OGJ Newsletter

GENERAL INTEREST Quick Takes

Victoria lifts onshore conventional exploration moratorium  

The Victorian government has lifted the moratorium on exploration for conventional oil and gas resources, at the same time placing a permanent ban on hydraulic fracturing and on coal seam gas exploration in the state.

Victorian Premier Daniel Andrews said the government has introduced two bills into the state parliament to give effect to the actions.

Hydraulic fracturing was banned in Victoria in 2017 (OGJ Online, Nov. 26, 2016). During the 2018 election campaign, the Andrews-led Labor Party promised to enshrine that ban in the Constitution to make it harder for any future government to overturn.

The decision to allow a resumption of conventional onshore exploration follows 3 years of detailed investigations by the Victorian Gas Program which found an onshore conventional gas industry would not compromise the State’s environmental and agricultural credentials.

The investigation was chaired by Victoria’s lead scientist, Dr. Amanda Caples, who chaired an independent Stakeholders Advisory Panel including farmers, environmentalists, industry representatives, and local councils.

The studies identified potentially significant onshore conventional gas resources in Victoria, particularly in the Otway basin in the west of the state into South Australia where there is existing production and infrastructure.

Priority for any gas produced from future onshore production licenses will be given to the domestic market.

The legislation provides for an orderly restart of conventional gas exploration and development from July 1, 2021.

FAR, Woodside settle Senegal arbitration 

FAR Ltd., Melbourne, and Woodside Petroleum Ltd. subsidiary Woodside Energy (Senegal) BV agreed to a settlement of the dispute arising from Woodside’s acquisition of ConocoPhillips’s stake in the joint venture covering three blocks, including the Sangomar oil discovery, offshore Senegal.

This follows FAR’s evaluation of the arbitration ruling handed down earlier in March by the International Court of Arbitration of the International Chamber of Commerce in Paris.

Both parties have formally agreed to withdraw their respective claims and bear their own fees, costs, and expenses in the arbitration.

The arbitral tribunal has been invited to terminate the arbitration with immediate effect.

The matter was initiated by FAR in June 2017 and was heard in July 2019.

The tribunal found in favor of Woodside and declared that FAR did not have a pre-emption right over Woodside’s 2016 transaction to enter the Rufisque Offshore, Sangomar Offshore, and Sangomar Deep Offshore (RSSD) joint venture.

Woodside acquired a 35% share in the joint venture from ConocoPhillips for $350 million, but FAR maintained that a valid pre-emptive rights notice had not been issued to the JV partners by ConocoPhillips.

The shareholding in the RSSD joint venture remains at status quo: Cairn Energy PLC 40%, Woodside 35% and operatorship of the Sangomar development phase, FAR 15%, and Petrosen 10%. Petrosen also has the right to increase its equity to 18% on development.

Santos to sell down Timor Sea interests 

Santos Ltd., Adelaide, has agreed to sell a 25% interest in Darwin LNG plant and Bayu Undan gas field in the Timor Sea for $390 million to SK E&S.

The deal, which takes effect from Oct. 1, 2019, is conditional on completion by Santos of the acquisition of ConocoPhillips’ northern Australian and Timor Leste portfolio reported in October 2019. It also depends on third party consents, regulatory approvals, and a final investment decision on development of the Barossa project also in the Timor Sea north of Darwin.

SK E&S of South Korea currently has a 37.5% interest in the Barossa project that is designed to backfill Darwin LNG as supplies from Bayu Undan wane.

Santos chief executive officer Kevin Gallagher said discussions to sell down its equity in Barossa to a target ownership of about 40% are advanced.

A final investment decision for Barossa development is expected following completion of the ConocoPhillips acquisition and once all necessary technical, engineering and commercial contracts are in place, including the processing agreement with Darwin LNG.

Exploration & Development Quick Takes

Jadestone delays Nam Du and U Minh gas developments 

Jadestone Energy Inc., Singapore, will delay development of Nam Du and U Minh gas fields offshore Vietnam.

All capital spending which had been planned for the project in 2020 has been cancelled, resulting in a 50% ($90 million) reduction to the company’s capex guidance for the year to $80-95 million.

Jadestone said the decision is not only a recognition of the new measures to conserve the company’s capital resources but that it focuses on the largest and longest element of the company’s 2020 program and one that would not have contributed to cash flow before fourth-quarter 2021.

The company had been expecting Vietnamese government approvals for the project during this year’s first quarter, but they have not eventuated. The fields are now unlikely to be brought on stream until late 2022 at the earliest.

The remaining capital program for the year will mostly comprise infill drilling at Montara oil field in the Australian Timor Sea and at Stag oil field in the Carnarvon basin offshore Western Australia.

