GENERAL INTERESTQuick Takes
ESAI 5-year crude oil outlook shows ample supplies
In its recent 5-year Global Crude Oil Outlook, ESAI Energy projects healthy non-OPEC supply growth to 2023.
The outlook highlights three trends that underscore the expectation that non-OPEC crude and condensate supply will increase by an average of 1 million b/d/year during 2019-23:
• Infrastructure catching up with US shale growth.
• Streamlined, cost-effective offshore projects from the Gulf of Mexico, Latin America, and the North Sea brought to production.
• Russia moving to a “coordinated” growth strategy.
Still, US shale remains the obvious key driver, ESAI said, pointing to a decrease in drilling time and an increase in initial production rates with longer laterals and “super-fracs.” Additionally, many shale producers have brought down debt and increased shareholder returns in the past year. Higher prices increased cash flow, and living within their means paid-off, shown by improved bottom lines on quarterly financial reports, ESAI said, and Permian production has benefited, held back only by infrastructure.
“There is a misperception that a supply crunch is imminent,” said ESAI Energy’s Sarah Emerson. “In a 5-year horizon, the potential for non-OPEC supply growth is impressive. This will have a bearing on the degree to which OPEC will have to dip into spare capacity to offset disruptions.”
Kosmos enters gulf with $1.2-billion acquisition
Kosmos Energy Ltd., Dallas, has agreed to acquire Gulf of Mexico operator Deep Gulf Energy (DGE), Houston, from First Reserve and other shareholders for $1.225 billion comprised of $925 million in cash and $300 million in common shares.
The acquisition, which includes Deep Gulf Energy LP, Deep Gulf Energy II LLC, and Deep Gulf Energy III LLC, adds to “an established business with attractive assets and a strong record of growing production and reserves through infrastructure-led exploration,” to Kosmos’s deepwater Atlantic Margin portfolio.
Production includes 25,000 boe/d, 85% of which is oil, with a reserves-to-production ratio of 8.8, increasing 2018 pro forma production by 50% to 70,000 boe/d. The assets hold 2P reserves of 80 million boe, increasing total 2P reserves by 40% to 280 million boe, the company said.
Kosmos has doubled production over the last 4 years and this acquisition “creates the platform to double production again in the next 4,” said Chairman and CEO Andrew G. Inglis.
The deal is expected to close at the end of the third quarter.
ConocoPhillips to sell Barnett assets for $230 million
ConocoPhillips has agreed to sell its interests in the Barnett shale play to Lime Rock Resources, Houston, for $230 million plus net customary adjustments.
Production associated with the assets for the first half of the year averaged 9,000 boe/d, of which 55% was natural gas and 45% was natural gas liquids, ConocoPhillips said. Without naming the seller, a release from Lime Rock Resources said the natural gas properties are primarily in Montague, Wise, Denton, and Cooke Counties, Tex. The acquired assets have “relatively low” associated water production rates and “substantial” horizontal development opportunities, said Charlie Adcock, co-CEO of Lime Rock Resources.
The transaction represents Lime Rock Resources’ first acquisition in the Fort Worth basin. As of yearend 2017, ConocoPhillips held about 114,000 net acres in the basin and 66,000 net acres in the Barnett, according to its annual report.
The definitive agreement follows an attempt by ConocoPhillips to sell the assets in 2017. An agreement signed in the year’s second quarter was later terminated.
Final rule issued to speed approval of gas exports
The US Department of Energy issued a final rule aimed at expediting approval of small-scale natural gas exports. The July 26 Federal Register notice applied to gas and LNG exports to countries not having a free-trade agreement with the US of no more than 51.75 bcf/year, which qualify for a categorical exclusion under DOE’s National Environmental Policy Act regulations.
