OGJ Newsletter
GENERAL INTEREST Quick Takes
US LNG cargo cancellations slow for September
Sluggish global demand for liquefied natural gas (LNG) continued to push US LNG buyers to cancel cargo loading for September, according to industry sources for Reuters. However, the pace of cancellation in September seems to have slowed down.
Some sources estimate that 15-26 LNG cargoes may have been cancelled, though the exact number of cancellations is not immediately clear. This compares to 40-45 cancellation for July and August. The number of cancellations for June loading ranged roughly from 20 to 30.
Cargo cancellations for September were mainly due to low prices in Europe, which has its storage capacity full, according to industry sources. One reason for fewer cargo cancellations in September is that traders are betting that prices will rise in November and December, with some tankers already holding their cargoes at sea for sale later, probably in Asia, industry sources with Reuters said.
A source said that most of the cargoes for September loading were cancelled from Cheniere Energy’s plants (i.e. Sabine Pass in Louisiana and Corpus Christi in Texas), similar to the situation in previous months.
US LNG exports this year are estimated to plummet by more than 70%, from 8.07 bcfd in January to expected 2.2 bcfd in July and August, according to the US Energy Information Administration (EIA)’s latest Short-Term Energy Outlook. However, EIA expects that US LNG exports will increase in each of the remaining months of the year and will recover to 6.5 bcfd in December.
Based on the number of canceled cargoes for the coming months, EIA expects US LNG export capacity will be utilized at less than 50% in June, July, and August 2020.
Castleton Resources inks $245-million deal with Range Resources
Castleton Resources LLC has agreed to acquire the Terryville upstream assets in Northern Louisiana from Range Resources Corp. subsidiaries for $245 million plus the potential for $90 million in additional proceeds contingent on future commodity prices. At the time of the agreement, the assets were producing 160 MMcfed, Range said as part of its second quarter report released Aug. 3.
Under the terms of the agreement, Range will retain certain midstream commitments through their remaining term. Range said it intends to use $28.5 million of the sale proceeds to reduce a portion of the retained commitments.
Pro forma for the Terryville acquisition, Castleton Resources will own over 315,000 net acres of leasehold in East Texas and Northern Louisiana with total daily net production of about 500 MMcfed. In December 2019, the company closed a deal to acquire the East Texas and North Louisiana Haynesville shale assets of BG US Production Co. LLC, a Royal Dutch Shell PLC subsidiary. (OGJ Online, Dec. 30, 2019).
Castleton Resources is owned by Castleton Commodities International LLC (CCI) and Tokyo Gas America Ltd., a wholly owned subsidiary of Tokyo Gas Co. Ltd. Tokyo Gas America will increase its ownership in Castleton Resources to 70% from 46% when the acquisition closes—expected on Aug. 14 with an effective date of Feb. 1—with the balance to be held by CCI.
Castleton Resources will change its name to TG Natural Resources LLC by late March 2021.
Denbury files Chapter 11 to facilitate reorganization
Denbury Resources Inc. and its subsidiaries have filed petitions for reorganization under Chapter 11 of the Bankruptcy Code in the US Bankruptcy Court for the Southern District of Texas to implement its prepackaged plan to eliminate $2.1 billion of bond debt, consistent with terms of its restructuring support agreement (RSA).
The RSA was entered into with funded debtholders holding 100% of the company’s revolving credit facility loans, some 67.2% of its second lien notes, and about 70.8% of its convertible notes.
The company’s existing lenders are providing a debtor-in-possession revolving loan that will “roll” into an exit facility with up to $615 million in availability. Upon court approval, this new financing and the cash generated from Denbury’s ongoing operations are expected to be sufficient to support the business during the court-supervised process.
Exploration & Development Quick Takes
Apache, Total make third consecutive Block 58 discovery
Apache Corp. and partner Total encountered at least 278 m of net oil and volatile oil-gas condensate pay in two intervals in Block 58 offshore Suriname and are preparing a fourth prospect on the block.
Kwaskwasi-1, operated by Apache as part of a 50-50 joint venture with Total and drilled by the Noble Sam Croft to a depth of 6,645 m, successfully tested for the presence of hydrocarbons in multiple stacked targets in the upper Cretaceous-aged Campanian and Santonian intervals (OGJ Online, Dec. 23, 2019).
The discovery is the third consecutive discovery on the block following the Sapakara West in April, and the Maka Central in January (OGJ Online, Apr. 2, 2020; Jan. 7, 2020).
