GENERAL INTEREST Quick Takes
EIA: US gas in storage reaches injection-season high
Thanks to near-record injection activity during the natural gas injection season (Apr. 1–Oct. 31), the amount of gas held in storage this year went from a relatively low value of 1,155 bcf at the beginning of April to 3,724 bcf at the end of October, according to the US Energy Information Administration.
Inventories as of Oct. 31 were 37 bcf higher than the previous 5-year end-of-October average, according to EIA’s Weekly Natural Gas Storage Report.
Working gas stocks ended the previous heating season at 1,155 bcf on Mar. 31—the second-lowest level for that time of year since 2004.
The 2019 injection season included several weeks with relatively high injections: weekly changes exceeded 100 bcf nine times during the year. Certain weeks in April, June, and September were the highest weekly net injections in those months since at least 2010.
From Apr. 1 through Oct. 31, more than 2,569 bcf of gas was placed into storage in the Lower 48 states. This volume was the second-highest net injected volume for the injection season, falling short of the record 2,727 bcf injected during the 2014 season. In 2014, a particularly cold winter left gas inventories in the Lower 48 at 837 bcf—the lowest level for that time of year since 2003.
Total, like Shell, quits AFPM over climate
Total SA has joined Royal Dutch Shell PLC in withdrawing from American Fuel and Petrochemical Manufacturers because of disagreement about polices on climate change.
In a report on integrating climate with strategy, the company said it reviewed 30 industry associations to which it belongs “to verify that their stances on climate issues are aligned with the group’s.”
Among six criteria in its assessment is support for the 2015 Paris Climate Agreement, which the company called “a major advance in the fight against climate change.”
Total Chairman and Chief Executive Officer Patrick Pouyanne also cited the Paris agreement, stating, “Our policy regarding industry associations demonstrates our consistency and credibility. Transparency will strengthen the action of businesses, which are key participants in discussions on how to achieve the objectives of the Paris Agreement.”
Total said it is keeping its membership in the American Chemistry Council, American Petroleum Institute, and Canadian Association of Petroleum Producers, climate positions of which are “partially aligned” with its own, but issued a warning.
“Total would reconsider its memberships in the event of lasting divergences,” it said.
Shell withdrew from AFPM in April after a review of 19 industry associations in Australia, Europe, and North America, also citing its support for the Paris Agreement among criteria.
It said it found alignment with its positions on climate change with nine of the associations, partial misalignment with nine, and “material misalignment” with AFPM.
Bison Oil & Gas, Pivot Energy announce solar project
Bison Energy LLC, a wholly owned subsidiary of Bison Oil & Gas Partners II LLC, and Pivot Energy have entered into an agreement to develop their first solar project in Arapahoe County, Colo.
The 2-Mw solar project, to be built 25 miles east of Denver, will have a total output of 3,800 Mw-hr, which is equal to the annual energy needs of 400 American homes.
The project is expected to break ground in late 2020.
Exploration & Development Quick Takes
C-NLOPB receives three successful bids
The Canada-Newfoundland and Labrador Offshore Petroleum Board received three successful bids for 13 parcels on offer in two areas covered by a bid round that opened in April (OGJ Online, Apr. 4, 2019). In Call for Bids NL19-CFB01 covering the Southeastern Newfoundland Region, ExxonMobil Canada Ltd. made a solo bid of $10,135,948 for 239,921-hectare Parcel 4. NL19-CFB01 offered nine parcels.
Successful bidders in Call for Bids NL19-CFB02, which offered four parcels in the Jeanne d’Arc region, were ExxonMobil Canada which made a solo bid of $10,449,996 for 111,317-hectare Parcel 2 and a combine led by Husky Oil Operations Ltd. which bid $18,022,500 for 76,737-hectare Parcel 3.
Interests in the Parcel 3 combine are Husky, 72.5%, and Suncor Energy Offshore Exploration Partnership, 27.5%.
