OGJ Newsletter

Jan. 1, 2018
International news for oil and gas professionals


WBG to stop upstream oil, gas financing after 2019

The World Bank Group (WBG) reported it plans to stop financing upstream oil and gas projects in developing countries to help implement the 2016 Paris climate agreement’s goals. Exceptions will be considered where there is a clear energy access benefit for the poor and the project fits within the countries’ Paris agreement commitments, it said on Dec. 12 during the One Planet Summit in Paris.

Current projects in its portfolio will continue as planned, WBG said. “For those countries with oil and gas resources, commercial financing is often readily available for exploration and production,” it said. “In exceptional circumstances in the poorest countries where there is a benefit to energy access, the World Bank Group will consider upstream natural gas projects.”

Support and financing will continue for midstream and downstream gas investments for transportation and distribution to end-users and for electric power generation, the WBG said. “In some countries, gas still plays an important role during the energy transition,” it noted.

“Gas has the lowest carbon dioxide emissions of any fossil fuel. We support natural gas as a flexible energy source that can help countries make the transition more quickly to renewables, expand access to energy for the poor, and displace carbon-intensive coal,” WBG said.

Groups sue to force BLM to implement methane rule

Seventeen environmental organizations have sued in US District Court for Northern California to compel the US Bureau of Land Management to implement its oil and gas 2016 methane venting and flaring rule. Their Dec. 19 action challenges BLM’s decision earlier in December to delay most of the regulation’s compliance deadlines until Jan. 29, 2019, while the agency reviews it further (OGJ Online, Dec. 8, 2017).

“Interior’s BLM methane waste rule delay flies in the face of overwhelming public support, Congress’s recent rejection of an attempt to repeal the rule, a federal court’s determination that an injunction halting implementation of the rule was not warranted, and—fundamentally—core precepts of federal law,” said Erik Schlenker-Goodrich, executive director of the Western Environmental Law Center in Eugene, Ore.

Groups participating in the lawsuit included the Sierra Club, Center for Biological Diversity, Environmental Defense Fund, San Juan Citizens Alliance, and Wyoming Outdoor Council.

Officially known as the Methane Waste and Prevention Rule, the Independent Petroleum Association of America and Western Energy Alliance, along with the states of Wyoming, North Dakota, and Montana, legally challenged it in federal court soon after the rule became final on Nov. 18, 2016. The case now is pending in US District Court for Wyoming.

BLM reviewed the 2016 final rule as part of Sec. of the Interior Ryan Zinke’s Secretarial Order No. 3349, American Energy Independence, issued on Mar. 29. The agency found that immediately implementing some parts of the 2016 final rule could unnecessarily burden industry as BLM considers which parts of that rule might change.

Russia, Iran boosting energy cooperation

Officials of state-owned Gazprom have signed agreements with counterparts at several Iranian entities envisioning cooperation in a range of operations.

Alexey Miller, chairman of the Gazprom management committee, and Ali Kardor, Iran’s deputy minister of petroleum and chief executive officer of National Iranian Oil Co., signed a “roadmap” under which Gazprom “will conduct a proof-of concept study with regard to implementing integrated projects for hydrocarbon production, transmission, and processing, including petrochemistry, in Iranian territory.”

Miller, Kardor, and Nasrat Rahimi, chairman of the board of Oil Industry, Pension, Saving & Staff Welfare Fund, signed a memorandum of understanding to explore joint work on a planned LNG project in Iran.

Gazprom and Industrial Development & Renovation Organization of Iran, a state-owned subisidary of the Ministry of Industry, Mine & Trade, signed an MOU for joint gas liquefaction projects in third countries and for collaboration on advanced gas processing and petrochemical work in Iran.

And Gazprom and NIOC signed MOUs covering:

• Hydrocarbon exploration and production in Iran.

• Collaboration in construction of the planned Iran-Pakistan-India gas pipeline.

