OGJ Newsletter
GENERAL INTEREST Quick Takes
Trump extends drilling moratorium
President Trump extended a drilling moratorium to federal waters off the coast of North Carolina with a decision issued Sept. 25 under authority of the Outer Continental Shelf Lands Act.
The moratorium will run 10 years, from July 1, 2022, to June 30, 2032. It is an extension of a moratorium covering the eastern Gulf of Mexico and the Atlantic coasts of Florida, Georgia, and South Carolina.
Originally the moratorium applied only to the eastern Gulf of Mexico and was scheduled to expire June 30, 2022, but in early September Trump added another decade to its length and expanded it to the South Atlantic coast (OGJ Online, Sept. 8, 2020).
Trump did not offer an explanation for his North Carolina decision, but Sen. Thom Tillis (R-NC) mentioned the moratorium 5 days earlier in a video statement posted to his Senate website.
“This morning, I spoke with President Trump, and I asked him to extend the offshore drilling moratorium to North Carolina. I’m pleased to announce the president will be doing just that,” Tillis said Sept. 21.
Tillis is in a race for reelection, with polls suggesting he and his Democratic challenger, Cal Cunningham, are running neck-and-neck. Trump also has to worry about winning North Carolina in his own reelection bid.
Trade associations representing the oil and gas industry released statements expressing their disappointment.
The decision “takes thousands of new jobs and critical revenue for states off the table at a time when the economy is struggling,” said Lem Smith, vice-president of upstream policy at the American Petroleum Institute.
Moratoriums lead to “outsourcing of energy production and economic growth as countries such as Russia happily wait in the wings to make up our domestic energy supply gap,” said Erik Milito, president of the National Ocean Industries Association.
Petrobras seeks operatorship of Foz Do Amazonas assets
Petrobras agreed to acquire operatorship and working interest in five exploration blocks in the Foz Do Amazonas basin from Total E&P do Brazil Ltda. The deal will see Total exit blocks FZA-M-57, FZA-M-86, FZA-M-88, FZA-M-125, and FZA-M-127, which lie in ultradeep waters 120 km offshore Brazil.
Earlier in September, Total said it had resigned operatorship in Foz do Amazonas basin and had notified block partners in August (OGJ Online, Sept. 8, 2020).
The five blocks were acquired in the National Petroleum, Natural Gas, and Biofuels Agency’s (ANP) 11th bidding round by a consortium operated by Total (40%), in partnership with Petrobras (30%) and BP Energy do Brasil Ltda. (30%).
Petrobras intends to increase its stake to up to 70%, depending on the preemptive right of BP.
Closing of the proposed transaction is subject to the regulatory agencies’ approval.
NPD approves Tor II startup
ConocoPhillips gained approval for startup of Tor II facilities in the southern North Sea from the Norwegian Petroleum Directorate. The operator expects startup to begin in this year’s fourth quarter.
Tor, discovered in 1970, lies 13 km northeast of Ekofisk field in 70 m of water with a reservoir depth of 3,200 m. The field mainly lies on Block 2/4 in production license 018, but a small part extends into Block 2/5 in PL 006. It produced from 1978 to 2015. Oil and gas was produced from fractured chalk of Late Cretaceous age in the Tor formation and of early Paleocene age in the Ekofisk formation. At shutdown, only 20% of the resources in place had been produced.
A plan for development and operation (PDO) for new development of the field, Tor II, was submitted in July 2019, and approved by the Ministry of Petroleum and Energy in the fall (OGJ Online, July 1, 2019).
Tor II comprises two new subsea templates to be installed on Tor field about 1 km west of the original Tor platform, with no connection to the shut-in facilities. Eight new production wells will be drilled and connected by pipeline to existing risers at the Ekofisk complex, about 13 km away. Resource potential for the Tor II project is 60-70 MMboe.
ConocoPhillips is operator with an 30.66% interest. Partners are Total, Var Energi, Equinor, and Petoro.
