OGJ Newsletter

July 26, 2021


Cybersecurity measures ordered for pipelines

Owners and operators of oil and gas pipelines designated as critical pipelines must implement “a number of urgently needed protections against cyber intrusions,” the Transportation Security Administration (TSA) announced June 20.

The security directive requires “specific mitigation measures to protect against ransomware attacks and other known threats to information technology and operational technology systems, develop and implement a security contingency and recovery plan, and conduct a cybersecurity architecture design review,” TSA said.

The agency was advised in developing its security directive by the Cybersecurity and Infrastructure Security Agency, both agencies being part of the Department of Homeland Security (DHS).

“Through this security directive, DHS can better ensure the pipeline sector takes the steps necessary to safeguard their operations from rising cyber threats,” Homeland Security Secretary Alejandro Mayorkas said.

TSA did not release the text of the directive along with the announcement, nor has it yet responded to questions about whether the text will be made publicly available.

This is the second security directive issued by TSA to the pipeline sector since a ransomware attack on the Colonial Pipeline in early May. The first directive required pipeline companies to conduct a cybersecurity review, with a late-June deadline for reporting the results (OGJ Online, June 11, 2021).

Plains All American, Oryx Midstream create Permian basin JV

Plains All American and Oryx Midstream Holdings LLC, a portfolio company of Stonepeak Infrastructure Partners, have entered into a definitive agreement to merge assets, operations, and commercial activities within the Permian basin into a new joint venture, Plains Oryx Permian Basin LLC.

The deal will include all of Oryx’s Permian assets and, with the exception of Plains’ long-haul pipeline systems and certain of its intra-basin terminal assets, the vast majority of Plains’ assets are within the Permian basin.

The JV will be operated by Plains with a 65% interest. Oryx will hold 35%.

The joint venture will hold about 5,500 pipeline miles, 6.8 million b/d of pipeline system multi-segment capacity, direct downstream connections to all major intra-basin and downstream markets, and about 4.1 million dedicated system acres, including supply and facilities dedications. The companies expect about $50 million in operational, cost, and capital synergies on a run-rate basis within 12 months.

The Plains assets comprising a part of the JV include 3,900 miles of pipeline and related operational storage capacity located within the Permian basin, long-term acreage dedication, and marketing agreements covering some 2.8 million acres, and supply and facilities dedications.

The Oryx assets include some 1,600 miles of pipeline and related operational storage capacity in the Permian basin, in addition to long-term acreage dedication and marketing agreements covering about 1.3 million acres.

Subject to closing conditions (including refinancing by Oryx of existing debt) and regulatory approvals, the merger agreement is expected to close in this year’s fourth quarter.

Shell, Uniper sign European hydrogen MoU

Shell Gas & Power Developments BV and Uniper Hydrogen GMBH have signed an MoU to accelerate development of a hydrogen economy in Europe. The collaboration will examine infrastructure requirements for large-scale transport of hydrogen and CO2 from the ports of Rotterdam and Wilhelmshaven to North Rhine Westphalia (NRW).

Taking what the companies describe as a full value-chain approach, Shell and Uniper said they will work backwards from customer demand to identify key opportunities to develop the foundation of a new hydrogen economy in Europe.

Among the projects considered will be Shell’s Rheinland transformation, under which work is ongoing to repurpose an existing refinery into a state-of-the-art energy and chemicals park. Shell on July 2 opened a 10-Mw polymer electrolyte membrane electrolyzer, using wind and solar power to produce hydrogen, and is working with partners to expand capacity to 100-Mw.

Uniper seeks to expand the supply of hydrogen from its existing production sites at Rotterdam and Wilhelmshaven to the Shell Energy and Chemicals Park Rheinland sites at Wesseling and Godorf, Germany.

Uniper earlier this year repurposed the Wilhelmshaven site of a planned LNG terminal to instead be part of a proposed German national hydrogen hub (OGJ Online, Apr. 19, 2021).

 Exploration & Development Quick Takes

OMV continues exploration south of Oselvar field

More detailed studies will be needed to determine potential connection between proven resources in the Forties and Andrew formations in a recent exploration well drilled by OMV (Norge) AS and the 1/3-11 (Ipswich) oil discovery, the Norwegian Petroleum Directorate said in a June 12 release.

Well 1/3-13—the first exploration well in production license 970—was drilled by the Maersk Integrator jack up drilling rig near the 2008 Ipswich oil discovery about 6 km south of Oselvar field in the southern North Sea and 300 km southwest of Stavanger. The objective was to prove petroleum in reservoir rocks in the Tor formation from the Late Cretaceous Age.

