OGJ Newsletter

Nov. 3, 2014
International news for oil and gas professionals

GENERAL INTERESTQuick Takes

Global production outages may be strategic warnings

Overseas crude oil production and transportation interruptions could be strategic warnings that are too important to ignore, a US Senate Energy and Natural Resources Committee minority staff report suggested.

Supply interruptions, which rose steadily in Iraq before ISIS seized Mosul in June, are occurring in many other countries, the report said. Such unplanned oil production outages are not due solely to violence and instability, and can reflect natural disasters, production problems, and more benign causes, the Oct. 27 report conceded.

"But in many cases, unplanned outages reflect growing, or at least ongoing, turmoil," it added.

Outages in Iraq, Yemen, Libya, and South Sudan, and ongoing challenges in Nigeria and Colombia reflect rising or persistent violence, the report said. Iran and Syria are special cases where interruptions illustrate international sanctions' knock-on effects, it indicated.

The analytical utility of such outages lies not in prediction, but in providing strategic warnings, the report emphasized. Their impact on global petroleum markets depends largely on their scale and duration, it said.

"Sustained levels of such outages in other countries may constitute a degree of strategic warning to policymakers that attention is required, and ultimately are a reminder that record-breaking increases in North American oil production can enhance national security and stabilize global markets," it concluded.

Williams Partners, Access Midstream Partners to merge

Williams Partners LP and Access Midstream Partners LP, both owned by Williams Cos., Tulsa, have agreed to merge. Williams in June purchased the remaining 50% general partner interest that it didn't previously hold in Access Midstream, giving way to the merger proposal (OGJ Online, June 16, 2014).

Williams Partners will become wholly owned by Access Midstream. The merged MLP will be named Williams Partners LP and will be based in Tulsa with major offices in Oklahoma City, Houston, Pittsburgh, Salt Lake City, and Calgary.

The merged MLP's assets will include the Transco, Northwest, and Gulfstream natural gas interstate pipeline network; large-scale positions in natural-gas supply areas in the Marcellus, Utica, Piceance, Four Corners, Wyoming, Eagle Ford, Haynesville, Barnett, Midcontinent, and Niobrara; and oil and natural gas gathering services in the deepwater Gulf of Mexico.

The MLP also will own downstream assets residing on the Gulf Coast and in western Canada. Williams plans to complete the drop-down of its remaining NGL and petrochemical services assets and projects by yearend or early next year. The company expects to have invested $600 million in the drop-down assets by yearend.

Following the closing of the merger, J. Mike Stice is expected to continue in the role as a director of the general partner of the merged MLP. Stice, who currently serves as chief executive officer of the general partner of Access Midstream, will retire as an officer of the company upon the closing of the merger.

Robert S. Purgason, current chief operating officer of the general partner of Access Midstream, is expected to join Williams as senior vice-president overseeing Access Midstream operations. Purgason will report directly to Alan Armstrong, Williams' president and chief executive officer.

Purgason also will serve the merged MLP as one of its general partner's senior vice-presidents rather than as its chief operating officer. Alan Armstrong is expected to serve as the merged MLP's general partner's chief executive officer.

PGNiG picks up interest in four fields on NCS

PGNiG Upstream International, the Norway-focused subsidiary of Polish Oil & Gas Co., has agreed to acquire 8% interest in Gina Krog field, 24.243% in Vilje field, 24.243% in Vale field, and 6% in Morvin field on the Norwegian continental shelf from Total E&P Norge AS, a wholly owned subsidiary of Total SA, for $317 million. The deal is effective Jan. 1.

Gina Krog was sanctioned in 2013 and is under development in the North Sea, with an expected production start-up in early 2017. The project will produce 60,000 b/d of oil and 9 million cu m/day of gas. Total E&P Norge AS will retain 30% interest in Gina Krog. Statoil ASA holds 58.7% and DNO holds 3.3%.

Patrice de Vivies, Total senior vice-president, Northern Europe E&P said, "With the Ekofisk South, Eldfisk II, Martin Linge and Gina Krog developments, Total's production in Norway is set to grow between 2014 and 2017."

Mariusz Zawisza, PGNiG chief executive, commented, "Involvement in four new fields in Norway has a special meaning for us. Firstly, it means immediate increase in production outside the country by about 60%. Second, the transaction will allow us to maintain an increased level of oil production for at least 10 years."

PGNiG says an independent auditor estimates the acquired interest's recoverable reserves at 33 million boe, of which 72% is oil and 28% is gas, representing a 60% increase in current resources for PGNiG in Norway.

