GENERAL INTEREST Quick Takes
Steelworkers union calls for RFS reforms
A United Steelworkers official called for reforms in the federal Renewable Fuel Standard after Philadelphia Energy Solutions LLC announced that it was seeking federal bankruptcy protection because of high costs incurred in meeting the regulation’s renewable fuel quotas (OGJ Online, Jan. 23, 2018).
Kim Nibarger, the union’s national oil bargaining chairman, said in Pittsburgh that the USW joined independent refiners and leading figures from both major US political parties more than a year ago to address imbalances created by the US Environmental Protection Agency’s use of renewable identification numbers (RIN) to track RFS compliance.
“Now, as a result of inaction, union members working at PES face an uncertain future,” he said following the refiner’s announcement, which cited the cost of complying with the requirement as the main contributor to more than $1 billion of debt that the company has incurred.
“Independent refiners generally lack the capacity and infrastructure to blend ethanol into their gasoline and must purchase RINs at prices artificially inflated due to hoarding by the largest oil companies and manipulation by the ethanol industry,” Nibarger maintained.
“Continued indifference by the administration and EPA will only drive more East Coast refineries into bankruptcy while thousands of good jobs...are at stake,” he warned.
EXCO Resources files petitions under Chapter 11
EXCO Resources Inc., Dallas, has filed petitions for a court-supervised reorganization under Chapter 11 of the US Bankruptcy Code in the Southern District of Texas and is in discussions with its creditors regarding the terms of a financial restructuring plan. The company will explore alternatives, including a sale of assets under Section 363 of the bankruptcy code.
In its quarterly report dated Nov. 7, 2017, EXCO said its liquidity was “significantly constrained.” As of Sept. 30, 2017, the company’s liquidity was $105.8 million and the principal amount of its outstanding debt was $1.4 billion.
Despite having taken actions to mitigate the impact of a sustained downturn in commodity prices and uncertainty in the energy market, said EXCO chief executive officer Harold L. Hickey, “we continue to face increasing liquidity pressures as we navigate the competitive environment.”
One such action was the April 2017 agreement to sell Eagle Ford assets to privately held Venado Oil & Gas LLC, Austin, for $300 million (OGJ Online, Apr. 11, 2017).
With court approval, EXCO intends to use $250 million in debtor-in-possession financing from existing lenders including Fairfax Financial Holdings Ltd. and its affiliates; Bluescape Resources Co. LLC and its affiliates, including Cove Key Management; and JPMorgan Chase Bank NA, and certain of its affiliates, to refinance its existing Reserve-Based Credit Agreement and support day-to-day operations.
EXCO Resources has principal operations in Texas, North Louisiana, and the Appalachia region.
Exploration & DevelopmentQuick Takes
Shell makes deepwater gulf oil find with Whale well
Shell Offshore Inc. has added to its Paleogene exploration success in the Perdido area in the deepwater US Gulf of Mexico with a discovery in its Whale well. The well encountered 1,400 net ft of oil-bearing pay, Shell said.
Whale is operated by Shell 60% and co-owned by Chevron USA Inc. 40%. It was discovered on the Alaminos Canyon Block 772, adjacent to the Shell-operated Silvertip field 10 miles from the Shell-operated Perdido platform.
The discovery “offers a combination of materiality, scope, and proximity to existing infrastructure,” said Marc Gerrits, Royal Dutch Shell PLC executive vice-president.
Through exploration, Shell has added more than 1 billion boe resources in the last decade in the gulf.
Shell currently has three deepwater projects in the gulf under construction: Appomattox, Kaikias, and Coulomb Phase 2. It also has investment options for additional subsea tiebacks and in Vito, a potential new hub in the region. Shell expects its global deepwater production to exceed 900,000 boe/d by 2020 from already discovered, established areas.
Total makes largest company discovery in gulf to date
Total SA is confirming upside potential with a sidetrack to its Ballymore discovery. Drilled to a final depth of 8,898 m, the Ballymore well encountered 205 m of net oil pay in a high-quality Jurassic Norphlet reservoir. The well is in 2,000 m of water about 120 km offshore Louisiana in the Gulf of Mexico.
Total reported the Ballymore prospect covers four blocks in the Norphlet play, including Mississippi Canyon Block 607 where the discovery was made. Total acquired a 40% interest in Ballymore as part of its September 2017 exploration agreement with Chevron Corp. (60% as operator) (OGJ Online, Jan. 24, 2018). The deal included seven prospects covering 16 blocks in the Norphlet (eastern gulf) and the Lower Tertiary Wilcox plays (central gulf).
Ballymore is the company’s largest discovery in gulf to date, the company said.
Jericho Oil enters farm-in, increases STACK acreage
Jericho Oil Corp., Vancouver, BC, has entered into a farm-in agreement through its Oklahoma STACK joint venture with a private operator to drill 2-5 horizontal wells in Major County near the company’s core STACK operating area.