Paul Blakeley, Jadestone president and chief executive officer, said Nam Du and U Minh remained important domestic gas resources for Vietnam that will ultimately contribute to generating clean power and fertilizer for the ongoing development of the southwest Vietnamese economy.

“But, with ongoing Vietnamese Government delays to the FDP approval process, there is a short-term option for us to defer our spending commitments on the project, which we have decided to take,” he said.

He said the country has the potential to take temporarily cheap competitor piped gas, which is oil price linked and benefiting from the current market dislocation, and that Nam Du and U Minh fields can be developed when investment conditions improve.

Drilling & Production Quick Takes 

Diamondback anticipates 1-3-month completions hiatus  

Permian Basin-focused Diamondback Energy Inc., Midland, Tex., anticipates a 1-3-month break from completions while maintaining its previously cut 2020 capital guidance of $1.5-1.9 billion (OGJ Online, Mar. 11, 2020). On Mar. 19, the company indicated a completions break of 1 month.

Following the break, three to five completions crews are expected to operate and complete 170-200 gross (153-180 net) wells with an average lateral length of 10,000 ft this year, the company said Mar. 31.

The company plans to exit the year’s third quarter operating eight drilling rigs, and exit the year operating seven drilling rigs. Additional cuts could be made should conditions warrant, the company said.

Full year revised 2020 production guidance is 295,000-310,000 boe/d, down from 310,000-325,000 boe/d. Full year revised 2020 oil production guidance is 183,000-193,000 million b/d. The company expects a fourth-quarter 2020 exit rate production guidance of 170,000-180,000 million bo/d (275,000–290,000 boe/d).

Diamondback believes it can maintain the fourth quarter 2020 exit rate oil production through 2021 with four to five completion crews, six to eight operated drilling rigs, and a capital budget 20-30% less than 2020’s current $1.5-1.9 billion capital budget.

An allocation breakdown of the revised budget was also provided. Drill, complete, and equipment (DCE) spend is expected to reach $1.31-1.63 billion, with an additional $100-150 million of midstream capital, and $90-120 million of infrastructure capital.

Ring Energy to cease 18-well drilling program  

Ring Energy Inc., Midland, will cease further drilling until commodity pricing stabilizes, the company said Mar. 10. The company will continue to spend on infrastructure upgrades and improvements it deems necessary to maintain current production. Meanwhile, the company is in discussions related to the marketing of its Delaware basin asset.

Reported in February, the company’s preliminary capital expenditure budget of $85-90 million for the year included the drilling of 18 new horizontal wells (13 1-mile, 5 1.5-mile) on the Northwest Shelf (NWS) asset in the Permian Basin; well workovers including converting wells to rod pump; infrastructure upgrades/extensions on NWS, Central Basin Platform, and Delaware assets, along with all contractual drilling obligations, including projected costs specific to non-operated wells.

Four of the wells have been drilled.

RockRose drills two wells at West Brae 

Rockrose Energy PLC has spud the second of two infill development wells at West Brae in the central North Sea Mar. 9 following completion of the first. Production from the first well is delivering in line with expectations and first production from the second well is expected in this year’s second quarter.

Drilled by the Noble Houston Colbert jackup drilling rig, the wells—designated WPGZ and WPOZ—are designed to access 2P reserves of over 3 million bbl and add net production of 2,500 b/d.

The wells are part of a seven-well development for 2020 aimed at enhancing production by over 8,500 b/d (net) this year and next. The company seeks to convert 2C resources to 2P reserves and deliver extended field life. West Brae produces from the Upper Paleocene/Eocene Sele formation and the Eocene Balder formation.

RockRose is 40% owner and operator at West Brae. TAQA Bratani, a wholly owned subsidiary of Abu Dhabi National Energy Co. PJSC, will assume operatorship of the Greater Brae Area from RockRose subject approval by the Secretary of State (OGJ Online, Jan. 17, 2020).

Gulf Keystone suspends Shaikan drilling

Gulf Keystone Petroleum Ltd. will suspend its current drilling campaign at its operated Shaikan field in the Kurdistan region of Iraq until conditions related to Coronavirus (COVID-19) improve to ensure safe operations.

To limit the spread of the virus, the Kurdistan Regional Government has put in place a series of tight controls on the movement of personnel into and around the region, thus, drilling is suspended with the SH-13 well.

Production rates from the field are at 38,000 b/d of oil. Production currently continues unaffected, but the company has restricted access to its production facilities.  Therefore, certain construction activities related to the expansion to 55,000 b/d of oil, also have been suspended until circumstances improve (OGJ Online, Jan. 17, 2019).   

The planned production increase, scheduled for this year’s third quarter, and average production guidance of 43,000– 8,000 b/d remain priorities, the company said, but the suspension may impact its ability to meet these targets.