The shallower Campanian interval contains 63 m of net oil pay and 86 m of net volatile oil-gas condensate pay. Based on samples taken, the API oil gravities are 34-43 degrees. The deeper Santonian interval contains 129 m of net hydrocarbon reservoir. Data collecting on API oil gravities in the Santonian are ongoing.
The 1.4-million acre block offers potential beyond recent discoveries, Apache said, noting at least seven distinct play types and more than 50 prospects within the thermally mature play fairway have been identified.
Upon completion of operations at Kwaskwasi-1, the Sam Croft will move to the fourth prospect—Keskesi—which lies 14 km southeast of Sapakara West-1. It will test oil-prone upper Cretaceous targets in the Campanian and Santonian. After drilling of the fourth well, Total will take over as block operator, it said July 30.
In early 2021, an appraisal campaign will be carried out to better characterize the 2020 discoveries, along with an additional exploration campaign.
Eni says Ken Bau-2X confirms, expands 2019 discovery
Eni Vietnam and Essar E&P plan additional drilling and testing of the 2019 Ken Bau discovery after exploration well Ken Bau-2X in the Song Hong basin offshore Vietnam confirmed a significant hydrocarbon accumulation, further expanding the discovery’s potential (OGJ Online, July 24, 2019).
Ken Bau 2X was drilled in Block 114, 2 km from the discovery well in 95 m of water to a total depth of 3,658 m subsea. It encountered pay in excess of 110 m in several intervals of Miocene sandstones interbedded with shale.
Two mini drill stem tests (DST) were conducted, coupled with an extensive data acquisition campaign comprising fluid sampling, Eni said. Preliminary estimates of Ken Bau accumulation are 7-9 tcf of raw gas in place with 400–500 million bbl of associated condensates. The well will be plugged.
Eni Vietnam operates the 5,900-sq-km Block 114 with a 50% interest, which it acquired from Essar E&P in 2012. Essar retains 50%.
Also in the Song Hong basin, in neighboring Block 116, Eni Vietnam plans new drilling and seismic activity as operator with 100% interest.
Ken Bau discovery could potentially provide a fast-track solution to meet the increasing energy demand in Vietnam, Eni said.
OMV drills appraisal in Hades discovery
OMV Norway AS is concluding drilling of appraisal well 6506/11-12 S in the Hades gas-condensate discovery about 5 km west of Morvin field in the Norwegian Sea and 240 km northwest of Kristiansund, according to the Norwegian Petroleum Directorate (OGJ Online, Apr. 6, 2018).
The well, the second in production license 644 after 6506/11-10, was drilled by the Island Innovator semisubmersible driling rig to 4,150 m measured depth and 4,062 m vertical depth subsea in 433 m of water. It terminated in the Lange formation in the Lower Cretaceous (OGJ Online, May 13, 2020). The objective was to delimit the gas-condensate discovery in the formation toward the southwest, reduce uncertainty associated with the resource estimate, and conduct a formation test.
The well encountered an interpreted gas column of about 8 m, with sandstone layers totaling about 83 m with poor-to-moderate reservoir properties. Gas-water contact was not directly encountered. The formation as not tested, but extensive data acquisition was carried out. The well will now be permanently plugged.
Preliminary resource estimate for Hades before 6506/11-12 S was drilled was 3-23 million standard cu m recoverable oil equivalent. After well appraisal, the estimate has been revised down to 2-7 million standard cu m recoverable oil equivalent.
Partners in PL 644/644 B will assess updated resources in Hades along with resources in Iris, the Middle Jurassic Garn formation in the same discovery, for further follow-up.
OMV is operator of PL 644/644B (30%) with partners DNO Norge AS (20%), Equinor Energy AS (40%), and Spirit Energy Norway AS (10%).
Drilling & Production Quick Takes
Okea restarts Draugen production
Okea ASA restarted production from Draugen field in the Norwegian Sea following turnaround activities. Work started June 23 and ended July 20, 2 days ahead of schedule. Startup tracked to plan, and production began July 21 in time to meet the agreed tanker loading.
The work included replacement of corroded piping and valves in hydrocarbon services; preparations for the Draugen gas import and long-term power project; change out of the subsea control system; inspection of corroded x-mas trees; installation of x-line for G-cyclones, reducing deferment when cleaning other hydro cyclones; inspection of heat exchangers, vessels, and the flare system; re-certification of 167 relief valves; and testing of emergency shutdown and other safety functions.
During the campaign, up to 169 people were onboard the Draugen platform, with 89 on dayshift and 80 on nightshift. COVID-19-related measures were followed.
PGNiG expects production boost from Mielec–Bojanow fields
Polish Oil and Gas Co. (PGNiG) expects to ultimately add about 24 million cu m/year to its natural gas output with production from Mielec–Bojanow fields.