Aker BP makes small oil discovery south of Gyda field
Aker BP ASA will plug well 2/1-17 S after a minor oil discovery in the southern part of the North Sea was assessed as uncommercial (OGJ Online, Aug. 1, 2019).
The exploration well—the second drilled in PL 019 C—was drilled by the Maersk Interceptor ultraharsh-environment jack up rig 10 km south of Gyda field and 280 km southwest of Stavanger to a vertical depth of 4,322 m and a measured depth of 4,334 m subsea in 66 m of water. The well was terminated in the Tyne Group in the Upper Jurassic.
The primary exploration target for the well was to prove petroleum in Upper Jurassic reservoir rocks (the Ula formation). The secondary exploration target was to prove petroleum in deeper reservoir rocks in the Jurassic and Triassic (the Eldfisk, Bryne, and Skagerrak formations).
The primary exploration target was not present in the well. In the secondary exploration target, the Eldfisk formation was encountered with a layer of 5 m of oil-bearing sandstones with good reservoir quality. The oil-water contact was not encountered. The Bryne and Skagerrak formations were not drilled.
Preliminary estimates place the size of the discovery at 500,000-1.5 million standard cu m of recoverable oil equivalent.
The well was not formation-tested but extensive volumes of data have been collected. The Maersk Interceptor will now drill development wells in PL 001 B in Ivar Aasen field in the North Sea, where Aker BP is operator.
ConocoPhillips ponders delineation near Balder field
ConocoPhillips Scandinavia AS and its partners will contemplate delineation and possible investigation of nearby prospects following a recent oil and gas discovery 15 km northwest of Balder field in the central North Sea. Preliminary estimates place the size of the discovery at 1-10 million standard cu m of recoverable oil equivalent.
Well 25/7-7, the second in PL 782 S, was drilled by the Leiv Eiriksson semisubmersible drilling rig 205 km west of Stavanger to a vertical depth of 4,705 m subsea in 127 m of water (OGJ Online, July 31, 2019). It was terminated in the Heather formation in the Middle Jurassic. The well was not formation-tested, but data has been collected and samples have been taken.
The well will be plugged.
The primary and secondary exploration targets for the well were to prove petroleum in Upper Jurassic reservoir rocks (Intra-Draupne and Heather formation sandstones, respectively).
In the primary exploration target, the well encountered two separate gas-condensate and oil-bearing intervals, with sandy layers in the Draupne formation totaling 25 m with reservoir properties varying from poor to very good. No hydrocarbon-water contact was encountered. Thin water-bearing siltstone layers were encountered in the secondary exploration target in the Heather formation.
The Leiv Eiriksson rig will now drill a wildcat well in PL 917, where ConocoPhillips Skandinavia is operator.
ADNOC, Total seismic pilot to use drones
Abu Dhabi National Oil Co. and Total SA will use drone aircraft and robotic vehicles to place and retrieve sensors in a pilot 3D seismic survey in Abu Dhabi.
The pilot will use Total’s proprietary Multiphysics Exploration Technologies Integrated Systems system, which the French company tested in 2017 in Papua New Guinea.
Khadija Al Daghar, ADNOC vice-president, research and technology development, said the collaboration aims “to be able to jointly develop a safer, faster, more efficient, and cost-effective acquisition system to acquire 3D and 4D high-resolution seismic images of the subsurface, which can be processed in real-time.” The pilot will test the versatility and upscaling ability of the system in 36 sq km of desert. Six aerial drones will drop sensors that will be retrieved by an unmanned ground vehicle.
NIOC reports oil find in southwestern Iran
A discovery called Namavaran made in Khuzestan in southwestern Iran has 53 billion bbl of oil in place, reports National Iranian Oil Co. Petroleum Minister Bijan Zangeneh said recent exploration has raised the estimate by 22 billion bbl from an earlier value established by work begun in 2016.
Drilling & Production Quick Takes
Alberta exempts more oil from output cap
Alberta has further eased its production-curtailment policy by exempting output from new conventional oil wells.