It was drilled to a vertical depth of 3,285 m below sea level and was terminated about 100 m into water-bearing chalk in the Tor formation, with good to very good porosity, but low permeability. Water depth at the site is 71 m. The well has been permanently plugged.

The well also encountered a 3-m thick petroleum-bearing layer in the Ekofisk formation from the Palaeocene, which is probably residual oil.

It encountered oil in an 8-m thick sandstone layer in the Forties formation and a total of 3 m of sandstone in the Andrew formation, both from the Palaeocene age. The oil-water contact was not proven.

The sandstones are of moderate to very good reservoir quality.

The well was not formation-tested, but data acquisition has been carried out.

The rig will now drill development well 16/1-D-13 on Aker BP-operated Ivar Aasen field in the North Sea.

Gas flows from Empire’s Carpentaria-1 exceed expectations

Empire Energy Ltd., Sydney, recorded stronger-than-expected gas flows from the Carpentaria-1 wildcat in the Beetaloo subbasin of the Northern Territory.

The vertical well, in the company’s 100%-owned permit EP187, flowed gas to surface at an initial peak rate of 0.5 MMcfd and an initial stabilized rate of 0.37 MMcfd during a 72-hour test period. This was followed by an instantaneous peak rate of greater than 1.6 MMcfd after a short shut-in period.

Empire has lodged a discovery notice with the Northern Territory Government.

Fracture stimulation carried out in four zones in the Velkerri formation (Velkerri A, A/B, B, and C shales) created a fracture network within those zones which is liberating flows from the gas-rich target shales.

Empire has yet to process the data required to assess which zone is providing the greatest contribution to flow rates and the relative gas versus liquids composition of each zone. The analysis will be determined in the next few weeks, but the most productive zones will most likely be targeted for future horizontal appraisal drilling, the company said.

The volume of fluid being produced to surface is gradually reducing, indicating the fracture network is being drained of fluids enabling the gas flow, Empire continued.

The proportion of carbon dioxide in the gas stream is less than the measurable lower limit of 1% which is lower than other wells drilled in the Beetaloo where CO2 content is 1-3%.

Initial results indicate that the shallower liquids-rich gas of the eastern side of the subbasin has the potential for commercial hydrocarbon production in future horizontal wells which may have up to 100 fracture initiation points from 20-30 fracture stimulation stages, rather than the four stages in Carpentaria-1 vertical well, the company said.

Testing is continuing and preparations are being made to drill the first horizontal appraisal well.

Aker BP lets subsea contract for KEG field development

Aker BP has let a contract for Kobra East Gekko (KEG) field development in the Alvheim area of the North Sea to the subsea alliance of Aker Solutions, Subsea 7, and Aker BP.

Alvheim field (PL203) consists of the Kneler, Boa, Kameleon and East Kameleon structures, as well as the Viper-Kobra structures and Gekko discoveries and is also host to other developments in the area. Alvheim field lies in the central North Sea near the UK border.

The Kobra East and Gekko fields will be developed with a subsea tieback of 8 km to the Alvheim FPSO via the existing Kneler B subsea manifold. The selected concept has been designed with flexibility for further future subsea tie-back developments.

The work under the award comprises engineering, procurement, fabrication, and installation of subsea facilities for the KEG project, including pipelines, umbilicals, subsea x-mas trees, structures, and subsea control modules. The production pipeline is a pipe-in-pipe design.

Total investments linked to these contracts are projected at 1.7 billion kroner, the operator said. Installation campaigns are scheduled to begin in second-quarter 2022 and to be completed first-quarter 2024.

Project management and engineering will begin immediately. The project as a whole is pending approval from authorities of the PDO submitted June 30, 2021.

Aker BP operates PL203. Partners are ConocoPhillips Scandinavia AS and Lundin Energy Norway AS.

 Drilling & Production Quick Takes

Norway production increased in June, NPD says

Norway’s liquids production averaged 1.883 million b/d in June, the Norwegian Petroleum Directorate reported. Norway’s daily liquids production averaged 1.860 million b/d in May (OGJ Online, June 18, 2021).

Oil production in June is 3.6% lower than the NPD’s forecast, and 0.4% higher than the forecast so far this year, mainly due to technical problems and maintenance work on some fields, NPD said.

The average daily liquids production in June consists of 1.674 million b/o, 196,000 bbl of NGL, and 12,000 bbl of condensate.

The total petroleum production for the first 6 months in 2021 is about 112.8 million standard cu m oil equivalents.

Energy Resources JV spuds Lockyer Deep wildcat

The onshore North Perth basin joint venture of Energy Resources Ltd. and Norwest Energy NL has spudded its long-awaited wildcat Lockyer Deep-1 in permit EP 368 in Western Australia.

