GENERAL INTERESTQuick Takes
EPA: US GHG emissions down in 2017 from year before
US gross greenhouse gas (GHG) emissions totaling 6,472 million tonnes of carbon dioxide equivalent (tCO2e) in 2017 came in 21.1 million tCO2e, or 0.3% less, than 2016’s 6,493 million tCO2e, the US Environmental Protection Agency reported.
The year-to-year decline was driven partly by a drop in CO2 emissions from fossil fuel combustion to 4,920 million tCO2e, which was a result of factors including a continued shift to natural gas from coal to generate electric power, more use of renewable fuel technologies at power plants, and milder weather that reduced demand, EPA said in its latest US Greenhouse Gas Inventory.
Total gross domestic GHG emissions in 2017 were 1.6% more than the 6,373 million tCO2e in 1990, the inventory’s baseline year. The 2017 amount was 14.1% less than 10 years earlier, when the inventory hit its peak of 7,371 million tCO2e.
Petroleum was the largest single fossil fuel combustion source, with a 44.6% share, followed by 29.5% for gas, and 25.8% for coal, EPA’s GHG inventory indicated.
Responding to this latest EPA report, Howard J. Feldman, American Petroleum Institute senior director for regulatory and scientific affairs, said the findings continue to reflect falling methane emissions per unit of US oil and gas production.
“The increased use of gas has reduced carbon emissions, lowered costs to American consumers, and increased our nation’s manufacturing competitiveness,” Feldman said. “US industrial electricity costs are lower than those of our foreign competitors, giving manufacturers—including producers of steel, chemicals, refined fuels, plastics, fertilizers, and numerous other products—a major competitive advantage.”
EIA: US E&P firms’ funding lowest in 5 years
In 2018, publicly traded US oil and gas exploration and production companies issued the lowest amount of new funding since at least 2013, raising $14 billion in debt and $2 billion from public equity markets, according to an analysis by the US Energy Information Administration.
Several factors likely contributed to reduced financing activity in 2018 compared with previous years, EIA said.
First, the relatively higher level of interest rates in 2018 contributed to a higher cost of issuing debt or equity for all companies, including E&P firms. The US Federal Funds rate averaged 1.8% in 2018—the highest since 2008—and energy business bond yields rose in the fourth quarter as oil prices declined.
In addition to higher interest rates, E&P companies may have needed fewer outside sources of capital than in previous years. Through third-quarter 2018, a group of 46 US oil producers generated $56 billion in cash flow from operating activities. The amount of cash flow from operations through the first three quarters of 2018 was higher than full-year amounts from 2015-17.
As a result, full-year 2018 cash flow will likely be the highest annual total since 2014 for these companies. Collectively, they spent $60 billion in capital expenditures and generated a net $8 billion from asset sales. Because cash from operations plus asset sales exceeded capital expenditures, many companies may have had enough cash to fund their investing activities without the need to issue debt or equity.
Chevron makes senior leadership appointments
Pierre Breber has been named vice-president and chief financial officer of Chevron Corp., effective Apr. 1. He succeeds Patricia Yarrington who will retire after 38 years of service.
Mark Nelson, currently vice-president, midstream, strategy, and planning, will succeed Breber as executive vice-president, downstream and chemicals.
Colin Parfitt, currently president, supply and trading, will become vice-president, midstream. Both appointments are effective Mar. 1.
Breber joined Chevron in 1989. He currently serves as executive vice-president, downstream and chemicals.
Harbert named as next AGA president
Karen A. Harbert, who has led the US Chamber of Commerce’s energy program for the past decade, will become the American Gas Association’s next president on Apr. 1. She will succeed David K. McCurdy, who plans to retire on Feb. 28. Harbert will be the first woman to lead AGA’s staff.
While at the US Chamber, Harbert was president and chief executive of what initially was the Institute for 21st Century Energy before it became the Global Energy Institute (GEI). She led the program’s development of a comprehensive Energy Works for US platform, which provides policy recommendations to secure the country’s energy future and create millions of jobs, billions of dollars in revenue, and trillions of dollars of private investment, GEI said.