Responding to crude oil prices depressed by transportation bottlenecks, the province has limited output since January, when a 3.56-million-b/d cap represented a cut of 325,000 b/d.
It has slowly raised the cap, apportioned among producers, since then. This month’s limit is 3.8 million b/d.
In September, conventional oil production in Alberta was 480,000 b/d, of which 90,000 b/d was from curtailed operators.
Last month, the government said operators can apply to increase oil production if the additional amount is moved out of the province by new rail capacity (OGJ Online, Oct. 31, 2019).
ExxonMobil unit lets contracts for FPSO off Guyana
An affiliate of ExxonMobil Corp. let a contract for the Payara development offshore Guyana to SBM Offshore, which will construct, install, lease, and operate for up to 2 years the Prosperity floating production, storage, and offloading vessel.
The FPSO design largely replicated the Liza Unity FPSO, which arrived on the Stabroek block earlier this year (OGJ Online, Aug. 29, 2019). The Prosperity will incorporate SBM Offshore’s newbuild, multipurpose hull combined with several standardized topsides modules. The vessel will be designed to produce 220,000 b/d of oil with associated gas-treatment capacity of 400 MMcfd and water injection capacity of 250,000 b/d.
In July 2017, ExxonMobil reported the 500-million boe Payara discovery, which is northwest of the Liza Phase 1 project (OGJ Online, July 25, 2017).
The FPSO will be moored in 1,900 m of water. It will will be able to store 2 million bbl of crude.
ExxonMobil affiliate Esso Exploration & Production Guyana Ltd. is operator and holds 45% interest in the Stabroek block. Hess Guyana Exploration Ltd. holds 30% and CNOOC Petroleum Guyana Ltd. holds 25% interest.
Norske Shell signs frame agreement for Ormen Lange
AS Norske Shell let a frame agreement for an engineering, procurement, construction, and installation contract to OneSubsea, a Schlumberger Ltd. company, for the supply of a subsea multiphase compression system for Ormen Lange natural gas-condensate field in the Norwegian Sea.
Ormen Lange field, discovered in 1997, has been developed with seafloor installations in 800-1,100 m of water in combination with an onshore plant at Nyhamna in Aukra municipality in Norway for processing and exporting gas. The field is produced through four seabed templates. Compression on the field is expected to increase the recovery of gas and condensate.
Through the contract, OneSubsea and Subsea 7 will supply and install a subsea multiphase compression system that uses the industry’s only subsea multiphase compression technology.
In Phase 1, OneSubsea will engineer and design the system. Following a final investment decision by the license group, the complete scope of the contract will be executed.
To be powered and controlled from the Nyhamna plant 120 km from the subsea location, the tieback distance of the compression system will break a world record for transmitting variable speed power from onshore to seafloor equipment.
The system will be installed in 850 m of water and comprises two 16-Mw subsea compression stations tied into existing manifolds and pipelines. This multiphase compression system is surge tolerant, does not require well-stream preprocessing, and is adaptable to varying conditions.
Licensing partners in Ormen Lange are operator Shell, Equinor, Petoro, Ineos, and ExxonMobil Corp.
Nido, Matinloc flows cease off Philippines
Oil production ceased after 40 years earlier this year from Nido and Matinloc fields off Northwest Palawan in the Philippines, the country’s Department of Energy reports.
Discovered in 1977, Nido field started flow in February 1979 and produced 18.9 million bbl of oil over its life.
Matinloc field was discovered in 1979, joined by the Pandan and Libro discoveries in 1980 and the North Matinloc discovery in 1988. The Matinloc complex had lifetime production of 12.5 million bbl of oil.
A consortium of Philodrill Corp., Alcorn Petroleum, Oriental Petroleum, Nido Production, Phinma Energy, and Forum Energy holds the Nido and Matinloc service contracts.
The country’s only other major hydrocarbon production comes from Malampaya gas field in 820 m of water off Palawan Island. Malampaya produced 150.8 bscf of gas last year, the largest annual total since start-up of production in June 2002.
