GENERAL INTEREST — Quick Takes
Netanyahu backs gas deal before High Court
Prime Minister Benjamin Netanyahu made an unprecedented personal appearance before Israel's High Court of Justice on Feb. 14 to defend his maneuvers in support of deepwater natural gas development.
In a controversial move last year, Netanyahu assumed the role of economy minister to sidestep the antitrust commissioner, who opposed an agreement allowing development of giant Leviathan gas field and expansion of nearby Tamar field (OGJ Online, Dec. 17, 2015). The commissioner resigned. His replacement hasn't supported the agreement, known in Israel as the gas outline, which the Cabinet approved last August. Among other things, the outline requires adjustment of license interests.
Article 52 of Israel's Restrictive Trade Practice Law of 1988 allows the economy minister to override antitrust objections when security or foreign policy interests are at stake. It previously hadn't been invoked.
Before the High Court, the prime minister said "our ability to realize the potential of the state of Israel's gas" was at stake. Further delay to long-delayed development, he said, "could lead to grave results, and it is doubtful if we could recover from them."
Shelly Yacimovich, a member of the Knesset from the opposition Zionist Union party, said Netanyahu's appearance "was empty of any truthful substance," according to press reports.
Total trims 2016 capex by 15%
Total SA is setting its organic capital expenditure for 2016 at about $19 billion, a reduction of 15% vs. that of 2015.
The French firm says the cut "marks a transition to a sustainable level of investments of $17-19 billion from 2017 onwards." Asset sales of $4 billion are expected in 2016, the same level as in 2015.
Total also reported an adjusted net income for 2015 of $10.52 billion, down 18% from the total a year earlier. Its fourth-quarter adjusted net income was $2.08 billion, down 26% year-over-year.
Strong downstream results in 2015, Total said, offset some of the upstream declines that resulted from lower oil and gas prices. Adjusted net operating income for the year from its refining and chemicals segment was $4.89 billion, twice that of 2014 because of industrial performance during a period of high margins and cost reduction programs.
Adjusted net operating income for the year from its upstream segment was $4.77 billion, a drop of 55% compared with that of 2014, essentially due to the lower commodity prices, partially offset by an increase in production, a decrease in operating costs, and a lower effective tax rate.
Hydrocarbon production in 2015 was 2.35 million boe/d, an increase of 9.4% compared with the 2014 level.
Companywide production is expected to rise 4% in 2016 compared with the 2015 total-when it posted a year-over-year increase of 9%-which is in line with Total's average growth target of 5%/year during 2014-19.
Five major startups are planned by the firm in 2016, the first of which was reported Feb. 8 from the Laggan and Tormore gas-condensate fields in the West of Shetland area (OGJ Online, Feb. 8, 2016).
Downstream, Total says its target to reduce European refining capacity by 20% will be met by yearend, a year ahead of the initial plan announced in 2012.
The cessation of traditional refining activities at La Mede in view of its conversion to a biorefinery (OGJ Online, Apr. 16, 2015), the restructuring of the Lindsey refinery, and the modernization of the Antwerp refinery will be finalized before yearend (OGJ Online, Sept. 24, 2014).
Cenovus cuts spending by 20%, plans to shed more jobs
Cenovus Energy Inc., Calgary, has reduced its planned capital spending for 2016 by an additional 20% to $1.2-1.3 billion (Can.), down 27% from that of 2015 and 59% from that of 2014. The firm outlined its initial 2016 budget in December (OGJ Online, Dec. 10, 2015).
As part of the measure, Cenovus plans to further reduce its workforce during the year after cutting 24% in 2015 compared with its 2014 level.
Separately, Kieron McFadyen will join the company on Apr. 6 as executive vice-president and president, upstream oil and gas. He will be responsible for all of Cenovus's oil sands and conventional operations.
Planned capital budget reductions for 2016 include lower spending at Cenovus's Foster Creek and Christina Lake oil sands projects, its emerging oil sands assets, and the company's conventional oil business.
However, the reductions are expected to have minimal impact on the company's oil sands production for 2016, which is forecast to remain within guidance at 144,000-157,000 b/d net.
Cenovus also says it sees further opportunities to cut operating expenses by prioritizing repairs and maintenance and cancelling or deferring nonessential work, including the deferral of a scheduled turnaround at Foster Creek until 2017.
Cenovus posted a net loss in 2015 of $641 million (Can.), compared with a loss of $472 million in 2014. Over the past 2 years, the firm has recorded inventory write-downs and asset impairments totaling $1.18 billion.
In 2015, companywide oil production totaled 206,947 b/d, up 2% from that of a year earlier; and natural gas production was 441 MMcfd, down 10% year-over-year. In 2016, liquids output is expected at 196,000-213,000 boe/d, with total upstream output at 258,000-280,000 boe/d.