Before joining the US Chamber’s staff, Harbert was assistant secretary for policy and international affairs at the US Department of Energy, where she was the primary policy advisor to the energy secretary and the department on energy issues. Concurrently, she was vice-chairman at the Paris-based International Energy Agency.
Prior to her tenure at DOE, Harbert was deputy assistant administrator for Latin America and the Caribbean at the US Agency for International Development where she oversaw programs in 11 countries, totaling more than $800 million and 1,000 employees.
Exploration & DevelopmentQuick Takes
ExxonMobil reports two discoveries offshore Guyana
ExxonMobil Corp. reported additional discoveries offshore Guyana with the Tilapia-1 and Haimara-1 wells in southeastern Stabroek block, bringing the total discoveries on that block to 12. The latest discoveries contributed to an estimated resource of more than 5 billion boe.
Tilapia-1 is the fourth discovery in the Turbot area that includes the Turbot, Longtail, and Pluma discoveries. Tilapia-1 encountered 305 ft of oil-bearing sandstone reservoir and was drilled to 18,786 ft in 5,850 ft of water. The well is about 3 miles west of the Longtail-1 well.
The Noble Tom Madden drillship began drilling Tilapia-1 on Jan. 7 and will next drill the Yellowtail-1 well, which is 6 miles west of Tilapia-1 in the Turbot area. Baseline 4D seismic data acquisition is under way.
Tilipia-1 and Haimara-1 were drilled as wildcats (OGJ Online, Jan. 7, 2019). The Haimara-1 well encountered 207 ft of gas and condensate-bearing sandstone reservoir. The well was drilled to 18,289 ft in 4,590 ft of water.
Haimara-1 is 19 miles east of the Pluma-1 discovery in a potential new development area. The Stena Carron drillship began drilling Haimara-1 on Jan. 3 and now will return to the Longtail discovery to complete a well test.
ExxonMobil is considering using at least five floating production, storage, and offloading vessels on the Stabroek block, expected to produce more than 750,000 b/d by 2025. The Liza Phase 1 development is expected to produce as much as 120,000 b/d in early 2020 via the Liza Destiny FPSO (OGJ Online Dec. 28, 2018).
Liza Phase 2 is expected to start by mid-2022. Pending government and regulatory approvals, sanctioning is expected in this year’s first quarter. Liza Phase 2 use a second FPSO designed to produce up to 220,000 b/d. Sanctioning of a third development, Payara, also is expected with start up as early as 2023.
Stabroek block is 6.6 million acres. Esso E&P Guyana Ltd. is operator with 45% interest. Hess Guyana Exploration Ltd. holds 30% interest and CNOOC Petroleum Guyana Ltd., a wholly owned subsidiary of CNOOC Ltd., holds 25% interest.
Cuadrilla reports initial Bowland shale flow tests
Cuadrilla Resources Ltd. said drilling, hydraulic fracturing, and flow testing of the UK’s first horizontal shale gas well indicated a rich reservoir of recoverable high-quality natural gas from the Bowland shale in northwest England.
Francis Egan, Cuadrilla chief executive officer, reported a complex fracture network was created in the shale and sand injected into the fracture stayed in place.
Crews started fracturing in Lancashire in October 2018, resuming fracturing in the UK for the first time in 7 years. Gas started to flow to the surface from Cuadrilla’s shale exploration well at the Preston New Road site in early November.
But Cuadrilla had to stop operations multiple times because microseismic events measured above a UK threshold requiring a halt to operations (OGJ Online, Dec. 12, 2018). Fracturing must be stopped if microseismic events of 0.5 or higher on the Richter scale are reported. Pressure in the well must be reduced.
Egan said the “intentionally conservative microseismic operating limit” has severely constrained the volume of sand that could be injected int the shale.