• Development of a concept for a unified system of gas production, transmission, and petrochemicals in Iran.

Exploration & DevelopmentQuick Takes

Lebanon approves offshore awards for two blocks

Lebanon’s Cabinet has approved the recently awarded licenses for Blocks 4 and 9 that lie in northern and southern areas offshore (OGJ Online, Oct. 23, 2017). Energy Minister Cesar Abi Khalil was quoted in The Daily Star saying drilling could begin as early as 2019.

Three companies are included in the consortium exploring both blocks: Total SA, Eni SPA, and OAO Novatek. Lebanon’s offshore is prospective for oil and gas, but the future of its development remains unknown (OGJ Online, July 7, 2017). Despite the announcement, the energy ministry has not released technical details of contracts nor has it disclosed the amount of the bids.

Eni picks up Tarfaya acreage offshore Morocco

Eni SPA has expanded its existing position in Morocco by entering a petroleum agreement with Moroccan state-owned Office National des Hydrocarbures et des Mines (ONHYM) in the Tarfaya offshore shallow-water exploration permits I-XII. The 23,900-sq-km area is offshore Sidi Ifni, Tan Tan, and Tarfaya in as much as 1,000 m of water.

Eni operates Moroccan interests in the Rabat Deep Offshore license, with 40% interest, as well as the El Jadida Offshore license. The operator maintains 75% working interest in El Jadida and the Tarfaya acquisition. Rabat Deep partners include Woodside 25% and Chariot Oil & Gas Ltd. 10%. ONHYM maintains a 25% share in all three projects.

In September, Eni signed a contract for the deepwater drillship Saipem 12000 to drill the RD-1 exploration well in Morocco’s Rabat Deep offshore permit (OGJ Online, Sept. 11, 2017).

Energean adds five Israeli blocks near Karish, Tanin

Energean Oil & Gas and its subsidiaries have increased to 13 the total number of licenses held in the East Mediterranean. The Israeli Petroleum Commissioner has awarded the operator Blocks 12, 21, 22, 23, and 31 offshore Israel, which were published in the country’s first round.

The blocks are in the immediate vicinity of Energean’s Karish and Tanin developments (OGJ Online, Jun. 20, 2017). Each license comes with a 3-year exploration period, and Energean said potential economic discoveries will most likely be developed as tie-backs to the floating production, storage, and offloading unit that will be installed 90 km offshore. The FPSO will have capacity of 400 MMcfd of gas. Energean expects to start production from Karish in 2020 after spending $1.3-1.5 billion on the development.

France enacts ban on oil, gas licensing

The French legislature has passed the ban on oil and gas exploration and production announced earlier this year (OGJ Online, June 26, 2017).

The law aims at halting production in France and its overseas territories by 2040. France produces about 15,000 b/d.

The government will not renew existing licenses or issue new licenses for exploration.

Drilling & ProductionQuick Takes

Repsol to revive production at North Sea Yme field

Repsol SA expects to recover 65 million bbl of oil stranded at currently shut-in Yme field in the Norwegian North Sea. The operator on Dec. 19 submitted a new plan for development and operation (PDO) for the field that will use existing facilities installed during the last development phase in 2007. The operator has leased the Maersk Inspirer jack up, which will be modified for Yme operations, acting as a drilling and production facility.

The PDO calls for reusing nine existing wells with a plan to drill six more. Startup is planned for 2020, according to the Norwegian Petroleum Directorate.

The field will produce from horizontal wells with pressure support from water injection and water-alternating-gas injection. All produced water and natural gas will be reinjected into the reservoir. Yme’s existing facilities include a caisson, a subsea oil storage tank, pipelines, and a connection between the Gamma and Beta platforms. Beta includes a manifold and subsea template with three slots, subsea loading system for oil from the storage tanks, and both platforms have existing wells.

Yme was in production from 1996 to 2001, after which the field was shut down and the facilities removed due to decreasing profitability of the field. A new PDO for Yme was approved in 2007 (OGJ Online, May 14, 2007).