BOEM, BSEE to research potential policy changes
The Bureau of Ocean Energy Management (BOEM) and the Bureau of Safety and Environmental Enforcement (BSEE) aim to advance new research into whether certain policy changes could help increase oil and gas production from deepwater infrastructure already in place in the Gulf of Mexico (GoM).
The study will examine specific economic parameters used by BOEM and BSEE for new and high-cost technologies like extended-reach subsea tiebacks. Implementation of these parameters could minimize stranded or left behind hydrocarbon resources. This research would apply to developments that might connect to deepwater facilities that have additional production capacity.
Deepwater production, which comes from depths greater than 200 m, accounts for 92% of total GoM offshore oil production, and 14% of all domestic oil produced in the US. In 2019, facilities in deepwater GoM averaged a record-breaking 1.7 million b/d of oil.
About 4 out of 5 deepwater facilities are producing less than 50% of their daily oil production capacity, based on a 3-year average of daily production rates. BOEM and BSEE identified contingent resources that exist 30-60 miles from existing facilities. This research will identify any difficulties that new technological advances may face, that could potentially hinder production and project economics.
Exploration & Development Quick Takes
Petrobras finds hydrocarbons in southern Campos basin
Petrobras identified hydrocarbons in the first exploratory well of Block C-M-657 in the southern portion of the Campos basin offshore Brazil. Well 1-BRSA-1376D-RJS (Naru) is about 308 km from Rio de Janeiro in 2,892 m of water.
The well verified presence of hydrocarbons in carbonate reservoirs of the presalt section. Well data will be analyzed to better assess the potential and direct exploratory activities in the area.
Block C-M-657 was acquired in March 2018 during the National Petroleum, Natural Gas, and Biofuels Agency’s (ANP) 15th bidding round. Petrobras is operator with 30%. Partners are ExxonMobil 40% and Equinor 30%.
Strike begins new appraisal program at West Erregulla
The 50-50 joint venture of Strike Energy Ltd. and Warrego Energy Ltd. began the first of three new appraisal wells on West Erregulla gas field onshore North Perth basin permit EP469.
West Erregulla-3 spudded Sept. 21. It will be followed immediately by Nos. 4 and 5.
Strike, as operator, said all three wells will be drilled to depths of about 5,000 m.
West Erregulla-3 is designed to determine the continuation of the commercial gas accumulation in the northern fault block, while West Erregulla-4 and -5 will appraise the reservoir distribution in the central fault block.
The wells will be cored and logged before being flow tested and, if successful, completed as future producers across the Kingia-High Cliff reservoirs for the proposed Phase 1 field development.
The Wagina reservoir gas discovery in West Erregulla-2 also will be appraised during the West Erregulla-4 and -5 drilling program.
The JV made the three-reservoir West Erregulla discovery drilling West Erregulla-2 in August-September 2019.
Strike and Warrego still aim to bring West Erregulla Phase 1 development on stream during first-half 2022 via a 50 terajoules/day processing plant and connecting pipeline to the nearby Dampier-Bunbury trunkline.
Empire spuds Carpentaria-1 in Beetaloo basin
Empire Energy Group Ltd. has spudded its Carpentaria-1 well in permit EP187, Beetaloo subbasin, Northern Territory, Australia.
The news follows the Sept. 22 report that Origin Energy began fracturing its Kyalla-117 well near Daly Waters (OGJ Online, Sept. 22, 2020).
Empire holds 100% interest in EP187 and plans to drill the Carpentaria wildcat to a depth of about 2,900 m.
The company plans to evaluate the two unconventional shale targets—Velkerri and Kyalla—which which have been independently assessed to hold an estimated prospective resource of 2.4 tcf of gas equivalent in the permit.
Drilling and evaluation is expected to take 40 days.
The well design allows for suspension and future re-entry, fracture stimulation, and flow testing which the company expects to begin in second-quarter 2021.