“We have only partially tested this well with just two out of the 41 stages installed along the horizontal section fractured fully as designed and less than 14% of the sand we had planned to inject to the shale rock put in place.”
Still, gas flowed at a peak rate of more than 200,000 standard cfd and a stable rate of some 100,000 scfd, he said. Cuadrilla estimates a potential initial flow rate range of 3-8 million scfd.
Previously, Ineos and Cuadrilla have suggested that the induced seismicity regulations be reviewed (OGJ Online, Feb. 4, 2019). The UK Department for Business, Energy, and Industrial Strategy, however, denied the requests. “The government has given the industry significant support to develop while ensuring our world-leading regulations remain in place to ensure fracking happens safely and responsibly,” it said.
SDX Energy awarded two licenses in Morocco
SDX Energy Inc., London, has agreed to drill an exploration well and do seismic work on each of two licenses it has been awarded in Morocco.
On the Moulay Bouchta Ouest exploration license, it will reprocess 150 line-km of 2D seismic data and acquire 100 sq km of 3D seismic data. The seismic work and drilling of the exploration well are to be completed within the first 3½ years of the 8-year license term.
The renewed 857-sq-km Lalla Mimouna Sud license also has an 8-year term, during the first 3 years of which SDX is to drill the well and acquire 50 sq km of 3D seismic data.
SDX originally acquired the license when it bought Moroccan and Egyptian assets from Circle Oil PLC for $30 million in January 2017. The license expired after completion of work commitments.
SDX applied for and won back the license after acquiring additional 3D seismic data in the area.
Drilling & ProductionQuick Takes
West Qurna-2 second-phase drilling starts
Lukoil has started drilling production wells in the second phase of development of West Qurna-2 oil field in southern Iraq.
It has signed contracts for the drilling of 54 wells targeting the Late Cretaceous Mishrif formation and three wells targeting the Early Cretaceous Yamama.
The work will increase West Qurna-2 production to 480,000 b/d in 2020 from 400,000 b/d currently. Lukoil says it’s using a cluster drilling approach new to Iraq.
Under a revised development plan Lukoil signed with state-owned Basra Oil Co. last year, West Qurna-2 output is to reach a plateau of 800,000 b/d in 2025. Plateau production under the original service contract was to have been 1.2 million b/d (OGJ Online, May 11, 2018).
Antero, DOJ reach Marcellus fracing settlement
Antero Resources Corp., Denver, has agreed to pay $3.15 million for Clean Water Act violations at 32 sites in three West Virginia counties affected by Antero’s Marcellus shale natural gas operations, the US Department of Justice reported.
DOJ, the US Environmental Protection Agency, and the West Virginia Department of Environmental Protection said the West Virginia counties involved are Harrison, Doddridge, and Tyler. Documents filed in the US District Court for the Northern District of West Virginia said Antero will pay a civil penalty and conduct restoration, stabilization, and mitigation work. The proposed settlement is subject to a comment period.
The work will involve 51½ acres, EPA said, estimating the proposed mitigation and restoration will cost $8 million. The area includes more than 3 acres of wetlands.
The violations involved the unauthorized disposal of dredged and fill materials into water nearby Antero’s hydraulic fracturing operations, DOJ said in a news release. Some of the incidents date back to 2011.
A consent decree said Antero will pay for the rehabilitation work, which will be directed by US and state environmental officials along with the US Army Corps of Engineers.
Antero will divide the penalty payment between West Virginia and the US government, the consent decree said.
“During a series of inspections between Apr. 8 and Apr. 11, 2014, EPA and the state identified ongoing poor operational practices at a number of sites, including significant sedimentation, incorrectly installed culverts and outfalls, impacts to unprotected mapped streams and wetlands, and a general lack of maintenance leading to further erosion,” documents said.
BP starts second-stage gas flow from Egypt fields
BP PLC has started production from the second stage of its West Nile Delta development offshore Egypt. The project, which produces gas from Giza and Fayoum fields, was developed as a deepwater, long-distance tie-back to an existing onshore plant.