At yearend 2015, Cenovus had total proved reserves of 2.5 billion boe, an increase of 7% compared with the 2014 total.
Exploration & Development — Quick Takes
Ireland awards first phase of 2015 license round
Ireland's Department of Communications, Energy & Natural Resources has awarded 14 new licensing options in the country's southern Porcupine basin. The 2015 Atlantic Margin licensing round recently concluded with 43 applications received by the September 2015 deadline, a number of which included seismic acquisition for later this year.
Minister Joe McHugh described the response to the round as "extremely positive," adding "this is by far the largest number of applications received in any licensing round held in the Irish offshore."
The awards offered include eight companies: Eni SPA with BP PLC as partner on one license; Europa Oil & Gas (Holdings) PLC, Nexen Energy ULC, Scotia, and Woodside Petroleum Ltd. received one license each; and ExxonMobil Corp. and Statoil ASA will partner on six licenses with ExxonMobil operating two blocks, and Statoil as operator on four blocks.
Woodside has been active off western Ireland in the Porcupine basin since 2013 when it farmed in to Petrel Resources PLC's licenses 3/14 and 4/14 (OGJ Online, Mar. 6, 2013).
The current license options include a 2-year work period. The second and final phase of awards is planned for mid-May.
Carboniferous sandstone targeted onshore UK
Egdon Resources PLC spudded the Laughton-1 well in UK onshore license PEDL209 in Lincolnshire, UK, on Feb. 12. The well is targeting a structural trap at 1,500 m. According to the firm, the Laughton prospect has multiple conventional targets, of which the 15-m thick Silkstone Rock is the primary interval.
The analogous Corringham oil field 5 km southeast of Laughton-1 produces from Silkstone. The Laughton-1 also will target two additional prospective reservoirs-Kilburn sandstone and Wingfield Flags. Egdon estimates its three targets to contain prospective resource volumes of 1.3 million bbl of oil.
Due to the conventional nature of these reservoirs, hydraulic fracturing will not be deployed in its completion strategy, the firm said. Lincolnshire has been associated with UK's shale potential in the Carboniferous Pendleian, which is 2,000 m deep and has been identified as prospective in the nearby Bowland basin in northwest England (OGJ Online, Jan. 16, 2013).
Union Jack PLC will earn 10% interest in the Laughton-1 exploration well and two other conventional prospects in PEDL209, in return for covering 16.67% of the well costs. Egdon Resources UK Ltd. will maintain 50% interest with partners Blackland Park Exploration Ltd. and Stelinmatvic Industries Ltd. holding 28% and 12%, respectively.
Woodside makes second gas discovery off Myanmar
Woodside Petroleum Ltd. reported that the Thalin-1A exploration well on Block AD-7 in the Rakhine basin intersected a gross gas column of 64 m, and 62 m of net gas pay is interpreted within the primary target interval.
Block AD-7 is in the Bay of Bengal, 100 km west of Myanmar. Located in 836 m of water, Thalin-1A reached a TD of 3,034 m, referenced from the rig rotary table.
Following drilling, wireline logging was conducted and confirmed the presence of a gas column through pressure measurements and gas sampling, Woodside says.
The Thalin-1A discovery follows the Shwe Yee Htun-1 gas discovery on Block A-6, which lies on the opposite end of the Rakhine basin, reported in January (OGJ Online, Jan. 4, 2016).
"These results are very encouraging for future exploration and appraisal activity given the significant footprint we have in Myanmar," said Peter Coleman, Woodside chief executive officer, adding that Thalin-1A successfully proved a working petroleum system and a new play-type different from that encountered at Shwe Yee Htun-1.
Thalin-1A is 60 km west of the Daewoo International Corp.-operated producing Shwe field, which has an onshore gas plant and pipeline gas export facilities (OGJ Online, Aug. 8, 2013).
With 40% interest in AD-7, Woodside Energy (Myanmar) Pte. Ltd. is operator with respect to deepwater drilling. Daewoo, with 60% interest, is operator for all other operations.
AD-7's area was recently expanded north to the Myanmar maritime boundary. The partners have approved the acquisition of an additional 1,200 sq km of 3D seismic data over the area, which is scheduled to be conducted March.
Woodside is the largest acreage holder in the offshore Rakhine basin with interests in six blocks, four of which were directly awarded by Myanmar in 2014 (OGJ Online, Mar. 26, 2014). The six permits comprise 47,000 sq km and represent 20% of Woodside's global exploration acreage.
Drilling & Production — Quick Takes
Gas flow starts from Algeria's In Salah southern fields
The In Salah Gas joint venture has started natural gas production from the 2,000-sq-km southern fields project, the latest phase of development of seven gas fields in central Algeria.
