted by customer demand.

Novatek signs two Arctic LNG 2 offtake agreements

PAO Novatek wholly owned subsidiary Novatek Gas & Power Asia Pte. Ltd., has signed heads of agreement with Zhejiang Energy Gas Group Co. Ltd. and Glencore PLC for long-term supply of LNG from Novatek’s planned 19.8-million tonne/year (tpy) Arctic 2 LNG plant.

The agreement with Zhejiang Energy builds on the MOU signed by the parties in October 2019 and establishes commercial terms for the supply of up to 1 million tpy for 15 years. LNG will be supplied on a delivered ex-ship basis to Zhejiang Energy’s LNG terminals in China.

Novatek’s agreement with Glencore was for long-term supply of more than 0.5 million tpy from Arctic LNG 2. The LNG will be delivered to East Asia via the Northern Sea route.

Arctic LNG 2 will use three 6.6-million tpy liquefaction trains. It will also produce 1.6 million tpy of gas condensate.

At the end of first-quarter 2021, Novatek estimated overall progress for Arctic LNG 2 at 39%, with the first train roughly 63% completed. The full plant is expected to enter service in 2024, with deliveries from Train 1 expected the year before.

Earlier this year the OOO Arctic LNG 2 joint venture completed 20-year sales agreements with each of the project’s participants (OGJ Online, Apr. 28, 2021). The agreements reached by Novatek would come out of its share of the plant’s production. Project participants include: Novatek (60%), TotalEnergies SE (10%), China National Petroleum Corp. (10%), China National Offshore Oil Corp. (10%), and the Japan Arctic LNG consortium of Mitsui & Co. Ltd. and Japan Oil, Gas, and Metals National Corp. (10%).