Prior to the new rule, which will take effect on Aug. 24, DOE said it had to conduct a public interest review before authorizing such exports. For applications meeting these criteria, the new rule will consider them as “small-scale natural gas exports” deemed to be in the public interest under the 1938 Natural Gas Act. Gas exports to countries with a qualifying FTA already are already deemed in the public interest under the law.
Small-scale US gas exports primarily go to the Caribbean and Central and South America, DOE said. Many countries in these regions do not generate enough gas demand to support the economies of scale required to justify LNG imports from large-scale terminals via conventional tankers, it said.
The small-scale export market developed as a solution. For example, said DOE, one US company, American LNG Marketing LLC, has exported more than 145 cargoes of small-scale shipments from its facility in Florida to both Barbados and Bermuda in the past 2½ years, it noted.
Exploration & DevelopmentQuick Takes
Second Buzzard development phase approved
Nexen Petroleum UK Ltd. has received approval from partners and the UK Oil & Gas Authority for second-phase development of Buzzard oil and gas field in the Central North Sea.
The new phase includes the installation in 96 m of water of a subsea manifold 5 km north of the Buzzard complex and drilling of as many as eight production wells and four water injectors. The production wells will be completed subsea and tied back to the Buzzard production platform, one of four bridge-linked platforms on the field.
The field in April produced an average 134,660 b/d of oil. It has 35 production wells and 13 water injection wells. The new phase is part of a plan to exploit expansion of Nexen’s estimate of original oil in place to 1.592 billion bbl from the original estimate of 970 million bbl.
Incremental development also will occur via the drilling of as many as six infill wells from Buzzard’s wellhead platform. The field produces from the Buzzard sandstone of the Upper Jurassic Kimmeridge Clay formation.
In a high-case estimate assuming production start in 2020, peak incremental production from the subsea wells will occur in 2021 at 43,520 b/d. With infill wells, the maximum boost is 44,350 b/d.
Oil in the second phase is slightly lighter than that of existing production, at 39° gravity.
The new work is expected to delay Buzzard’s cessation of production by 10 years to 2046.
Nexen, a wholly owned subsidiary of CNOOC Ltd., operates Buzzard with a 43.21% interest. Partners are Suncor Energy UK Ltd., 29.89%; Chrysaor, 21.73%; Dyas Exploration UK Ltd., 4.7%; and Oranie-Nassau Energie Resources Ltd., 0.46%.
Second-phase work involves an integrated project team of Nexen; AGR Well Management Ltd.; Baker Hughes; COSL Drilling Europe; Subsea 7; and WorleyParsons Services UK Ltd.
Eni Area 1 development off Mexico approved
Eni SPA has received approval to develop its shallow-water Amoca, Mizton, and Tecoalli oil discoveries in Area 1 of Mexico’s Campeche Bay (OGJ Online, Sept. 26, 2017).
The National Hydrocarbon Commission approved its plan for phased development, with early production starting in first-half 2019 through a wellhead platform in Mizton field.
The plan, subject to a final investment decision expected in the fourth quarter, calls for production to move ashore through a 10-in. multiphase pipeline for treatment at an existing Pemex facility. The early-production plateau rate will be 8,000 bo/d.
Full-field production will start in late 2020 through a floating production, storage, and offloading facility with treatment capacity of 90,000 b/d, the projected plateau production rate. Eni will install two platforms in Amoca field and one in Tecoalli field.
Eni estimates total development capital expenditure at $1.9 billion. It has authorized initial investments to fund long-lead items and start construction of the first platform.
It holds a 100% interest in the Area 1 PSC. It estimates hydrocarbons in place at 2.1 billion boe, 90% oil.
India consolidating oil and gas licenses
India’s Union Cabinet is consolidating hydrocarbon types in its oil and gas licenses in a move that for the first time will allow nonstate operators to develop shale resources.
Until now, India has awarded separate licenses, most recently production-sharing contracts, for conventional resources and coalbed methane.
And it has approved shale exploration and development only for licenses awarded by nomination of state-owned operators. Oil & Natural Gas Corp. and Oil India Ltd. therefore hold the only shale-development rights.