Yme was originally developed with a jack up production facility and a storage vessel for one of the structures, Gamma. The other structure, Beta, was developed with subsea wells.

Due to structural faults, the Beta facility could not be used and it was removed in 2016 without initiating production on the field (OGJ Online, Aug. 24, 2016).

Repsol became operator after its 2015 acquisition of Talisman Energy Inc. Current partners include Repsol Norge AS, 55% working interest; Lotos Exploration & Production Norge AS, 20%; Kufpec Norway AS, 10%; and OKEA AS, 15%.

Eni brings Zohr on stream offshore Egypt

Eni SPA has brought Zohr, a giant Mediterranean Sea gas field, on stream on Shorouk block offshore Egypt. Production started less than 3 years after discovery, and Eni estimates Zohr has resources of more than 30 tcf (about 5.5 billion boe).

Previously Eni has said it expects production will reach about 75 million standard cu m/day of gas by 2019. The field lies in 1,500 m of water.

Claudio Descalzi, Eni chief executive officer, said Zohr will allow Egypt “to turn from an importer of natural gas into a future exporter.” Eni has 60% interest. Partners are Rosneft with 30% interest and BP PCL with 10% interest.

Eni is co-operator of Zohr through Petrobel, jointly held by Eni and the state Egyptian General Petroleum Corp. (EGPC), on behalf of Petroshorouk, jointly held by Eni and the Egyptian Natural Gas Holding Co. (Egas).

Zohr’s development was put on a fast track. Eni previously amended the project scope to add more onshore processing and pipeline capacities to accommodate its start-up timeline.

The accelerated 1-bcfd start-up phase involved production from subsea wells connecting via a gas pipeline to the onshore plant at Port Said (OGJ Online, Feb. 22, 2016).

The project’s second phase, or the accelerated ramp-up-to-plateau, will add more wells to bring the total to 20 wells, boosting production to 2.7 bcfd by yearend 2019.

Second-phase plans include another gas line as well as an additional onshore processing plant, Eni previously said.

The two gas processing plants will each host four processing trains of 350 MMcfd each.

An Italian operator, Eni reported its third-quarter production averaged 1.8 million boe/d, up about 5% from the same period last year. Executives anticipate four-quarter production to reach an average 1.9 million boe/d, which would be Eni’s highest output in 7 years.

Eni has worked in Egypt since 1954, where it operates through its subsidiary IEOC Production BV.

Reggane Nord gas starts flowing in Algeria

Repsol and Sonatrach have started production from four of six natural gas fields in the Reggane Nord complex in the Sahara Desert of southwestern Algeria.

The companies share operatorship of the complex. Production is to reach 280 MMcfd of dry gas in January.

The project encompasses Azrafil Sud-Est, Kahlouche, Kahlouche Sud, Tiouliline, Sali, and Reggane gas fields. Repsol expects production to extend at least to 2041.

The operators and their partners have drilled five exploration and delineation wells and 18 development wells. Initial production is from 10 wells. Further drilling is planned.

The project’s central processing facilities include a gas treatment plant, a gathering network, and a 74-km pipeline connecting the treatment plant to a new transmission line.

Interests are Sonatrach, 40%; Repsol, 29.25%; DEA Deutsche Erdoel AG, 19.5%; and Edison, 11.25%.


Iraq’s Kirkuk refinery completes capacity expansion

North Refineries Co. (NRC), a subsidiary of Iraq’s Ministry of Oil, has commissioned a 13,000-b/d crude distillation unit (CDU) at its refinery in Kirkuk, lifting overall processing capacity at the site to more than 50,000 b/d.

The unit, which entered operation in mid-December, follows commissioning of another 10,000-b/d CDU earlier in the year, the ministry said in a release.

With startup of the two units now completed, the refinery is operating at a capacity of 56,000 b/d, the ministry said.