The project involves development of Gour Mahmoud, In Salah, Garet el Befinat, and Hassi Moumene dry gas fields by partners Sonatrach, BP PLC, and Statoil ASA. Drilling of 26 planned southern field wells began in 2014 and is expected to continue until 2018.
Production is planned to ramp up to 14.1 million cu m/day as wells in Garet el Befinat and Hassi Moumene are brought online over the next 2 months.
The JV began production in 2004 from Krechba, Teguentour, and Reg fields in the northern portion the area (OGJ Online, July 7, 2004). BP says developing the southern fields will maintain anticipated production at 9 billion cu m/year.
The southern project's scope includes a 500-MMscfd gas dehydration central processing facility near Hassi Moumene (OGJ Online, Jan. 19, 2011); brownfield modifications to existing processing facilities at Reg, Teg, and Krechba; 150 km of carbon steel export pipelines; 160 km of 13% chrome corrosion resistant alloy infield flowlines; and the drilling and tie-in of the 26 wells.
In Salah Gas has total estimated recoverable resources of 159 billion cu m. Gas from the southern fields is sold under the same contracts as gas from the northern fields.
Partners' shares in the In Salah Gas JV are Sonatrach 35%, BP 33.15%, and Statoil 31.85%. BP's and Sonatrach's In Salah involvement dates back more than 20 years (OGJ, May 5, 1997, p. 58). Statoil bought into the partnership in 2003 (OGJ Online, July 15, 2003).
BP, Oman Oil to develop Khazzan project's second phase
BP PLC and Oman Oil Co. have signed a heads of agreement with the government of Oman to amend the Oman Block 61 exploration and production sharing agreement (EPSA), extending the block's license area and enabling further development of the major Khazzan tight gas field.
BP operates Block 61 with 60% interest and Oman Oil holds the remaining 40%.
The extension will add 1,000 sq km to the south and west of the original 2,700-sq-km Block 61, and allow a second phase of development, accessing more resources in the area that have been identified by drilling activity within the original block.
Further development is subject to final approval of the government of Oman and BP. Both approvals are expected in 2017.
BP says the Khazzan reservoirs in Block 61 represent one of the Middle East's largest unconventional tight gas accumulations. "Khazzan is a major resource with the potential to produce gas for Oman for decades," said Bob Dudley, BP Group chief executive.
Combined plateau production from Phases 1 and 2 is expected to total 1.5 bcfd, equivalent to 40% of Oman's current total domestic gas production.
The Phase 1 project, sanctioned in December 2013, remains on schedule for startup in late 2017. Subject to completion of the agreements and final sanction, the new Khazzan Phase 2 project will come on stream from 2020.
BP in 2014 handed out billions of dollars in contracts for the project covering drilling work (OGJ Online, Oct. 2, 2014), and process and infrastructure work (OGJ Online, Feb. 20, 2014; Mar. 4, 2014). The firm had previously said it was mulling investment of $15 billion over a 10-year period for full-field development of Block 61 fields (OGJ Online, June 20, 2011).
The two phases are expected to produce 1.5 bcfd through development of 10.5 tcf of recoverable gas resources, involving construction of a three-train central processing facility with associated gathering and export systems and drilling 325 wells over a 15-year period.
Improved reservoir performance, drilling efficiencies, and other improvements have reduced the well count by 100 wells from the original Phase 1 plan, BP notes.
Statoil hands over Maersk Gallant rig to Total
Statoil ASA has elected to cancel its contract for the Maersk Gallant jack up rig, which is now under a new contract with Total E&P Norge AS spanning from Feb. 14 to Aug. 21.
Total will pay a cancellation fee according to the former contract. Statoil's contract for the rig dated back to August 2014. Since last October, the rig has been subchartered to ConocoPhillips.
The Maersk Gallant contract is the latest of several to be terminated by the Norwegian firm.
Since last summer, it has terminated contracts with Transocean Ltd. for the Discoverer Americas ultradeepwater drillship (OGJ Online, Dec. 17, 2015); Songa Offshore for the Songa Trym semisubmersible drilling rig (OGJ Online, Nov. 2, 2015); and COSL Drilling Europe AS for the COSL Pioneer drilling rig (OGJ Online, June 24, 2015).
PROCESSING — Quick Takes
EPA sued over latest renewable fuel quotas under RFS
The American Petroleum Institute has sued the US Environmental Protection Agency in a challenge of the agency's most recent biofuel requirements under the federal Renewable Fuel Standard.
Its Feb. 11 action in US Appeals Court for the District of Columbia Circuit came a day after the American Fuel & Petrochemical Manufacturers filed a petition for review with the court over the same requirements.
API said its lawsuit specifically challenges the agency's failure to meet deadlines for the 2014 to 2017 biomass-based diesel standards and for mandating more cellulosic ethanol in 2016 than even exists.