PGNiG entered Norway in 2007 with the purchase of shares from ExxonMobil Corp. in Skarv field, where production launched at the end of 2012. PGNiG Upstream International has 12 licenses on the NCS, and says it plans to apply for more licenses during future licensing rounds.

Exploration & DevelopmentQuick Takes

Hess to develop deepwater gulf oil field

Production is to begin in 2018 from deepwater Stampede oil field in the Gulf of Mexico under a development plan approved by operator Hess Corp. and partners.

The project will involve subsea completions tied back to a new tension-leg platform.

Hess initially plans to drill six production wells and four water-injection wells through two subsea drill centers in 3,500 ft of water. The Miocene sandstone reservoir occurs at about 30,000 ft.

The first rig in a two-rig program is to begin work in fourth-quarter 2015.

Gross topsides processing capacities are 80,000 b/d of oil and 100,000 b/d of water for injection.

Hess expects the development to cost $6 billion. It estimates recoverable resources at 300-350 million boe.

Stampede field is 115 miles south of Fourchon, La., on Green Canyon Blocks 468, 511, and 512.

The field combines two discoveries, Pony by Hess in 2006 on Block 468 and Knotty Head by Nexen Inc. in 2005 on Block 512. A late-2012 exchange agreement combined the interests.

Hess, Nexen, Chevron Corp. subsidiary Union Oil Co. of California, and Statoil hold 25% interests each.

Repsol makes oil discovery in ultradeepwater gulf

Spain's Repsol reported an ultradeepwater oil discovery on Keathley Canyon Block 642 in the Gulf of Mexico.

The company said the Leon well found net pay of 150 m within a 400-m column. The well reached total depth of 9,684 m in 1,865 m of water. It is 352 km offshore Louisiana.

Repsol has 60% and Colombia's Ecopetrol has 40%.

"With the Leon discovery, Repsol continues to strengthen its position in the United States, which is one of the company's key strategic areas," the company said.

The discovery is 50 km northwest of Repsol's 2009 Buckskin discovery (OGJ Online, Feb. 6, 2009).

Eni finds gas near Jangkrik offshore Indonesia

Eni SPA has discovered natural gas in its first well on the East Sepinggan Block offshore East Kalimantan, Indonesia, 35 km from where it is developing Jangkrik gas field (OGJ Online, June 12, 2014).

Eni holds 100% interest in the block, 170 km south of the Bontang LNG plant.

The Merakes 1 discovery well, drilled to 2,640 m TD in 1,372 m of water, cut 60 m of hydrocarbon pay in high-quality sandstones.

Eni estimated gas in place in the Lower Pliocene clastic sequence at 1.3 tcf.

Drilling & ProductionQuick Takes

Chevron begins gas production from Bibiyana

The Bangladesh subsidiary of Chevron Corp. has started natural gas production from the Bibiyana expansion project in the northeastern part of the country.

The project included an expansion of the existing gas plant to process increased natural gas volumes from Bibiyana field, additional development wells, and an enhanced gas liquids recovery unit (OGJ Online, July 30, 2012).

The project is expected to boost Chevron-operated natural gas production capacity in Bangladesh by more than 300 MMcfd to 1.4 bcfd. The project also is expected to increase the company-operated NGL production capacity by 4,000 b/d to 9,000 b/d.

Chevron's Bangladesh subsidiary holds 99% working interest in Bibiyana. The company first launched production from the field in 2007 (OGJ Online, Mar. 21, 2007).

ConocoPhillips plans ANS drill site in Kuparuk field

ConocoPhillips has disclosed plans for a drill site on Kuparuk oil field on Alaska's North Slope, representing the first new drill site on that location in more than a decade. Peak production is expected to reach 8,000 b/d of oil.

The decision follows last year's passage of Senate Bill 21, which prompted ConocoPhillips and BP PLC to immediately launch $1 billion in programs along with the intent to evaluate up to $3 billion of projects in the Greater Prudhoe Bay area (OGJ Online, Nov. 4, 2013). ConocoPhillips moved a second rig to Kuparuk in January (OGJ Online, Jan. 31, 2014).

Funding for Kuparuk field expansion project Drill Site 2S (DS2S) has been sanctioned by ConocoPhillips and Kuparuk co-owners BP Exploration, ExxonMobil Corp., and Chevron Corp.