The Giza and Fayoum development, which includes eight wells, is producing 400 MMcfd of gas and is expected to ramp up to a maximum rate of some 700 MMcfd.
The WND development, which encompasses the North Alexandria and West Mediterranean Deepwater offshore concession blocks, is being developed in three phases. When fully on stream in 2019, combined production from all three phases is expected to reach 1.4 billion bcfd, equivalent to about 20% of Egypt’s current gas production. All gas produced will be fed into the national gas grid.
Stage 1 of the project, which started producing in 2017, included gas production from the first two fields, Taurus and Libra. Taurus, Libra, Giza, and Fayoum fields hold gas resources within the Pliocene formations. Raven field, to be developed in Stage 3, holds gas resources in the deeper Miocene formations. Production is expected late this year.
BHP approves Atlantis Phase 3, Trion field drilling
BHP Group’s board approved $696 million in funding to develop the Atlantis Phase 3 expansion in the US Gulf of Mexico and $256 million in funding to drill an additional appraisal well in Trion field offshore Mexico.
BHP’s Atlantis decision came after Atlantis operator BP PLC approved the Atlantis Phase 3 in January (OGJ Online, Jan. 8, 2019). Atlantis Phase 3, which is 130 miles off Louisiana, is a subsea tieback of eight production wells. Production is expected to begin in 2020. BHP holds 44% interest in Atlantis field. BP holds 56% interest.
Offshore Mexico, BHP said it is working to delineate the scale of Trion field. The 3DEL appraisal well will help BHP confirm the volume and hydrocarbon composition near the Trion structure crest and study its development viability. The appraisal well is scheduled to be spudded in this year’s second half. BHP is Trion operator with 60% interest while Petroleos Mexicanos (Pemex) holds 40% interest.
PROCESSINGQuick Takes
Mongolia advances construction of refinery
The government of Mongolia—through wholly owned Mongol Refinery State Owned LLC—has signed a memorandum of understanding with Engineers India Ltd. (EIL) for delivery of additional work on the country’s first refinery project now under construction on 150 hectares in Altanshiree Soum near Sainshand in the southeastern province of Dornogovi (OGJ Online, June 22, 2018).
As part of the MOU signed on Feb. 10, EIL will provide project management consultancy services for construction of the 30,100-b/d grassroots refinery, India’s Ministry of Petroleum & Natural Gas said in a news release. This latest contract follows Mongolia’s earlier award to EIL for delivery of a detailed feasibility study on the project (OGJ Online, Jan. 26, 2018).
Supported by a $1-billion soft credit line to Mongolia from India announced in May 2015, the refinery comes as part of India’s effort to develop further ties with the landlocked country and help reduce its energy dependence on China and Russia.
While a timeframe for official commissioning of the project has yet to be revealed, the refinery, once completed, will process Mongolia’s own shale crude production currently exported to China to produce 560,000 tonnes/year of gasoline, 670,000 tpy of diesel, and 107,000 tpy of liquefied gas for domestic use, helping to reduce the country’s finished product imports from Russia.
Gas plant starts at Dirok field in Assam
Hindustan Oil Exploration Co. Ltd., Chennai, has placed on stream a modular gas processing plant at Dirok natural gas field in Assam, where it plans to drill four wells under a revised plan for second-phase development.
The Hollong plant, about 10 km south of Digboi, can process 35 MMscfd of gas and 800 b/d of condensate. HOEC called it “a first of its kind in India.”
The field started production in 2017 (OGJ Online, Aug. 30, 2017). Initial development included the drilling of six wells, construction of the Hollong plant, and pipeline construction.
In addition to the planned wells, second-phase development will include expansion of the gas processing plant, more pipeline construction, and an increase in production to 55 MMscfd.
HOEC operates Block AAP-ON-94/1 in partnership with state-owned Oil India Ltd. and Indian Oil Corp. Ltd.