After drilling and completing two standard-lateral, 4,500-ft horizontal wells targeting the Osage formation, the STACK JV will earn a 50% interest in 6,000 net leasehold acres. Additional well commitments by the STACK JV will increase the combine’s drilling terms on the leasehold acreage. Combined with the STACK JV’s existing acreage, its consolidated core position will total 11,600 net acres.
The STACK JV will participate in the drilling of the first scheduled Osage well and pay its working interest share of costs. The second Osage well is expected to be drilled in this year’s first half.
As part of the deal the STACK JV partner increased its capital commitment to finance a portion of the farm-in agreement. Pro-forma for the commitment Jericho will hold 26.5% interest in the STACK JV.
Chinese firms win three Tarim basin blocks
Chinese companies have paid a total of more than $421 million for three of five oil and gas exploration blocks on offer in the Xinjiang Uygur Autonomous Region of northwestern China, reports Xinhua (OGJ Online, Dec. 15, 2017).
The official press agency said seven companies submitted bids for the Tarim basin exploration rights.
It identified winning bidders as Shenergy Co. Ltd., Xinjiang Energy (Group) Co. Ltd., and Zhongman Petroleum & Natural Gas Group Corp. Ltd.
Beach makes gas find in S. Australia’s Otway basin
Beach Energy Ltd., Adelaide, has made a gas field discovery in the onshore Otway basin of South Australia with the deviated Haselgrove-3 ST1 well in production licence PPL62 about 8 km south of Penola.
The wholly owned Beach permit is on state forestry land and the deliberately deviated well aimed at the primary Sawpit sandstone reservoir and the shallower Pretty Hill sandstone.
Beach said the well intersected an estimated gross gas column of 104 m (total vertical thickness) in the Sawpit with an estimated net pay of 25.6 m. The Pretty Hill intersection had an estimated net pay of 8.5 m.
Encouraged by this result, a cased hole test was run over the interval 4,203-4,185 m in the Sawpit sands which flowed gas at 25 MMcfd during a 100-min period through a 36/64-in. choke. The wellhead pressure was recorded at 2,700 psi.
Beach said the flow rate was constrained to 25 MMcfd because of the small completion tubing size and early indications suggest the Sawpit reservoir could flow at much greater rates.
The well is now shut in while preparations are made for a production test later this month with a view to proving up a commercial development.
Results of that test are expected to confirm the well deliverability and gas composition which initial results suggest contains a low inert component that will minimize gas processing requirements. Existing nearby pipeline infrastructure will enable a swift development if the production test mirrors the initial assessment.
Drilling & ProductionQuick Takes
Suncor Energy ramps up Fort Hills oil sands output
Suncor Energy, Calgary, reported that the Fort Hills oil sands project in northern Alberta is continuing its steady production ramp-up after the startup of secondary extraction on Jan. 27.
Fort Hills, which is 90 km north of Fort McMurray, Alta., has a capacity of 194,000 b/d of oil, 103,000 b/d net to Suncor.
The first of three trains from secondary extraction is now online and production on this train will continue to ramp up through this year’s first quarter.
“With operations at Fort Hills now in continuous production, we’ve brought one of the best long-term growth projects in our industry into service and we’re now focused on the safe and steady ramp up through 2018,” said Steve Williams, Suncor president and chief executive officer.
At peak construction Fort Hills employed an average of 7,900 people. Now in operation, Fort Hills employs 1,400 direct employees and the majority have been hired from Alberta.
The Fort Hills project was sanctioned by the Fort Hills partners in 2013. The project has already completed five test runs of the plant, producing 1.4 million bbl of froth.
The second and third trains of secondary extraction are being insulated and expected to start up in this year’s first half. Fort Hills remains on track to reach 90% capacity by yearend.
Fort Hills is operated by Suncor, which holds 53.06% interest in the project. The Fort Hills joint venture partners are Total E&P Canada Ltd. 26.05% and Teck Resources Ltd. 20.89%.
Aramco lets contract for jackets off Saudi Arabia
Saudi Aramco let a contract to McDermott International Inc. for the engineering, procurement, construction, and installation of 13 jackets for use in Zuluf, Marjan, Berri, and Abu Safah fields off Saudi Arabia with a combined weight of 24,000 tonnes.
McDermott plans to use its engineering teams in Dubai and Chennai with construction taking place at McDermott’s facilities in Jebel Ali, Dubai, and Dammam. Vessels from McDermott’s fleet are scheduled to undertake the installation and completion work. Work is expected to be carried out through this year’s second half.
Since 2001, McDermott has built and installed more than 121 jackets for Aramco with a total weight of 200,000 tonnes.