Cesar G. Romero, president and chief executive officer of Shell Philippines Exploration BV, the operator, estimated last December that Malampaya will produce until 2026-29.
PXP applies to develop Malampaya gas hub
PXP Energy Corp., Mandaluyong City, Philippines, wants to develop an integrated natural gas hub centered on deepwater Malampaya gas field off Palawan Island in the West Philippine Sea.
Development would occur after expiration of Malampaya’s Service Contract (SC) 38 in 2024 (OGJ Online, Nov. 12, 2019).
PXP notified the Philippine Stock Exchange it had submitted an unsolicited proposal to the Philippine Department of Energy for the hub project, which would facilitate development of nonproducing Sampaguita gas field and nearby prospects in SC 72. Forum (GSEC 101) Ltd., in which PXP holds a majority interest, operates SC 72.
The contract is subject to force majeure because of a maritime territorial dispute between the Philippines and China. Forum, which acquired the SC 72 from Sterling Energy Ltd. in 2005 and has conducted geophysical work since then, plans to drill two Sampaguita wells when force majeure ends.
Malampaya, gas from which is critical to the generation of electricity in the Philippines, is operated by a subsidiary of Royal Dutch Shell PLC, which holds a 55% interest in SC 38 in partnership with a unit of Chevron Corp., with 45%.
In its filing with the stock exchange, PXP also said it “has expressed an interest” to acquire the Chevron stake.
PROCESSING Quick Takes
Calumet sheds San Antonio refinery
Calumet Specialty Products Partners LP has completed the sale of its 21,000-b/d San Antonio refinery and related assets—including a crude oil terminal and pipeline—to Startlight Relativity Acquisition Co. LLC.
As part of the transaction—finalized on Nov. 11 but with an effective date of Nov. 1—Starlight agreed to pay $63 million in cash for the facility, property, and equipment, plus adjustments for net working capital, inventories, and post-closing amounts.
In a related transaction, Calumet entered into a settlement-and-release agreement with TexStar Midstream Logistics LP settling all outstanding litigation between the two parties, which will result in the release of a $38-million balance sheet liability.
“The divestment of the San Antonio refinery represents another step forward in Calumet’s strategic transformation,” said Tim Go, Calumet’s chief executive officer. “This transaction further delevers Calumet’s balance sheet, reduces earnings volatility by lowering our exposure to fuels refining, and allows the partnership to focus its time and capital more intently on our higher-return core specialty products business.”
The San Antonio refinery, which processes crude oil and condensate primarily from the Eagle Ford basin, currently produces LPG, naphtha, regular and premium gasoline, commercial and military jet fuel, ultralow-sulfur diesel, and atmospheric tower bottoms.
The refinery hosts about 250,000 bbl of storage capacity and includes 200,000 bbl of additional crude oil storage capacity at a crude oil terminal in Elmendorf, Tex.
Under Starlight’s ownership, the refinery has been renamed San Antonio Refinery LLC and will be operated by Lazarus Energy Holdings LLC, which also operates a 15,000-b/d crude distillation facility with about 1.2 million bbl of storage capacity, owned by Blue Dolphin Energy Co., in nearby in Nixon, Tex.
CGPG unit lets contract for petchem complex revamp
Dayuewan (Zhuhai) Petrochemical Co. Ltd., a subsidiary of China Grain Petrochemical Group, has let a contract to Honeywell UOP LLC to provide a range of proprietary technologies to upgrade heavy fuel oil into higher-value petrochemical products at its complex in the Gaolan Port Economic Zone in Guangdong Province, China.
As part of the contract, Honeywell UOP will deliver basic engineering and technology licensing, as well as technical and start-up services for the project, which includes a 1.4 million-tonnes/year Uniflex MC slurry hydrocracking unit to upgrade bottom-of-the-barrel fuel oil into light oil products that will be fed to a Unicracking unit to produce naphtha for a CCR Platforming unit, the service provider said.