The new policy will allow exploration for and development of all resource types under existing production-sharing contracts and nomination licenses.
“This policy will enable the realization of prospective hydrocarbon reserves in the existing contract areas which otherwise would remain unexplored and unexploited,” the Cabinet said in a press statement.
OGA contracts aim at boosting UKCS work
The UK Oil & Gas Authority (OGA) has awarded a series of contracts to support work designed to boost exploration of the UK Continental Shelf.
Under a contract funding the first year of the 4-year UKCS Petroleum Systems Project, a combine of Lloyd’s Register and IGI Ltd. will compile a database of geochemical data acquired across the UKCS over the past 5 decades.
The database will include the provision of sample information and analysis from legacy well-sampling databases maintained by the British Geological Survey for the OGA.
The geochemical and supporting geological databases will become available to the industry and academia.
The OGA let a separate contract to Ikon Science to evaluate the rock physics and seismic amplitude responses of underexplored Jurassic and Triassic plays of the Central North Sea and East Shetland basin.
Findings will be made available before the 32nd Mature Licensing Round scheduled in mid-2019.
Drilling & ProductionQuick Takes
CERI: IMO 2020 will jolt bitumen output
Thermal bitumen production in Alberta will be jolted when sulfur limits fall for marine fuel in 2020, according to a new study by the Canadian Energy Research Institute.
The group developed an optimization model to assess US refining responses to requirements by the International Maritime Organization (IMO) that bunker fuel contain no more than 0.5 wt % sulfur, down from 3.5 wt % now. Most Canadian bitumen is consumed by complex Canadian and US refineries.
After 2020, CERI said, “Canadian crude will have to compete for US refining space on netback refining value with other crudes that currently contribute to high-sulfur fuel oil supply.”
It modeled US refining for each Petroleum Administration District for Defense under three scenarios defined by degree of compliance with the IMO 2020 regulation.
Under “plausible scenarios,” CERI said, a refinery-margin loss of $16-20/bbl between 2020 and post-2025 will directly affect the price differential between light and heavy crude oil.
That will widen Western Canada Select crude’s discount to West Texas Intermediate, historically $13/bbl, to $31-33/bbl.
CERI determined that production projects based on steam-assisted gravity drainage that use less than 3 cu m of steam to produce 1 cu m of bitumen probably will break even. SAGD projects that use a greater proportion of steam will lose money.
CERI cited data indicating Alberta production below the profitability threshold amounts to about 574,000 b/d of bitumen.
CNRL eyes output expansion at Horizon mine
Canadian Natural Resources Ltd. is considering expansion of production at its Horizon bitumen mine in Alberta by 75,000-95,000 b/d of synthetic crude oil (SCO) in the near and long term. In its earnings report for the second quarter of 2018, CNRL said it has “identified opportunities to increase reliability, lower costs, and add production growth” at the mine, which is in the Athabasca region north of Fort McMurray. It also holds a 70% interest in the nearby Athabasca Oil Sands Project mine.
After an expansion last year, the Horizon mine produced an average 247,000 b/d of SCO during December 2017 and February 2018. CNRL said it has increased by 10,000 b/d its expectations for possible expansion of paraffinic froth treatment at Horizon and is now targeting 40,000-50,000 b/d.
The treatment converts bitumen into diluted bitumen, or dilbit, which is upgraded into SCO. An estimate for capital investment in the froth-treatment expansion is $1.4 billion (Can.).
CNRL also said it expects by yearend to define and high-grade opportunities for near-term SCO production growth at Horizon of 35,000-45,000 b/d. The high-grading includes a possible vacuum gas oil expansion.
For this effort, it has increased its 2018 capital budget by $170 million for advance engineering and procurement of long-lead equipment. It plans to act on the opportunities in 2019 and 2020.