Tengizchevroil lets contract for Kazakh expansion

Tengizchevroil (TCO), a joint venture of Chevron Corp., ExxonMobil Corp., KazMunayGas, and LukArco, has let an engineering, procurement, and construction contract to Bechtel to build four crude-oil storage tanks at the TengizChevroil oil production facility in Tengiz, Kazakhstan. Bechtel also will modernize the fire and gas detection systems across the entire crude tank farm.

The project will add to the existing facility 500,000 bbl of tank storage, export pumps, interconnecting pipe, switching manifolds, a monitoring station, associated facilities, and supporting infrastructure.

TCO in 2012 began front-end engineering and design on a 250,000-300,000 b/d expansion of oil production capacity from Tengiz field (OGJ Online, Feb. 15, 2012).

Chevron earlier this year reported its net production is expected to increase to 3.1 million boe/d in 2017 from 2.6 million boe/d in 2013 due in part to expansion of the TCO consortium (OGJ Online, Mar. 13, 2014).

Contract let for deepwater development off Nova Scotia

The government of Nova Scotia has let a contract to Petrofac for a development study on a prospective offshore oil reservoir lying 3,000 m beneath the seabed in 2,000 m of water. The project will be led by Petrofac's subsea engineering business K W Subsea.

Teams from within Petrofac's engineering and consulting services business will provide support for the project, including process design, naval architecture, subsea engineering, and cost estimating, as well as a specific drilling scope. The project is expected to be completed early next year.

Blocks have been awarded to Royal Dutch Shell PLC and BP PLC, which together have exploration commitments of more than $2 billion (OGJ Online, May 6, 2014). Deepwater drilling is scheduled to begin in 2015 with the start of production estimated after 2025.

Nova Scotia estimates its offshore potential at 120 tcf of natural gas and 8 billion bbl of oil. The area has been compared with offshore northwest Africa because of the water depths.

PROCESSINGQuick Takes

Sasol takes FID on Louisiana petrochemical complex

Sasol Ltd. has reached a final investment decision (FID) for its proposed integrated ethane cracker and downstream derivatives complex to built adjacent to the company's existing operations in Westlake, La. (OGJ Online, May 1, 2014).

In addition to a grassroots ethane cracker capable of producing 1.5 million tonnes/year of ethylene, the $8.1 billion complex will include six chemical manufacturing plants, Sasol said.

Another $800 million will be invested in infrastructure and utility improvements, as well as in land acquisition, the company said.

With site preparation now under way, the new complex currently is on schedule to be commissioned in 2018, Sasol said.

Once commissioned, the petrochemicals complex roughly will triple Sasol's US chemical production capacity to further strengthen the company's competitive position in a growing global chemicals market, according to David Constable, Sasol's president and chief executive.

"The US Gulf Coast's robust infrastructure for transporting and storing abundant, low-cost ethane was a key driver in our decision to invest in America," said Constable.

About 90% of ethylene output from the new cracker will be converted into a diverse slate of commodity and high-margin specialty chemicals for global markets in which Sasol already holds strong positions, the company said.

Sasol also confirmed it has let a contract to a joint venture of Fluor Corp. and Technip for engineering, procurement, and construction management (EPCM) on the project.

Under the contract, which covers EPCM for the ethane cracker, downstream derivatives units, associated utilities, offsites, and infrastructure work, the Fluor Corp.-Technip venture also will provide start-up, commissioning, and performance testing support to Sasol, Fluor and Technip said in separate releases on Oct. 27.

A value of the EPCM contract was not disclosed.

Sasol previously awarded both Fluor and Technip contracts to provide various front-end engineering and design services for the complex, which when completed will represent the largest single manufacturing investment in Louisiana's history (OGJ Online, Oct. 16, 2013; July 15, 2013).

In May, Sasol Ltd.-owned Sasol Chemicals (USA) LLC let a contract to Boardwalk Pipeline Partners LP subsidiary Boardwalk Louisiana Midstream LLC to provide long-term ethane and ethylene storage and transportation services to support the proposed integrated Westlake complex (OGJ Online, May 1, 2014).

Williams advances Geismar olefins plant restart

Williams Partners LP said it plans to resume ethylene production as soon as next month at its rebuilt and expanded Geismar, La., olefins plant following a series of delays after a 2013 explosion at the site (OGJ Online, June 13, 2013).

All major construction related to the plant's rebuild, expansion, and safety-related upgrades has been completed, and the plant is scheduled to begin manufacturing ethylene for sale in November, Williams Partners said.

General contractors for the expansion and rebuild projects have demobilized, and Williams Partners' operations personnel currently are directing the dry-out the plant, which has entered the final stages of commissioning and start-up, the company said.