The new CDUs join the refinery’s original three CDUs, each of which have a crude processing capacity of 10,000 b/d.

Upon announcing startup of the refinery’s fourth CDU in March, NRC only planned the recently commissioned fifth CDU to have a processing capacity of 10,000 b/d, the ministry said in a Mar. 8 release.

The ministry did not disclose details regarding a source of the additional 3,000 b/d capacity to account for the discrepancy between the expanded refinery’s apparent 53,000-b/d nameplate and 56,000-b/d operating capacities.

The largest of Iraq’s state-owned refiners, NRC also completed rehabilitation and restart of its 14,000-b/d Qalarah, 16,000-b/d Haditha, and 30,000-b/d Sainia refineries earlier this year, the ministry said.

Despite financial hardship as the country continues to rebuild, develop, and further expand its oil and gas industry, Iraq has announced a host of proposed downstream expansions and greenfield projects during the past year, according to a series of ministry releases.

Including the 140,000-b/d refinery in southern Karbala Province already under construction, these projects are part of Iraq’s longer-term plan to construct four refineries to add 750,000 b/d of refining capacity. The additional planned projects include a 300,000-b/d Nassiriya refinery as well as refineries in Maysan and Kirkuk (OGJ Online, June 25, 2015).

Alberta bitumen refinery begins diesel production

North West Redwater Partnership (NWRP) has started diesel production at the first phase of its long-planned greenfield bitumen refinery still under construction in Sturgeon County, about 45 km northeast of Edmonton, Alta. (OGJ Online, Jan. 28, 2010).

Operator North West Refining Inc. (NWR) began producing diesel from Canadian Synthetic crude oil feedstock at the refinery on Dec. 12, marking a major milestone on the way to full commercial operation in 2018 of its 79,000-b/d Phase 1 development, NWRP said.

Start of diesel production comes amid commissioning of several units at the site as part of a series of performance measures that must be met before Phase 1 of the refinery reaches full operations.

Construction in other areas of the project—which was more than 95% completed as of late August—remains ongoing, NWRP said.

Once fully commissioned, the Sturgeon refinery will process 240,000 b/d of Canadian bitumen feedstock to produce ultralow-sulfur diesel, diluent, and other bitumen products for both domestic and global markets, according to NWR’s web site.

The refinery originally was to include three 50,000-b/d phases for a total processing capacity of 150,000-b/d (OGJ Online, Nov. 16, 2016).

Neither NWRP nor NWR responded to requests for clarification regarding the apparent update to proposed processing capacities of the refinery’s three phases.

NWRP is a joint venture of NWR (formerly North West Upgrading Inc.), Calgary. Canadian Natural Upgrading Ltd., a wholly owned subsidiary of Canadian Natural Resources Ltd., is also of Calgary.

Hanwha Total’s Daesan complex due PE expansion

Hanwha Total Petrochemicals Co. Ltd. (HTPCL), a 50-50 joint venture of Hanwha Group, Seoul, and Total SA, Paris, will invest more than $300 million to expand the polyethylene (PE) capacity of its Daesan refining and petrochemicals integrated complex in Chungnam Province, South Korea, about 145 km from Seoul.

The proposed project will increase PE capacity at the site by more than 50% to 1.1 million tonnes/year by yearend 2019, Total said.

The expansion will use proprietary Advanced Double Loop technology jointly licensed by Total and Chevron Phillips Chemical Co. to produce a wide range of high-end specialty PEs to supply South Korean demand as well as the fast-growing Chinese market, the operator said.

The project complements the planned $450-million expansion of the Daesan complex’s steam cracker, which alongside increasing ethylene production capacity by 30% to 1.4 million tpy also will increase the complex’s feedstock flexibility, enabling it to process competitively priced and abundantly available propane supplies resulting from rising US shale gas production (OGJ Online, Apr. 12, 2017).