Drilling & Production Quick Takes
CNOOC starts production at Jinzhou 25-1
CNOOC Ltd. commenced production at Jinzhou 25-1 oilfield 6/11 in central Liaodong Bay, Bohai Sea. Average water depth at the site is 22.5 m.
A total of 19 production wells and 10 water injection wells are planned. Peak production of 16,500 bo/d is expected in 2023.
One eight-legged wellhead platform was built in connection with the project, which connects to existing facilities at Jinzhou 25- and Jinzhou 25-1S oilfields.
The project is one of 10 the operator expected to put on stream this year as part of a plan to steadily increase its oil and gas reserves and production through 2022.
CNOOC holds 100% interest in Jinzhou 25-1 oilfield 6/11.
Husky commissions third deepwater gas field offshore China
Husky Energy commissioned Liuhua 29-1 field, Block 29/26, in the South China Sea. It is China’s first deepwater gas field development with about 1,300 m water depth. First gas is expected in early November.
Tied into existing infrastructure at Liwan, Liuhua 29-1 is the third field in the Liwan gas project, 300 km southeast of the Hong Kong Special Administrative Region, that also includes Liwan 3-1 and Liuhua 34-2 fields (OGJ Online, Mar. 31, 2014; Dec. 15, 2014).
The seven-well project was completed safely, ahead of schedule, and $100 million below budget, the company said.
In total, the Liwan gas project is expected to deliver around $950 million (Husky working interest) from operations in 2021. Liuhua 29-1 alone is expected to generate $1.3 billion in funds from operations for Husky over the next decade.
Year-to-date total production from Liwan 3-1 and Liuhua 34-2 is about 390 MMcfd of natural gas and 16,000 b/d of associated liquids. Total production in 2021 is expected to be 450 MMcfd and 17,500 b/d liquids.
Husky Oil China, a subsidiary of Husky Energy, holds 75% interest in Liuhua 29-1. China National Oil Corp. (CNOOC) owns the remaining 25%. Husky is operator of the deepwater infrastructure of the Liwan gas project while CNOOC operates the shallow water infrastructure.
Norway production decreased in August, NPD says
Norway’s daily liquids production averaged 2.019 million b/d in August, the Norwegian Petroleum Directorate reported. Norway’s daily liquids production averaged 2.062 million b/d in July.
On Apr. 29, the government decided to implement a cut in Norwegian oil production. The production figures for oil in August include this cut of 134,000 b/d in the second half of 2020. Oil production in August is 0.2% lower than the NPD’s forecast, and 0.1% below the forecast so far this year.
The average daily liquids production in August included 1.722 million b/o, 270 000 bbl of NGL, and 26,000 bbl of condensate.
The update takes the authorities’ oil production regulation into account, as well as delayed start-up of fields under development and oil production in the first quarter.
The total petroleum production for the first 8 months of the year is about 153.6 million standard cu m oil equivalents.
Wellesley drills dry hole in North Sea PL 829
Wellesley Petroleum AS drilled a dry hole in North Sea production license 829, about 75 km north of Gjøa field and 60 km northwest of Florø in 211 m of water.
The objective of well 6204/11-3, the first in the license, was to prove petroleum in reservoir rocks in the Lower Cretaceous (Åsgard formation). The well was drilled by the Borgland Dolphin drilling facility to a vertical depth of 1,290 m subsea and was terminated in basement rock.
No reservoir rocks were encountered. About 30 m of aquiferous sandstone was encountered in underlying Jurassic rocks with moderate to very good reservoir quality, but the well is dry. Although the well was not formation-tested, data acquisition was undertaken. The well has been plugged and the Borgland Dolphin is headed to Kvina Shipyard in Fedafjorden.
Wellesley Petroleum is operator (60%) with partners Equinor (20%) and Petoro AS (20%).