The conventional gas prospect trends northwest-southeast and extends into the JV’s neighboring permit EP426. It is about 10 km due north of the Strike Energy-Warrego Energy gas discovery at West Erregulla and 20 km east of Mitsui-Beach Energy’s Waitsia gas field.

Lockyer Deep-1 will evaluate the large fault-closed three-way dip structure at the Permian-age Kingia and High Cliff sandstone levels.

Norwest Energy estimates prospective resources of 167-1,122 bcf of gas.

Additional hydrocarbon potential exists within the shallower Wagina formation which does contain gas at West Erregulla and produces gas in Beharra Springs field to the south.

Energy Resources is operator with 80% interest. Norwest Energy holds the remaining 20%.

Kuwait Energy encounters pay in Al Jahraa sidetrack

Kuwait Energy Egypt drilled a sidetrack at Al Jahraa field in the Abu Sennan license, onshore Egypt, and encountered net pay in three reservoir units, partner United Oil & Gas PLC said in a July 19 release.

Al Jahraa-8 well commenced drilling on May 2, targeting the Abu Roash and Bahariya reservoirs in an undrained portion of the field. After drilling through the Upper Bahariya and reaching 4,071 m MD, inflow into the well was observed.

The well was brought under control but due to hole conditions in the highly deviated well, a decision was made to plug the well back above the Abu Roash C reservoir and drill sidetrack AJ-8ST1.

Due to hole conditions in the sidetrack, a liner was run to 4,314 m MD and the well landed without reaching the bottom zone of the Lower Bahariya reservoir which had been a pre-drill target.

Initial interpretations from the sidetrack indicate a total of over 40 m MD of net oil pay encountered cumulatively across three different reservoir units. Preliminary results indicate over 30 m of net pay in the Upper and Lower Bahariya reservoirs, and net pay also appeared in the Abu Roash E (AR-E) reservoir. The well has now been secured with liner and will be completed and tested across the three pay intervals.

After completing AJ-8, the EDC-50 rig will move about 7 km north of the field to drill the ASX-1X exploration well. This is a similar structure to the nearby discovery that was recently made at ASD-1X, with targets in Khoman, Abu Roash, and Bahariya reservoirs. It is expected to be the final well of the 2021 campaign.

United holds a 22% working interest in the licence, which is operated by Kuwait Energy Egypt (OGJ Online Jan. 4, 2021).


Turkmen petrochemical plants to change hands

The government of Turkmenistan is transferring ownership and operation of two petrochemical plants currently belonging to Turkmengaz to fellow state-owned operator Türkmenhimiýa, or Turkmenchemistry.

The natural gas-to-gasoline (GTG) complex at Ovadan-Depe near Ashgabat, in Turkmenistan’s Akhal Province, and the Kiyanly gas chemical complex in the Turkmenbashi district of Balkan Province will be transferred to the jurisdiction of Türkmenhimiýa “in a short time” following finalization of necessary documents, Turkmen state media said on July 12.

Announced by Turkmenistan’s President Gurbanguly Berdimuhamedov on July 9, the decision to transfer the chemical plants was made to “establish the stable operation of these plants, as well as release [Turkmengaz] from solving problems that are not within its competence,” according to Berdimuhamedov.

Further details regarding the proposed transfer of ownership of the two chemical enterprises were not disclosed.

Initially commissioned in October 2018, the $3.4-billion Kiyanly gas chemical complex—the largest in the region—processes 5 billion cu m/year natural gas via a gas separation unit equipped with Toyo’s Coreflux technology and BASF SE’s Oase technology produce 386,000 tonnes/year (tpy) of polyethylene and 81,000 tpy of polypropylene, with up to 4.5 billion cu m/year of remaining marketable gas shipped via pipeline for commercial use (OGJ Online, Aug. 27, 2020).

Built by a consortium of Kawasaki Heavy Industries and Rönesans Endüstri Tesisleri Ins¸aat Sanaýi ve Ticaret As¸ and officially entered into operation in June 2019, Turkmengaz’s $1.7-billion Akhal GTG complex is designed to process 1.785 billion cu m/year of natural gas to produce 600,000 tpy of Euro 5-compliant A-93 gasoline as well as 115,000 tpy of liquefied gas and 12,000 tpy of diesel using Haldor Topsoe AS’s proprietary Topsoe Improved Gasoline Synthesis (Tigas) (OGJ Online, Jan. 14, 2020).