The Korzeniówek 2-K appraisal well was drilled in the village of Pustków, in the Debica district in Podkarpackie, Poland.
Exploration work began in the area in late 2017 with the spudding of Korzeniówek-1K. The recorded flow of high-methane natural gas is typical of the Carpathian Foredeep basin Miocene formation, the region’s prevalent geological structure, the company said. Annual gas production from Korzeniówek-2-K is estimated at 17.4 million cu m, plus some 6.6 million cu m from Korzeniówek-1K.
Both wells will be brought on stream via the existing infrastructure of the Pilzno gas production facility. PGNiG is analyzing the geological and formation data which will influence its decision to continue exploration work in the area.
Novatek begins gas condensate production at North-Russkiy cluster
PAO Novatek subsidiary Novatek-Tarkosaleneftegas commenced pilot production from gas condensate bearing layers of North-Russkoye and East-Tazovskoye fields with cumulative total annual production capacity of 7.7 billion cu m of natural gas and 1 million tons of gas condensate.
Natural gas produced in the North-Russkiy cluster is intended for the Russian domestic market, and additional volumes of gas condensate “will ensure full utilization of our processing facilities,” said Leonid Mikhelson, management board chairman.
The North-Russkiy block includes North-Russkoye, Dorogovskoye, East-Tazovskoye, and Kharbeyskoye fields scheduled for commercial launch in 2020-2021.
PROCESSING Quick Takes
Petronas lets contract for Kasawari offshore gas plant
State-run Petroleum Nasional Bhd. (Petronas) subsidiary Petronas Carigali Sdn. Bhd. has let a contract to Honeywell UOP LLC to provide modular natural gas processing technology for development of a 900-MMcfd offshore gas purification plant in Kasawari gas field in the South China Sea, off Sarawak, Malaysia.
As part of the contract, UOP will deliver a suite of its proprietary acid gas removal technology, including MemGuard and Separex technologies and adsorbents, to remove contaminants such as carbon dioxide, hydrogen sulfide, and mercury from natural gas, UOP said.
Especially suited to process natural gas for production and power generation in remote locations such as Kasawari offshore field, the modular Separex technology—the membrane systems of which contain spiral-wound membrane elements to remove acid gas and vapor-phase water from natural gas streams—will free up valuable space within the subsea pipelines that bring gas from offshore to onshore and reduce moving parts which require minimum operator intervention, according to Michael Cleveland, vice-president and general manager of UOP’s gas processing business.
Gas processed at Kasawari will be further processed and liquefied at Petronas’s majority held Malaysia LNG Sdn. Bhd.’s (MLNG) existing nine-train LNG complex in Bintulu, Sarawak, to be exported globally for power generation, UOP said.
In June, Petronas said it expects the Kasawari offshore central processing platform—which will produce from five subsea wells—to reach startup in first-quarter 2023.
Thai Oil lets contract for Sriracha clean fuels project
Thai Oil PLC has let a contract to McConnell Dowell Corp. Ltd. to provide civil works for the previously announced Clean Fuel Project (CFP) at its 276,000-b/d refinery at Sriracha, in eastern Thailand’s Chonburi province.
McConnell Dowell’s scope of work under the contract—which was awarded by the consortium of Saipem, Petrofac, and Samsung Engineering delivering engineering, procurement, construction, and commissioning services on CFP—includes both earthworks and civil works in both greenfield and brownfield areas to support the overall project of improvement and expansion to the existing refinery, including the addition of new complex processing units, all required utilities, and supporting installations, the service provider said.
With construction works already under way at the site and scheduled to be completed in 2021, the overall project is scheduled for startup in 2023, McConnel Dowell said.
A value of the civil works contract was not disclosed.
This latest contract follows Thai Oil’s previous award to Haldor Topsoe for licensing of its SNOX air quality-control technology to help secure compliance with air-emission regulations for a new energy recovery unit to be built as part of the CFP.
The $4.825-million CFP involves 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 (OGJ Online, Mar. 18, 2020).
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, Thai Oil said 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.
Hengli Petrochemical starts up new alkylation unit
Hengli Petrochemical (Dalian) Co. Ltd. (HPDC) has commissioned a new alkylation unit at its new 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).
Equipped with proprietary technologies from E.I. DuPont de Nemours & Co. subsidiary DuPont Clean Technologies, the new 300,000-tonnes/year STRATCO alkylation unit enables Hengli to produce high-quality alkylate, a key component for cleaner, high octane gasoline, from a 100% isobutylene feed stream, DuPont said on July 24.