PROCESSINGQuick Takes
Consortium lets contract for Uganda’s first refinery
The Albertine Graben Refinery Consortium (AGRC)—comprised of YAATRA Africa LLC, Mauritius; Lionworks Group Ltd.; Mauritius; Baker Hughes General Electric’s (BHGE) Italian subsidiary Nuovo Pignone International SRL; and Saipem SPA of Italy—has let a contract to Saipem to deliver front-end engineering design for a grassroots 60,000-b/d refinery in Kabaale, in western Uganda’s Hoima district.
Valued at about $68 million, the FEED phase—which will use Ugandan vendors and personnel—will last 17 months, with a possible extension for the engineering, procurement, and construction phase to follow in the future, Saipem said.
The FEED contract follows AGRC’s project framework agreement (PFA) for the refinery signed earlier this year with the Ugandan government through the Ministry of Energy & Mineral Development and state-owned Uganda National Oil Co.
Slated for startup in 2020, the refinery project aims to create greater independence for the domestic Ugandan market by reducing imports of oil and refined products from other countries, as well as ensure a hub for refined products for the East African market, Saipem said.
Under the April PFA, the BHGE-led AGRC will be responsible for funding all pre-final investment decision activities for the project as well as construction and operation of the refinery, which is to be developed as a commercially viable venture with a regional market focus.
Once completed, the refinery will produce kerosine, gasoline, diesel, heavy fuel oils, and other products for supply to the Ugandan and regional markets.
Overall cost of the proposed refinery project is estimated at about $3-4 billion, Irene Muloni, Uganda’s minister of energy, said in April.
Methanex lets contracts for Geismar 3 methanol plant
Methanex Corp., Vancouver, BC, has let a contract to KBR Inc. to provide front-end engineering design services for a 5,000-tonne/day methanol plant to be built adjacent to its existing methanol plants in Geismar, La. (OGJ Online, Jan. 27, 2015).
As part of the reimbursable engineering, procurement, and construction management option contract, KBR will work closely with Methanex to provide FEED services for the third methanol operating plant at the Geismar site, the service provider said.
KBR said it expects to complete FEED work on the project over the next 12 months, with final investment decision on the third plant due by mid-2019.
Pending FID by Methanex to proceed with adding the potential third plant at Geismar, KBR will then have an opportunity to provide detailed EPCM services for the project, the service company said.
Methanex currently operates two methanol plants at Geismar, each with a production capacity of 1 million tonnes/year.
MPLX to expand Permian processing, development
MPLX LP, through its subsidiary MarkWest Energy Partners LP, has completed definitive agreements with Kaiser Francis Oil Co. (KFOC) to provide gathering and processing services in the Delaware basin as part of its plan to further expand its growing presence in the Permian basin.
As part of the agreements, with Kaiser Francis as an anchor, MarkWest will develop the 200-MMcfd Tornado gas processing plant in Loving County, Tex., as well as natural gas gathering infrastructure primarily in Lea County, NM, both of which are scheduled to be completed in August 2019, MPLX said.
MarkWest also owns and operates two gas processing plants in Culberson County, Tex., that—alongside other unidentified plants under development—also will be connected to the planned Tornado plant via a high-pressure gathering system, according to the company.
In addition to the proposed gas plant and gathering infrastructure, MPLX has acquired a 10% equity interest in the Agua Blanca pipeline originating in Orla, Tex., and terminating at Waha, Tex., which entered service in April.
With the pipeline already fully subscribed at 1.4 bcfd but expandable to 2 bcfd, MPLX said a lateral currently is under construction to connect Agua Blanca with MarkWest’s 200-MMcfd Argo processing plant in West Texas, which reached startup earlier this year (OGJ Online, June 13, 2017).
TRANSPORTATIONQuick Takes
Inpex starts gas production from Ichthys field
The Inpex Corp.-led consortium at Ichthys gas-condensate field in the Browse basin 220 km offshore Western Australia has started natural gas production from its subsea wells to the massive 120,000-tonne Ichthys Explorer production platform.