PROCESSING Quick Takes 

Total delays restart of Grandpuits refinery 

Total SA has postponed restarting its 101,000-b/d Grandpuits refinery near Melun in northern France following a planned maintenance shutdown earlier in the month as a result of the country’s ongoing reduced demand for fuels amid the coronavirus (COVID-19) pandemic.

The refinery, which ceased production in early March for execution of scheduled maintenance on unidentified units at the plant, previously was due for restart by the end of the month, Total said in a release.

While Total confirmed the Grandpuits site will maintain unidentified “partial activity” during the prolonged shutdown period, the operator did not indicate a specific timeframe for when it might resume operations at the refinery, which supplies much of the greater Paris region with refined fuel products.

Total did not disclose details of scheduled maintenance that was to be conducted during the month-long shutdown of the Grandpuits-Gargenville refining platform, which—before the COVID-19 interruption—most recently was scheduled for its next major turnaround in 2021, according to the operator’s website.

To date, it remains unclear whether the planned 2021 turnaround in any way will be impacted following Total’s Mar. 23 announcement that—in a context of oil prices near $30/bbl—the operator will cut its 2020 organic capex budget by more than $3 billion, or 20%, reducing 2020 net investments to less than $15 billion (OGJ Online, Mar. 23, 2020).

NZ’s Marsden Point refinery halves production 

The Marsden Point oil refinery, operated by Refining New Zealand at Whangarei on the east coast of the North Island of New Zealand, is halving production for at least the next 3 months due to falling fuel demand in the country.

Refining NZ, whose major shareholders (and major customers) are BP, Mobil, and Z Energy, said the plan is to produce less fuel with fewer staff by closing down sections of the plant and concentrating on key fuels.

Managing director Paul Zealand said the immediate focus in this period of uncertainty is to continue to operate the refinery and the pipeline to Auckland safely to meet customers’ reduced need for high quality transport fuels.

The staff numbers will be cut by two thirds, leaving 200 people on site. Other staff will be working remotely to ensure the back-room operations continue.

Zealand said that supplies of crude oil from overseas have not been disrupted and are arriving as scheduled, but it is likely that with reduced demand, the refinery’s stocks of various products will rise.

All construction work at the refinery will also cease for the moment except projects required for the refinery’s safe operation.

Thai Oil advances Sriracha refinery expansion, upgrading project 

Thai Oil PLC is advancing construction on its previously announced Clean Fuel Project (CFP) at its 276,000-b/d refinery at Sriracha, Thailand (OGJ Online, Apr. 11, 2017).

A ceremony for the laying of the foundation stone for the project’s main production control building was held on Mar. 16, the operator said.

The $4.825-million CFP includes retirement of two crude distillation units (CDU). The addition of a fourth, 220,000-b/d CDU to the existing third unit will raise the refinery’s total crude capacity to 400,000 b/d.

The project also will add a vacuum gas oil hydrocracker, a residue hydrocracker, a hydrogen manufacturing unit, a naphtha hydrotreater, a diesel hydrodesulfurization unit, a sulfur recovery unit, and an electric power plant fueled by residue pitch.

The refinery, now 100% dependent on light crude, will have a crude slate after completion of the project of 40-50% light crude, 5-15% medium crude, and 40-50% heavy crude.

The CFP also will improve product yields to 25% light distillate, 62% middle distillate, and 13% others, such as sulfur, long residue, and reformate, with no fuel oil.

As the private sector’s first megaproject in the Eastern Economic Corridor to position Thailand to become Southeast Asia’s energy hub, the CFP additionally aligns with current global market conditions and changing regulations such as the reduction in fuel oil use by marine transport as well as production of Euro 5-quality gasoline and diesel for improved environmental quality, Thai Oil said.

The CFP, on which ground officially broke for construction in September 2019, is scheduled to begin commercial operation in 2023.

Thai Oil previously let a $4-billion contract to a consortium of Saipem, Petrofac, and Samsung for the CFP, under which the partners will deliver engineering, procurement, construction and startup services for new units and upgrading of existing units (OGJ Online, Oct. 19, 2018).

The operator also signed a $757-million sales and purchase agreement with Global Power Synergy Plc (GPSC) for the electric power plant, or energy recovery unit (ERU), to be added as part of the CFP, Thai Oil said in a May 9, 2019, release.

GPSC’s investment in the ERU—which will generate power and steam using petroleum pitch from the refinery as its main fuel—will help Thai Oil reduce its CFP investment burden by 15%, Thai Oil said.

TRANSPORTATION Quick Takes 

Gazprom begins Power of Siberia 2 pipeline design, survey work 

Gazprom will begin the pre-investment phase of its Power of Siberia 2 natural gas pipeline project, having received instructions to do so from the Russian government. Pre-investment includes a feasibility study, design, and survey work. Power of Siberia 2 would deliver 50 billion cu m/year (bcmy) to western China via Mongolia.