The steam cracker and polymer expansion projects together will allow the integrated manufacturing site to capture margins across the full value chain, said Bernard Pinatel, Total’s president of refining and chemicals division.

The ethylene expansion project at Daesan is scheduled to be completed in mid-2019, Total previously said.

Total and Hanwha formed HTPCL following Hanwha’s 2015 purchase of Samsung Group’s petrochemicals business, which included Samsung’s 50% interest in the Daesan complex under the former Samsung Total Petrochemicals Co. Ltd. joint venture, according to an Apr. 30, 2015, release from HTPCL.

In addition to its current output of 1 million tpy of ethylene, 1.77 million tpy of paraxylene, and 1.05 million tpy of styrene monomer, the Daesan complex produces polypropylene, PE, ethylene-vinyl acetate copolymer, as well as gasoline, diesel, jet fuel, LPG, fuel oil, and solvents.


Nebraska PSC denies Keystone XL petition

The Nebraska Public Service Commission unanimously denied TransCanada Corp.’s petition for reconsideration of the PSC’s earlier approval of a mainline alternative for the proposed Keystone XL crude oil pipeline through the Cornhusker State (OGJ Online, Nov. 20, 2017).

Opponents considered the Dec. 19 order a victory because it keeps TransCanada from filing an amended application for federal approval and forces it to submit a new one requiring fresh environmental reviews and setting the stage for more legal challenges.

“It’s absolutely the worst decision possible for TransCanada, and the best possible outcome for landowners and the protection of their property rights,” said Brian E. Jorde, a lawyer with DominaLaw Group LLC in Lincoln. “The PSC process is over now, and the appeal process of the PSC decision can begin and run all the way through the courts.”

In a statement, a TransCanada spokesman said the project’s sponsor was reviewing the ruling and considering the appropriate next steps in Nebraska.

“More importantly, Keystone XL remains a viable project with strong commercial support,” the spokesman said. “The project continues to have widespread support of the US and Canadian governments as well as state and provincial governments in Montana, South Dakota, Nebraska, Saskatchewan, and Alberta. President Trump and his administration continue to actively support Keystone XL and we expect to secure final federal permits in early 2018. We remain committed to the project,” he said.

ACE issues permit to Bayou Bridge Pipeline

The US Army Corps of Engineers’ New Orleans District issued a permit to Bayou Bridge Pipeline LLC to construct a 162-mile underground extension of an existing crude oil pipeline from Lake Charles, La., to the St. James marine terminal hub. The Dec. 14 decision followed completion of an environmental assessment, US Code Section 408 review, and consideration of all comments received during the public notice and comment period, officials said.

The $750-million project is an extension of an existing pipeline from Nederland, Tex., to Lake Charles, its sponsor said. About 88% of it will parallel existing systems including roads, power lines, and other pipelines across the Atchafalaya basin, it said.

When completed, the 24-in. pipeline will have a 480,000 b/d capacity to move crude from various sources to the St. James hub, which is home to several refineries. Bayou Bridge is a joint venture of Energy Transfer Partners LP, which holds 60% stake and is its operator, and Phillips 66 Partners LP. The new segment is scheduled to go into service during 2018’s first quarter.

ACE’s individual permit process required Bayou Bridge’s sponsor to provide a Louisiana-issued coastal use permit and water quality certification as well as proof that all compensatory wetland mitigation requirements have been satisfied before a final permit decision was rendered, the district office said. It required the applicant to avoid and minimize jurisdictional wetland impacts to the greatest extent practicable by reducing the proposed project’s footprint and pipeline right-of-way.

The pipeline will have a temporary impact on 455 acres of jurisdictional wetlands and include conversion of 142 acres of forested wetlands to permanent pipeline ROW, requiring the purchase of 708 acres of mitigation from ACE-approved wetland mitigation banks in the affected watershed. The combination of avoidance, minimization, and mitigation will result in zero net loss of jurisdictional wetlands, the ACE office said