Developed through DuPont research into the best ways to maximize product octane and minimize end point with isobutylene feedstock, the first-of-its-kind unit uses DuPont’s proprietary XP2 technology in the STRATCO Contactor reactor, which is designed to improve the acid-hydrocarbon emulsion flow path near the tube bundle-heat transfer area of the reactor to enhance processing capabilities and achieve optimal alkylate-product quality, according to the service provider.
Already performing to design specifications, the new alkylation unit is allowing production of high-quality, high-octane alkylate to benefit the refinery’s overall gasoline pool, HPDC said.
TRANSPORTATION Quick Takes
Northern Natural seeks permission for Northern Lights 2021 expansion
Berkshire Hathaway Energy’s Northern Natural Gas requested US Federal Energy Regulatory Commission permission to build its Northern Lights 2021 natural gas pipeline expansion. The expansion will provide 45.7 MMcfd of incremental winter peak-day service and prevent existing customers from bypassing Northern’s system.
Included in the project are: a new 11,153-hp compressor station in Pine County, Minn.; additional compression at the Pierz station in Morrison County, Minn.; pipeline loop and extension totaling 1.43 miles; replacement of 0.08 miles of 8-in. OD pipe with 12-in. OD pipe (Viking interconnect branch line); and modifications to the Pierz interconnect.
The Pine County compressor station will tie-in to Northern’s existing 20-in. OD B-line and use a Solar Taurus 70 turbine. Additional compression at Pierz will be accomplished via an 1,100-hp reciprocating unit tied in to Northern’s proposed 12-in. OD Viking interconnect.
The three shippers requiring incremental volume increases by Nov. 1, 2021, are CenterPoint Energy Resources Corp. (34.9 MMcfd), Northern States Power Co. (9.5 MMcfd), and Midwest Natural Gas (1.4 MMcfd). Northern requested FERC approval no later than Mar. 16, 2021, to meet this date.
Northern Lights is a project designed to meet customers’ supply-growth requirements through 2026. Northern Lights 2021 will cost an estimated $57.4 million.
Petronas completes Tembikai gas pipelay
Petronas Carigali Sdn Bhd. subsidiary Vestigo Petroleum Sdn Bhd has completed the 68-km, 12-in. OD subsea pipelay for the Tembikai natural gas development in 70 m (230 ft) of water offshore Malaysia. The pipeline connects the non-associated gas development’s unmanned platform to the Berantai floating production, storage, and offloading vessel.
Cortez Subsea Ltd. partnered with Alam Maritim (M) Sdn Bhd. in using NOV-Tuboscope’s Zap-Lok mechanical connector technology for the project. The rigid pipe was connected to flexible risers by using a stinger-deployed diverless connector, remotely operated vehicle, and a deployment frame.
Cortez’s work included engineering, procurement, construction, installation, and precommissioning of the pipeline system.
Vestigo launched the gas development project in 2018. Tembikai produced first oil in 2015 from a separate development.
PTTGCA signs Energy Storage Ventures for NGL storage
PTTGC America (PTTGCA) has executed a precedent agreement with Energy Storage Ventures LLC through its wholly owned subsidiary Mountaineer NGL Storage to provide NGL storage for PTTGCA’s proposed 1.5-million tonne/year ethane cracker and petrochemical complex in Mead Township, Belmont County, Ohio. The agreement will establish the first underground NGL storage site in the Marcellus and Utica shale formation, according to PTTGCA.
The underground salt caverns for NGL storage are part of a 200-acre site in Ohio’s Monroe County. The site, owned and operated by Mountaineer, is about 8 miles south of the PTTGCA project site. PTTGCA is working with Mountaineer on 1 million bbl of ethane storage and a pipeline that will link the storage to the PTTGCA complex.
Mountaineer will develop the $250-million storage site in two phases by creating multiple caverns in the existing underground salt formation. Each cavern will be capable of storing about 500,000 bbl of NGL, including propane, butane, ethane, and ethylene. Mountaineer has obtained all required permits to begin construction of Phase 1 of the project—about 1.5 million bbl—which will take 2-3 years to complete. An additional 1.5 million bbl is planned for Phase 2. Additional expansion is possible, subject to market demand.
PTTGCA, the US subsidiary of Thailand’s PTT Global Chemical, and then-partner Daelim Chemical USA LLC, a subsidiary of South Korea’s Daelim Industrial Co. Ltd., earlier this year revised the timeline for reaching final investment decision on the cracker project to first-quarter 2021. Daelim has since withdrawn from the project.