As recently as August 2020, Turkmengaz was in discussion with Japan’s Kawasaki Heavy Industries Ltd. on a proposed expansion of the Akhal GTG complex that would involve construction of a second GTG plant at the existing complex as part of an ongoing bilateral collaboration partnership between Turkmenistan and Japan in the petrochemicals sector (OGJ Online, Aug. 31, 2020). The current and future status of the proposed expansion, however, have yet to be revealed.

LACC lets contract for Louisiana petrochemical complex

LACC LLC, a venture of Lotte Chemical Corp. subsidiary Lotte Chemical USA Corp. and Westlake Chemical Corp., has let a contract to McDermott International Ltd. to deliver engineering, procurement, and construction for a seventh heater to be added at LACC’s 1-million tonnes/year ethane cracking complex in Westlake, La. (OGJ Online, May 10, 2019).

Designed to support cracker operations at the site, the new heater will be equipped with proprietary Short Residence Time (SRT)-III technology from McDermott’s preferred technology partner Lummus Technology LLC, the service provider said on July 14.

EPC activities on the project are scheduled to begin immediately for a targeted commissioning date in fall 2023, according to McDermott.

Additional details regarding the contract, including its value, were not disclosed.

While new cracking furnaces typically are added to cracker operations to accommodate increased capacity, neither Lotte Chemical nor Westlake Chemical have indicated any official plans to expand production at the Westlake complex.

Commissioned in 2019, the $3.1-billion, 250-acre southwestern Louisiana petrochemical complex—which produces 2.2 billion lb/year of ethylene—also houses a 700,000-tpy monoethylene glycol plant operated by Lotte subsidiary Lotte Chemical Louisiana LLC (OGJ Online, Apr. 23, 2018).


Ksi Lisims LNG files initial project description

The Nisga’a Nation, Rockies LNG Partners LP, and Western LNG have filed the initial project description for their proposed floating 12-million tonne/year Ksi Lisims LNG plant with the Government of British Columbia and the Government of Canada. The plant would be stationed at Wil Milit on the northern tip of Pearse Island near the Nisga’a village of Gingolx, BC. Project partners expect commercial operations to begin late 2027 or early 2028. 

Two third-party natural gas pipeline projects are being evaluated to supply feed to Ksi Lisims LNG. Both have received regulatory approvals.

Project partners expect Ksi Lisims LNG to have net-zero carbon emissions. The plant will use hydropower generated in British Columbia and potentially carbon capture and storage, as well as other mechanisms such as carbon offsets and efficiency monitoring.

Ksi Lisims LNG is regulated under BC’s 2018 Environmental Assessment Act and Canada’s 2019 Impact Assessment Act. Project proponents will also conduct an assessment in accordance with Chapter 10 (Environmental Assessment and Protection) of the Nisga’a Final Agreement (Nisga’a Treaty), which will be incorporated into the BC environmental assessment and the federal impact assessment process.

Project partners have begun early engagement with First Nations, government and regulatory officials, and community leaders to introduce the project and to solicit comments on early drafts of the initial project description, many of which have been incorporated into the recent filing.

TotalEnergies signs tolling contract for Gladstone LNG

TotalEnergies signed a $750 million, 15-year tolling contract with Global Infrastructure Partners Australia (GIP) for the downstream infrastructure of the Santos-operated Gladstone LNG project owned by subsidiary Total GLNG Australia (TGA).

GIP will receive a throughput-based tolling fee calculated on TGA’s share of gas processed through the infrastructure with an effective date of Jan. 1, 2021.

TGA will retain full control and ownership of its 27.5% interest in the Gladstone LNG downstream joint venture.

The integrated LNG project involves production of natural gas from Fairview, Arcadia, Roma, and Scotia fields in the Surat and Bowen basins of southeast Queensland.

Gas is transported about 400 km to the liquefaction plant on Curtis Island near Gladstone. The two-train Curtis Island plant has a capacity to produce a total of 7.8 million tonnes/year of LNG.

The LNG plant was brought on stream in 2015.

Venice Energy hires GasLog to find South Australia FSRU

Venice Energy has agreed with GasLog Ltd. to negotiate a charterparty for supply of a 150,000-cu m floating storage and regasification unit (FSRU) as part of Venice’s proposed new LNG import terminal project in Outer Harbor, Port Adelaide, South Australia. Planned regasification capacity is 160 petajoules/year (415 MMcfd).

The company expects government and other approvals in the next few months, followed by an anticipated 12-month construction period from financial close and connection to the state’s gas network by end-2022 to early 2023. Interconnections with the Moomba to Adelaide Pipeline System and South-East Australia Pipeline are within 600 m of the planned terminal site.

Work will include construction of two new wharves in Outer Harbor.

As part of the agreement GasLog will provide a technical support crew to operate the terminal.