PROCESSING Quick Takes
Hengli starts up new PSA units at Dalian complex
Hengli Petrochemical (Dalian) Co. Ltd. (HPDC) has commissioned seven new pressure swing adsorption (PSA) units from Honeywell UOP LLC to supply high-purity hydrogen at its 20-million tonnes/year (tpy) crude-to-paraxylene integrated refining and petrochemical complex in Hengli Petrochemical Industrial Park (HPIP) at Changxing Island Harbor Industrial Zone in Dalian, Liaoning Province, China (OGJ Online, July 11, 2019).
HPDC will use the new Honeywell UOP Polybed PSA units to produce about 1.4 million cu m/hr high-purity hydrogen in its downstream hydrotreating operations to help produce diesel, gasoline, and jet fuel, as well as to create feedstock for petrochemical products, the service provider said on Sept. 21.
Alongside technology licensing, Honeywell UOP also provided services, equipment, catalysts, and adsorbents for the skid-mounted PSA units, which use proprietary UOP adsorbents to remove impurities at high pressure from hydrogen-containing process streams, allowing hydrogen to be recovered and upgraded to more than 99.9% purity to meet refining needs.
Startup of the new PSA units follows HPDC’s commissioning of a new 300,000-tpy STRATCO alkylation unit—based on technology from E.I. DuPont de Nemours & Co. subsidiary DuPont Clean Technologies—at the Dalian complex in July (OGJ Online, July 24, 2020).
HPDC previously engaged Honeywell UOP to provide its proprietary Callidus advanced flares and low-nitrogen oxides (NOx) burner technology to help reduce NOx emissions at the Dalian integrated complex (OGJ Online, July 18, 2018).
Equatorial Guinea advances Punta Europa refinery
Equatorial Guinea is moving forward with its previously announced plan to build a modular crude oil refinery in Punta Europa, Malabo, on Bioko Island.
VFuels LLC, Houston, has completed execution of a feasibility study for construction of the proposed refinery project, which will cost between $55-76 million, Equatorial Guinea’s Ministry of Mines and Hydrocarbons (MMH) said via a Sept. 19 release from the Equatorial Guinea Press and Information Office.
With the feasibility study now completed, MMH said at the time that “within the next few weeks” it will begin talks with interested investors in hopes of signing a heads of agreement for the project in December 2020.
Based on the current timeline and pending selection of investors, the government of Equatorial Guinea—which also will hold interest in the project as well as provide fiscal incentives for interested partners—plans to reach final investment decision on the project during first-quarter 2021, according to MMH.
To be operated by strategic partner Marathon Oil Co., the planned Punta Europa refinery will process 5,000-10,000 b/d of raw condensate from Alba and Alen fields and be implemented in two phases, the first of which will last 20-24 months, followed by a second 33-36-month phase, MMH said.
The refining project comes as part of MMH’s initiative of the Year of Investment 2020, which is seeking investments for a modular refinery and storage tanks in the continental region, as well as promotion of other projects derived from methanol, among others.
Alongside enabling Equatorial Guinea to reduce its dependence on refined product imports, the proposed Punta Europa modular refinery project also will help avoid a reduction in the republic’s exchange reserves as well as provide higher-quality fuels to regional consumers produced from that domestic production, according to MMH.
Citgo, Phillips 66 advance post-Laura repairs
Citgo Petroleum Corp. remains on schedule for an October restart of its 425,000-b/d refining complex in Lake Charles, La., following damages to the refinery resulting from high winds caused by Hurricane Laura’s Aug. 27 landfall along the US Gulf Coast in southwestern Louisiana.
As power gradually is restored to the area, Citgo continues to make critical repairs at the Lake Charles refinery, the operator said on Sept. 23.
Specifically, partial power has been restored to two of the three refinery substations, and with repairs to damaged refinery equipment progressing well, the refinery remains on track for a phased restart of operations with all units returned to service by mid to late-October, Citgo said.
The operator previously said that, while the refinery fared well overall, the complex sustained major damage to most of its cooling towers, minor damage to noncritical tanks, and a large amount of unidentified miscellaneous damage requiring noncritical repairs (OGJ Online, Sept. 11, 2020).