Aker BP gets consent to use jack up off Norway
Norway’s Petroleum Safety Authority (PSA) has authorized Aker BP to use the Maersk Interceptor jack up drilling rig in the North Sea. The consent covers use of the Maersk Interceptor facility for drilling and completion of two water injection wells, 16/1-D-6 and 16/1-D-7, in Ivar Aasen field. Drilling is scheduled to start in February.
Maersk Interceptor was delivered by the Keppel Shipyard of Singapore in 2014. The facility is owned by Maersk AS and operated by Maersk Drilling Norge AS.
Ivar Aasen field is in the northern part of the North Sea 175 km west of Karmøy in 110 m of water.
The field is being developed as a stand-alone platform for partial processing and water conditioning and injection, with transfer of the multiphase hydrocarbon mixture through two pipelines to neighboring Edvard Grieg field for final processing and export. Ivar Aasen field started oil production on Dec. 24, 2016 (OGJ Online, Dec. 30, 2016).
ExxonMobil collaborates on well-integrity technology
ExxonMobil Upstream Research Co. signed a 3-year joint development agreement with MagnaBond LLC to develop technologies to better evaluate well cementing, casing, and tubing during decommissioning activities.
Existing evaluation technology cannot adequately characterize cement quality through multiple casing strings, an ExxonMobil news release said. A well’s production tubing must be pulled to inspect the cement, adding to the time and expense required for decommissioning.
ExxonMobil will work with MagnaBond to develop technology allowing for through-tubing cement evaluation before arrival of a rig or a workover unit.
Jayme Meier, ExxonMobil Upstream Research vice-president of engineering, said, “Developing a technology that enables us to see the quality of well casing and cement with a single tool is a major step in determining overall well integrity.”
MagnaBond has expertise in technology transfer and supply chain design from other industries, including semiconductor, aerospace, and automotive technologies.
In 2017, ExxonMobil collaborated with other oil and gas companies to form the Plugging and Abandonment Collaborative Environment, an industry network promoting early adoption of emerging technology for well plugging and abandonment practices.
PROCESSINGQuick Takes
Brazos Midstream lets contract for cryogenic gas plant
Brazos Midstream Holdings LLC, Fort Worth, has let a contract to a division of Honeywell UOP LLC to deliver a third cryogenic natural gas processing plant to extract NGLs from gas produced in the southern Delaware basin.
As part of the contract, UOP will provide engineering, fabrication, and supply of a proprietary 200-MMcfd UOP Russell modular cryogenic NGL-recovery unit, the company said.
To be called Comanche III, the new unit follows UOP’s supply of two earlier plants equipped with UOP Russell technology that also were customized to handle the unique composition of NGL-rich gas in the Delaware portion of the Permian basin, including the 60-MMcfd Comanche I plant commissioned in 2017 and the recently completed 200-MMcfd Comanche II plant (OGJ Online, Oct. 10, 2017).
While it disclosed neither a value nor timeframe for its work under the current contract, Honeywell UOP Russell said this latest project follows the service provider’s on-time completion earlier this year of Brazos’ Comanche II plant, which will reduce the installation schedule for Comanche III.
With an unidentified site already secured for Comanche III, Brazos previously said it would begin construction on the new plant in early 2018.
Alongside its existing 260 MMcfd of existing operated processing capacity, Brazos also currently owns and operates about 350 miles of natural gas and crude oil pipeline as well as 50,000 bbl of crude oil storage in the Delaware basin.
As part Brazos’ late-2017 acquisition of a natural gas gathering system in the southern Delaware basin from Callon Petroleum Co., the operator signed a long-term, fee-based agreement with Callon for gas gathering and processing services for acreage under development in the southern Delaware’s Ward and Pecos counties in Texas.
Including the Callon dedication, Brazos’ midstream infrastructure is anchored by long-term acreage dedications with Permian operators covering 240,000 acres.
Saras lets contract for Sardinian refinery
Italy’s Saras SPA has let a contract to Aspen Technology Inc., Bedford, Mass., to provide software aimed at improving business performance and drive operational excellence at its 300,000-b/d, high-conversion refinery in Sarroch, on the southwestern coast of Sardinia.
Aspen Technology will deliver its proprietary Aspen Mtell prescriptive maintenance software to drive reliability for the refinery’s capital and asset-intensive operations, the service provider said.
Part of the aspenONE Asset Performance Management (APM) software suite combining big data, machine learning, and process knowledge expertise to maximize performance across the design, operations, and maintenance asset lifecycle, Aspen Mtell mines historical and real-time operational and maintenance data to discover the precise failure signatures that precede asset degradation and breakdowns, predict future failures, and prescribe actions to mitigate or solve problems.
Saras selected Aspen Mtell based on its speed of deployment, accurate early detection of asset failures, avoidance of false alarms, and ability to scale the solution system-wide during a competitive proof-of-concept vendor selection process focused on critical refinery equipment.