"We will continue to shine a light on this outdated and broken mandate and the need for positive change for the American consumer," API Downstream Group Director Frank Macchiarola said.
"EPA's 2016 mandated ethanol volumes push more ethanol into our fuel supply than is safe for the vast majority of cars on the road," Macchiarola said. "This action could harm consumers who could face higher fuel costs and damaged engines as a result."
AFPM Pres. Chet Thompson said on Feb. 10 that certain aspects of the final RFS rule still run afoul of the Clean Air Act despite the agency's best efforts.
"Among other things, EPA failed to provide obligated parties with requisite lead time and used flawed methodologies in establishing volume requirements," Thompson said. "This rule further confirms that the RFS program is dysfunctional and that the only real solution is full repeal by Congress."
Shell advances AO capacity expansion at Geismar plant
Royal Dutch Shell PLC subsidiary Shell Chemical LP has started construction on a $717-million project to increase alpha olefins (AO) production at its Geismar, La., chemical manufacturing plant, which post-expansion, will become the largest AO production site in the world.
Shell Chemical and general construction contractor Turner Industries Group LLC, Baton Rouge, formally broke ground on the 3-year expansion project in a ceremony held on Feb. 16, the Louisiana Economic Development (LED) said.
The AO-4 expansion, which will add a fourth AO unit and boost the Geismar site's production capacity by 425,000 tonnes/year to an overall 1.3 million tpy, is scheduled to be commissioned in early 2018, LED reported.
Start of construction follows a late-2015 announcement by Shell that it had reached final investment decision to proceed with the project (OGJ Online, Nov. 30, 2015).
CHS commissions coker at Kansas refinery
US farmer-owned cooperative CHS Inc., Inver Grove Heights, Minn., has commissioned a delayed coking unit to replace a more than 60-year-old unit at its 85,000-b/d McPherson refinery in central Kansas.
A project planned and initially started by former refinery operator National Cooperative Refinery Association (NCRA) in March 2013 (OGJ Online, Mar. 12, 2013), the coker became operable on Feb. 5, CHS said on Feb. 17.
CHS did not disclose details regarding the unit's capacity, but the coker-which replaces an 18,800-b/sd (16,920-b/cd) unit built in 1952-was to have a capacity of 25,000 b/sd (22,500 b/cd) beginning in 2016, according to US Energy Information Administration statistics.
Startup of the coking unit will enable the McPherson refinery to cut costs while meeting increased product demand by enabling greater flexibility to process a wider slate of less expensive, heavier crudes into more valuable finished products such as gasoline and diesel, as well as petroleum coke for industrial applications, the company said.
Safety features of the unit include a fully automated decoking control system that will allow operators, from a protected area away from the coker, to drill out and remove coke from unit drums, CHS said.
Originally planned as an investment of $555 million, the McPherson multiyear coker replacement project likely will have a final cost of $579 million, CHS told investors in its annual report for fiscal year 2015.
A $330-million project is designed to boost crude processing capacity at the McPherson refinery to 100,000 b/d (OGJ Online, Sept. 2, 2015) also remains on schedule to be completed this year, the company said.
TRANSPORTATION — Quick Takes
Williams Partners inks deals for Gulf Coast LNG facilities
Williams Partners LP, Tulsa, reported it has executed long-term contracts with two shippers for Gulf Connector, a 475,000-dekatherm/day expansion of the Transco pipeline system to connect US natural gas supplies with global LNG markets.
Gulf Connector will deliver gas for Cheniere Energy Inc.'s Corpus Christi, Tex., liquefaction project and a shipper in Freeport LNG Development LP's liquefaction project near Freeport, Tex. Both of these facilities are currently under construction.
The Gulf Connector project involves adding compression and making the gas flow bidirectional on a portion of the Transco system between Louisiana and South Texas. It's designed to provide incremental firm transportation from Transco's Station 65 in St. Helena Parish, La., to mainline interconnects with proposed header pipelines in Wharton County, Tex., and San Patricio County, Tex.
Williams Partners also is building the Gulf Trace Project to serve Cheniere's Sabine Pass Liquefaction project in Cameron Parish the first large-scale LNG export facility in operation in the continental US (OGJ Online, Apr. 25, 2014). The first shipment of LNG from that facility is expected late February or March and the Gulf Trace Project is expected to be completed in early 2017.
Cheniere's Corpus Christi export terminal is proposed to have as many as five liquefaction trains two of which are under construction with expected aggregate nominal production capacity of up to 22.5 million tonnes/year of LNG. Train 1 and 2 are expected to become operational in late 2018 and mid-2019, respectively.
The Freeport LNG export terminal will have three liquefaction trains with expected aggregate export capacity of 15.3 million typ. The Freeport export facility is also planned to commence operations in phases between September 2018 and August 2019.
Transco is a wholly owned unit of Williams Partners.