The project also includes three Polybed pressure-swing adsorption (PSA) units to supply high-quality hydrogen for the Uniflex process. The PSA units are designed to generate 320,000 cu m/hr of hydrogen.
When the project is completed, Dayuewan will be converting nearly all its vacuum residue to light oil products, representing one of the highest conversion rates in the world. The project also will adopt a range of advanced process technologies to recycle hydrogen and LPG.
Intended to enable Dayuewan to modernize its operations by transformation and upgrading, the combination of technologies will be designed as an integrated operating block to maximize product yields with lower capital and operating expense than standard configurations, said Henry Liu, vice-president and general manager of Honeywell UOP’s business in China.
Honeywell UOP did not disclose a value of the contract nor a timeframe for the project’s completion.
Since its establishment in December 2016, Dayuewan has been committed to the concept of green, energy-saving and high-efficiency technologies, establishing a modern petrochemical complex with advanced technologies, equipment and recyclable resources, and which integrates production, processing, storage, and terminals.
Chinese operator lets contract for petchem unit
Formosa Chemicals Industries (Ningbo) Co. Ltd., a subsidiary of Formosa Chemicals & Fibre Corp., has let a contract to McDermott International Inc. to provide technology licensing and basic engineering services for a grassroots alpha-methylstyrene (AMS) recovery unit at its petrochemical operations in Ningbo, Zhejiang Province, China.
The 10,000-tonne/year unit will be equipped with AMS technology jointly licensed by McDermott’s Lummus Technology and Eni SPA subsidiary Versalis SPA, McDermott said.
The service provider valued the contract award—which represents the first licensing of AMS technology—at $1-50 million, which was reflected in McDermott’s second-quarter 2019 backlog.
TRANSPORTATION Quick Takes
Construction starts on Ingleside pipeline, terminal
Construction on the Ingleside pipeline and the Harvest Midway terminal has begun, reported Hilcorp Energy Co. affiliate Harvest Midstream Co.
The Ingleside line is a 24-mile, 24-in. oil pipeline that will originate from the Harvest Midway terminal and connect to multiple oil export terminals in the Ingleside area, including the Flint Hills Resources Ingleside terminal and the South Texas Gateway terminal being developed by Buckeye Partners. The Ingleside line also will connect to multiple terminals in the Midway and Taft area.
The pipeline will have a final capacity of 600,000 b/d with up to 380,000 b/d supplied by the existing Harvest Eagle Ford pipeline systems. The pipeline will provide Harvest customers direct access to Ingleside terminals, which is the fastest growing export center along the Gulf Coast, the company said.
The Harvest Midway terminal covers 160 acres and has the capacity to store more than 10 million bbl of oil. The initial buildout will include 200,000 bbl of crude oil storage, as well as measurement and pumping infrastructure capable of 25,000 bbl/hr.
The Ingleside pipeline is expected to begin service at the end of the first quarter of 2020 and the Harvest Midway terminal is projected to be in service at the beginning of the fourth quarter of 2020.
FERC okays Jordan Cove LNG biostudy extension
The US Federal Energy Regulatory Commission agreed on Oct. 30 to grant a National Marine Fisheries Service official’s request for more time to prepare its biological opinion of the proposed Jordan Cove LNG export terminal and Pacific Connector natural gas pipeline.
James Martin, branch chief for FERC’s Gas Branch 3, said he was confirming the request Chuck Wheeler of NMFS’s Oregon Coast Branch made because he agreed with the reasons Wheeler outlined in an Oct. 18 letter.
The proposed LNG terminal would be built on the North Spit at the Port of Coos Bay, Ore., on a site zoned for industrial development, 7 nautical miles from the entrance of the federally controlled and maintained navigation channel.
The proposed 229-mile, 36-in. pipeline would transport gas from interconnections with the Ruby Pipeline and the Gas Transmission Northwest pipelines near Malin, Ore.