Eni, SABIC form synthesis gas venture
Eni SPA and Saudi Arabian Basic Industries Corp. (SABIC) have signed a joint development agreement to advance a technology for conversion of natural gas into synthesis gas. The partnership will build a demonstration plant at an Eni facility.
The technology is based on the short contact time catalytic partial oxidation of natural gas. “This technology was initially developed by Eni after an intensive [research and development] period,” Eni said in a press statement. “This was coupled with SABIC’s short contact time reactor R&D and the company’s extensive knowledge of the integration of synthesis gas generation into processes to produce derived chemicals.”
The statement said the joint technology will improve synthesis gas production and integration into high-value applications by lowering capital and operating expenditures, increasing energy efficiency, lowering carbon dioxide emissions, and broadening feedstock flexibility.
TRANSPORTATIONQuick Takes
Prompt approval sought for pipeline safety update
Six public and trade associations have asked US Transportation Sec. Elaine Chao “to act expeditiously” to approve revisions to the US Pipeline and Hazardous Materials Safety Administration’s federal natural gas pipeline safety regulations.
“PHMSA’s rule will advance gas transmission pipeline safety by defining specific requirements to facilitate the use of 21st-century pipeline safety technologies and processes,” the groups, which include the Interstate Natural Gas Association of America and the American Gas Association, said in their Feb. 7 letter.
For example, it will facilitate deployment of noninvasive tools that can evaluate a pipeline’s condition and identify sections needing repairs or replacement, they noted.
“The rule provides a foundation upon which PHMSA can better promote the utilization of modern pipeline inspection technologies, recognizing the safety, environmental, and consumer benefits that such technologies can provide,” the groups said.
It also sets out requirements for operators to test certain existing pipelines to ensure that they meet today’s safety standards, they said. “Thus, the rule provides a means for pipeline companies to continue advancing the safety initiatives identified by Congress in 2011.”
The organizations said they are represented on DOT’s gas pipeline advisory committees and that they provided PHMSA recommendations on the proposed rule’s technical feasibility, reasonableness, cost-effectiveness, and practicability during public meetings of the proposed rule throughout 2017 and 2018.
“While our organizations sometimes disagree about the specifics of pipeline safety regulations, in this case consensus was achieved on many important pipeline safety topics through the advisory committee process. The advisory committee ultimately provided PHMSA with recommendations to support finalizing the rule,” they said.
APLNG JV lets Surat gas gathering line contract
The Origin Energy-ConocoPhillips combine Australia Pacific LNG has let a package of gas gathering and infrastructure works worth $90 million (Aus.) to CPB Contractors—the Australasian construction company of Sydney-based engineering firm CIMIC Group Ltd. (formerly Leighton Holdings)—for the Surat basin of southeast Queensland.
The contract, which will connect and deliver gas from more than 300 coal seam gas (CSG) wells in the region during the next 2 years, is an extension of CPB’s work for APLNG that delivered 800 wells over the past 5 years.
The new contract includes infrastructure for access tracks and well site lease pad preparation, gas and water pipeline gathering networks, electrical supply connections, and the rehabilitation of right-of-ways once installations have been completed.
The gas from the Surat CSG wells is sent for processing to APLNG’s LNG plant on Curtis Island near Gladstone.
Sentinel to develop Texas GulfLink export terminal
Sentinel Midstream, Dallas, has reported plans to development Texas GulfLink, a proposed deepwater crude oil export terminal near Freeport, Tex. The completed facility will be capable of fully loading very large crude carrier vessels.
Texas GulfLink will include an onshore terminal with as much as 18 million bbl of storage, an offshore 42-in. pipeline, and a manned offshore platform to facilitate port operations with two catenary anchor leg mooring single-point mooring buoys. Projected export loading rates will be as much as 85,000 bbl/hr, with a nominal capacity of 1.2 million b/d over the course of a year.