Power supplied via generators at its terminals enabled Citgo’s Lake Charles refinery rack to resume supply of ultra-low sulfur diesel (ULSD) to regional customers on Sept. 8.
As of Sept. 14, fellow regional refiner Phillips 66 said it expected its 249,000-b/d Lake Charles refining complex in Westlake, La., to become operational within 2 weeks pending restoration of reliable electricity.
While unidentified repairs required at the site will take at least 3 months, Phillips 66 confirmed the refinery could remain in operation while work is under way.
Hurricane Laura made landfall near Cameron, La., at 1:00 a.m. CST on Aug. 27 as a Category 4 storm with maximum sustained winds of 150 mph and a minimum central pressure of 938 mb, according to the National Oceanic and Atmospheric Administration’s National Hurricane Center for the Atlantic region.
TRANSPORTATION Quick Takes
Qatar Petroleum orders compression for LNG
Qatar Petroleum has ordered 12 main refrigerant compressors (MRC) from Baker Hughes Co. for use in the LNG production segment of Qatar Petroleum’s North Field East (NFE) project, being executed by Qatargas. The MRC will be used as part of four LNG trains adding 33 million tonnes/year (tpy) of liquefaction capacity, increasing Qatar’s total LNG production capacity to 110 million tpy.
Each MRC train will consist of three Frame 9E DLN Ultra Low NOx gas turbines and six centrifugal compressors for a total scope of supply of 12 gas turbines to drive 24 centrifugal compressors. Packaging, manufacturing, and testing of the gas turbine-compressor trains will take place at Baker Hughes’ plants in Florence and Massa, Italy.
Qatar Petroleum expects to produce first gas from NFE by end 2025. The second phase of the North Field LNG expansion project, North Field South, will further increase Qatar’s LNG production capacity to 126 million tpy.
The company began development drilling for NFE earlier this year, spudding the first of 80 development wells from eight wellhead platforms (OGJ Online, Apr. 15, 2020).
Harvest Ingleside pipeline shipping to Moda center
Harvest Midstream Co. commissioned two connections between Harvest’s Ingleside pipeline and Moda Midstream. The first connection provides shippers access from the Harvest Ingleside pipeline to Moda Midstream LLC’s Ingleside Energy Center in Ingleside, Tex. The second connection is a bi-direction connection between the Harvest Ingleside pipeline and Moda Midstream’s Taft terminal in Taft, Tex. The bi-directional capability allows Moda’s Taft terminal to receive crude volumes from the Ingleside pipeline and also deliver volumes to the Ingleside pipeline.
Harvest noted completion of the 24-mile, 24-in. OD pipeline in June (OGJ Online, June 23, 2020). It will ship as much as 380,000 b/d supplied by existing Harvest Eagle Ford pipeline systems. Full operations of Harvest’s Midway terminal were expected to begin Oct. 1.
Byron Energy completes SM58-59 pipelay
Byron Energy Ltd.’s South Marsh Island Block 58 and 59 oil and natural gas pipeline installation has been completed offshore Louisiana by Chet Morrison Contractors LLC.
Morrison installed 11.5 miles of 3-, 4-, 6- and 8-in. OD pipeline in water depths of 140 ft. Installation included burial, risers, tie-ins, mitigation of crossings, pigging, hydrostatic testing, and commissioning. Morrison’s CM-15 lay barge completed installation.
The company coordinated with export pipeline operators to install hot tap tie-ins to their transmission lines. This was performed using diving support vessel (DSV) Kelly Morrison, while DSV Joanne Morrison provided both saturation and surface diving support for riser clamp, pipeline tie-in, and various dive operations.
Byron Energy earlier this year installed its nine-slot South Marsh Island 58 G (SM58 G) production platform. SM58 G has a designed production capacity of 8,000 b/d of oil and 80 MMcfd of gas (OGJ Online, June 11, 2020).