LNG from the project’s onshore Darwin plant in the Northern Territory is expected by the end of September.
Inpex said the start-up marks the beginning of what is expected to be a 40-year life for the $40-billion project.
Gas from the wells will be processed on the platform. Condensate will then be piped to the Ichthys Venturer floating production, storage, and offloading vessel moored nearby, while dry gas will be piped nearly 900 km by subsea pipeline to the Darwin LNG facilities.
The project expects its initial cargo of condensate to be shipped first and then LNG and LPG during September.
It will take 2-3 years to reach full production of 8.9 million tonnes/year along with 1.7 million tonnes of LPG and 100,000 b/d of condensate.
The start-up of gas production is about 18 months after the original expected on-stream date of yearend 2016. The project reached final investment decision in 2012.
Targa, partners to develop Whistler Pipeline project
Targa Resources Corp.; NextEra Energy Pipeline Holdings LLC, an indirect, wholly owned subsidiary of NextEra Energy Resources LLC; WhiteWater Midstream LLC, a portfolio company of Denham Capital Management and Ridgemont Energy Partners; and MPLX LP plan to jointly develop the Whistler Pipeline project to provide an outlet for natural gas production from the Permian basin to markets along the Texas Gulf Coast.
The proposed project is designed to transport 2 bcfd of gas through 450 miles of 42-in. pipe from Waha, Tex., to NextEra’s Agua Dulce market hub, with another 170 miles of 30-in. pipe continuing from Agua Dulce and ending in Wharton County.
Supply will be sourced from upstream connections in the Midland and Delaware basins, including direct connections to Targa plants through a 27-mile, 30-in. pipeline lateral, as well as a direct connection to the 1.4 bcfd Agua Blanca Pipeline—a joint venture of WhiteWater, WPX Energy, MPLX, and Targa—which crosses through the Delaware basin, including portions of Culberson, Loving, Pecos, Reeves, Winkler, and Ward counties. The project would have access to the Nueces Header and markets at Agua Dulce, as well as along a northern extension through Corpus Christi to the Houston Ship Channel.
The project, to be constructed by NextEra Energy Pipeline Holdings, operated by Targa, and financed at the project level, would begin operation in fourth-quarter 2020.
Targa, NextEra, MPLX, and WhiteWater, and their producer customers would commit volumes exceeding 1.5 bcfd to the project. The project is in negotiations for additional firm transportation commitments. An open season is expected in the coming months.
FERC: NY waited too long to deny line’s water permit
The US Federal Energy Regulatory Commission ruled that the New York State Department of Environmental Conservation (NYSDEC) waived its authority to deny the Northern Access Pipeline Project a crucial water permit because the state agency did not act within a year of receiving the interstate natural gas pipeline sponsors’ application for it.
Sponsors National Fuel Gas Co. and Empire Pipeline Inc. applied for a NYSDEC certification under Section 401 of the federal Clean Water Act on Mar. 2, 2016, FERC said in its Aug. 6 ruling. NYSDEC denied the application on Apr. 7, 2017, which was more than a year after the state agency received it, a deadline established in CWA Section 401. NYSDEC essentially waived its CWA certification authority when it did this.
The commission reached a similar conclusion nearly a year earlier when it ruled that NYSDEC waived its authority to approve or deny a CWA Section 401 permit for the Millennium gas pipeline’s 7.8-mile Valley Lateral in Orange County, NY, after failing to act within a year (OGJ Online, Sept. 18, 2017).
In an Aug. 7 statement, Williamsville, NY-based NFGC said FERC’s ruling a day earlier removed a major barrier for the Northern Access project while making the energy grid more reliable and resilient. “We remain committed to the project, and due to the...delay caused by the actions of the state agency, our team is developing a revised timeline including reviewing the status of various other relevant permits,” it said.