The operator expects to achieve savings following implementation of the software, which is part of an important digitalization project at the refinery, according to Zucca.
Saras plans to use sister engineering firm and industrial automation specialist Sartec SRL to implement Aspen Mtell throughout the Sarroch refinery, Aspen said.
The service provider disclosed neither a value of the contract nor a timeline for when the project will be completed.
Tatneft commissions units at Tatarstan refinery
PJSC Tatneft, Almetyevsk, Russia, has commissioned a naphtha hydrotreater and isomerization unit at its unit at the 9 million-tpy refinery of subsidiary JSC Taneco’s multiphase integrated refining and petrochemical complex in Nizhnekamsk, 250 km from Tatarstan’s capital city of Kazan.
The 1.1 million-tpy naphtha hydrotreater and 420,000-tpy isomerization unit entered service on Jan. 25, Tatneft said.
Startup of the two secondary processing units form the first stage in implementation of a full-scale design for the complex’s production of 100% Euro 5-quality gasoline, with the units respectively enabling output of high-octane gasoline blending components as well as feedstock for a catalytic reforming unit scheduled for commissioning at the site later this year.
The recently commissioned units come as part of an ongoing program Tatarstan launched in 2005 to strengthen the republic’s refining industry, as well as in accordance with basic provisions of a quadripartite agreement on modernization of Russia’s processing industry between oil companies; the Federal Antimonopoly Service of the Russian Federation; the Federal Service for Environmental, Technological, and Nuclear Supervision (Rostechnadzor); and the Federal Agency for Technical Regulating and Metrology (Rosstandart) to reequip and upgrade processing capacities at Russian Federation refineries.
Requiring a total investment to date of 307 billion rubles from Tatneft and 24.7 billion rubles from Taneco as of yearend 2017, the modernization program, which is scheduled to be fully completed in 2023, also will include commissioning of kerosine and diesel hydrotreating units in 2018, as well as startup of a new crude unit, GDU-VDU-6 (also known as ELOU-AVT 6).
Designed to boost nameplate crude oil processing capacity at Nizhnekamsk to 14 million tpy by 2020, GDU-VDU-6 also will enable the refinery to process half of all regional oil production into finished products for the Russian market.
Tatneft previously commissioned a 2 million-tpy delayed coking unit at the refinery, which allowed the manufacturing site to completely eliminate its yield of dark oil products, increase overall refining depth to 99.2%, and raise its yield of light oil products to 87% (OGJ Online, July 6, 2016).
TRANSPORTATIONQuick Takes
States issue water permits for Atlantic Coast line
Agencies in North Carolina and West Virginia separately issued water permits on Jan. 26 and 25, respectively, for the proposed Atlantic Coast natural gas pipeline. Their actions came more than a month after Virginia’s water quality board certified its approval for the project, but with a delay.
The proposed 600-mile system would originate in West Virginia, extend across Virginia with a lateral east to Chesapeake, and continue south into eastern North Carolina where it would terminate in Robeson County. The line’s sponsors are Dominion Energy Inc., Duke Energy Corp., Piedmont Natural Gas Co., and Southern Co. Gas.
The North Carolina Department of Environmental Quality water quality certification approval and its conditions are final and binding unless they are contested within 60 calendar days, the agency’s water resources division said in a Jan. 26 letter to Leslie Hartz, a vice-president at Dominion Energy Transmission Inc. in Richmond.
North Carolina’s Sierra Club chapter and other opponents intend to protest the permit’s approval before the state’s Office of Administrative Hearings, OGJ has learned.
West Virginia’s Department of Environmental Protection said its latest permit approval will require ACP’s developer to comply with a storm-water pollution prevention plan it had to develop in addition to the general permit has received, which will expire on May 18.
“Your annual permit fee has been assessed as $1,500. You will be invoiced by this agency 1 month prior to the anniversary date of your original approval date,” Scott G. Mandirola, who directs WVDEP’s water and waste management division, said in his Jan. 25 letter to Hartz.
PAA to build Cactus II Permian basin crude line
A Plains All American Pipeline LP (PAA) subsidiary received sufficient binding commitments from shippers to begin building its 515-mile Cactus II crude pipeline system from the Permian basin to the Corpus Christi-Ingleside, Tex., area. Permitting, right-of-way, and procurement activities are under way and, subject to receipt of necessary permits and regulatory approvals, the 24-in. OD Cactus II is expected to be operational by third-quarter 2019.
The 575,000-b/d pipeline includes a combination of existing and new pipe. The first new pipeline will extend from Wink South to McCamey, Tex., and the second pipeline from McCamey to Corpus Christi and Ingleside.
PAA received sufficient customer interest to also conduct a second Cactus II binding open season. Origin points will be Orla, Wink South, Midland, Crane, and McCamey, Tex.