The company in 2020 plans to build 1,942 km of gas trunklines, bring 114 wells onstream, and put into operation three gas treatment units with a combined capacity of 27.5 million cu m/year (mcmy).

Pipeline construction plans include construction of the Gryazovets–Volkhov–Slavyanskaya line to feed Nord Stream 2. The Slavyanskaya compressor station is in the Kingisepp district of the Leningrad region and will include 11 GPA-32 Ladoga turbines with a total capacity of 352 Mw. Installation of six of these compressors as well as associated air-cooling units and gas treatment plants has been completed. Pipeline drying was underway in February 2020.

Gazprom is also continuing pre-development of Kharasaveyskoye gas and condensate field in the Yamal peninsula. Gazprom began Kharasaveyskoye development in 2019 and said production will start in 2023 at 32 bcmy from Cenomanian-Aptian deposits. Later production will come from deeper Necomian-Jurassic strata (OGJ Online, Mar. 21, 2019).

The company has injected 72.2 bcm of gas into underground storage since October 2019 and has daily deliverability of 843.3 mcm. Gazprom says its gas production capacity is 545 bcmy.

Gazprom produced 500.1 bcm in 2019, exporting 199.3 bcm. The export figure was slightly less than its record 2018 gas exports of 201.8 bcm. The company said its 2019 share of the European market was 35.6%.

Northern Hemisphere awards Mexico pipeline, storage contract 

Northern Hemisphere Logistics Inc. has hired Mirage Energy Corp. to participate in development of Northern Hemisphere’s Isthmus Corridor project. The project includes underground natural gas storage and pipeline connecting that storage to the country’s transmission system, as well as rehabilitation of crude and products ports on both the Gulf of Mexico and Pacific coasts and connecting pipelines.

Cenote Energy S. de R.L. de C.V.’s underground natural gas storage site’s Phase 1, part of the Isthmus Corridor project, will have 52 bcf of working gas storage, expandable to 786 bcf once fully developed and as demand warrants.

Isthmus Corridor also includes WPF Mexico Pipelines S. de R.L. de C.V.’s 42-in. OD pipeline connecting this storage to Station 19 on Mexico’s national pipeline system and from there to the Los Ramones hub. An existing 48-in. OD pipeline will be rehabilitated and interconnected, creating a 1,000-mile system spanning the Mexican isthmus and boosting gas deliveries to the southern part of the country.

Northern Hemisphere Logistics S.A.P.I. de C.V.’s hydrocarbon liquids docks at Coatzacoalcos, Veracruz, on the Gulf of Mexico will be rehabilitated, including installation of new monobuoys. Pipelines, 30- and 48-in. OD, connecting Coatzacoalcos with Salina Cruz, Oaxaco, on the Pacific coast will also be rehabilitated, including pumping stations and tankage. New monobuoys will be installed at Salina Cruz as well.

The agreement gives Mirage 30% participation in the $6-billion project.

Phillips 66 defers crude pipelines, fractionation 

Phillips 66 is deferring its Red Oak and Liberty pipelines and its Sweeny Frac 4 project as part of reducing 2020 consolidated capital spending by $700 million to $3.1 billion. Phillips 66 also postponed making a final investment decision on its ACE Pipeline.

Phillips 66 in 2019 formed two separate 50-50 joint ventures to build Red Oak and Liberty. The company and Bridger Pipeline LLC formed Liberty Pipeline LLC to build the 24-in. OD Liberty Pipeline to transport crude oil from the Rockies and Bakken production areas to Cushing, Okla. With Plains All American Pipeline, Phillips 66 formed Red Oak Pipeline LLC to build the Red Oak Pipeline system to transport crude oil from Cushing and the Permian basin to Corpus Christi, Ingleside, Houston, and Beaumont, Tex. Initial service from Cushing to the Gulf Coast had been targeted for as early as first-quarter 2021 (OGJ Online, June 10, 2019).

Phillips 66, Harvest Midstream Co., and PBF Logistics LP announced plans in early 2019 to jointly develop the ACE Pipeline system to transport crude from the market hub in St. James, La., to downstream refining destinations in Belle Chasse, Meraux, and Chalmette, La. (OGJ Online, Jan. 14, 2019).

Sweeny Frac 4 is a planned 150,000-b/d fractionator at Phillips 66’s Sweeny refinery complex in Old Ocean, Tex. The company does not expect DCP Midstream to exercise its option to participate in Sweeny Fracs 2 and 3 in 2020 and is also deferring or cancelling certain discretionary projects in its refining segment. Sweeny Fracs 2 and 3 are planned 150,000-b/d expansions. Sweeny Frac 1 (100,000 b/d) entered service in 2015.

The company’s reduction in adjusted capital spending from its announced $3.3-billion budget was partially offset by an anticipated $400-million reduction in cash capital contributions from DCP Midstream.