The 600 million-lb/year Geismar expansion project has the plant's ethylene production capacity to 1.95 billion lb/year from 1.35 billion lb/year, with Williams Partners' share of the total capacity amounting to about 1.7 billion lb/year.

While the company previously had revised the plant's restart date to September with plans to begin first ethylene sales in October, commissioning was delayed following a decision to install $20 million in safety-related equipment and to provide additional contingency associated with the start-up process (OGJ Online, Aug. 5, 2014).

The company's rebuild and expansion work at Geismar follows a June 2013 explosion that originated in the area of the plant's propylene fractionator, killing two workers (OGJ Online, June 25, 2013).

Following the June incident, Williams Partners proceeded with repair and expansion work at Geismar for an initially planned restart in April (OGJ Online, Dec. 12, 2013).

Contract let for Canadian bitumen refinery

North West Redwater Partnership (NWR) has let a contract to Jacobs Engineering Group Inc. for additional work at NWR's greenfield bitumen refinery project in Sturgeon County, about 45 km northeast of Edmonton, Alta. (OGJ Online, Jan. 28, 2010).

Under the latest contract, Jacobs will deliver construction management services for the Sturgeon refinery, Jacobs said.

A value of the contract was not disclosed.

NWR previously let a contract to Jacobs for engineering and procurement services for the refinery's utilities requirements, which is a fundamental component of Phase 1 of the project (OGJ Online, Mar. 11, 2014).

Once completed, Phase 1 of the $8.5-billion project will have a processing capacity 50,000 b/d and will capture 1.2 million tonnes/year of carbon dioxide to be sold for use in enhanced oil recovery. Two further phases with capacities of 50,000 b/d each also are planned for the refinery.

Following commissioning of all three phases, the Sturgeon refinery will operate at a capacity of 150,000 b/d to produce diesel, diluent, and other bitumen products for both Canadian and global markets.

NWR, a joint venture of North West Upgrading Inc. and Canadian Natural Upgrading Ltd., a wholly owned subsidiary of Canadian Natural Resources Ltd., previously said it plans to commission commercial operations for Phase 1 in September 2017 (OGJ Online, Mar. 3, 2014).

TRANSPORTATIONQuick Takes

Energy Transfer, Phillips 66 in pipeline JVs

Energy Transfer Equity LP, Energy Transfer Partners LP, and Phillips 66 have formed joint ventures to develop two crude oil pipelines that together will connect the Bakken/Three Forks play in North Dakota with the US Gulf Coast.

The Energy Transfer entities will hold 75% interests in each of the projects. Phillips 66 will own the remaining 25% interests and fund its share of construction.

One of the projects, Dakota Access LLC, involves new pipeline linking North Dakota with the hub at Patoka, Ill. Energy Transfer said contractual commitments so far indicate delivery capacity of more than 450,000 b/d of crude to various points in the Midwest.

The other project, Energy Transfer Crude Oil Co. LLC, will carry crude from an interconnection with the Dakota Access pipeline at Patoka to Nederland, Tex.

Commercial operations are expected to begin in fourth-quarter 2016.

Energy Transfer Partners launched a binding open season covering the system in March and a binding expansion open season in September to assess interest in lifting planned Dakota Access capacity from the original 320,000 b/d (OGJ Online, Mar. 10, 2014).

NBP launches open season for Bakken Header lateral

Northern Border Pipeline Co. (NBP), Houston, launched a month-long nonbinding open season to gauge shipper interest in a pipeline project to transport natural gas from the Bakken area of North Dakota into the NBP system.

The proposed Bakken Header Supply Lateral project will consist of about 64 miles of 16-in. line, compression, and related facilities that would extend westward from near the outlet of Hess Corp.'s Tioga processing plant in northwestern North Dakota to where it will provide access to additional processing facilities.

At full capacity, the project will be capable of transporting as much as 295 MMcfd of gas, NBP said.

The open season will close on Nov. 26. The expected in service date of the project is early to mid-2017.

NBP is a general partnership owned by TC PipeLines LP and Oneok Partners LP. TransCanada Northern Border Inc. serves as NBP's operator.

TransCanada issued EAC for Coastal GasLink

TransCanada Corp. reported that the British Columbian Environmental Assessment Office has issued an environmental assessment certificate (EAC) for the Coastal GasLink pipeline project.

Shell Canada Ltd. in mid-2012 let a contract to TransCanada to design, build, own, and operate the proposed 670-km, 48-in. Coastal GasLink system, a $4 billion pipeline that will carry natural gas from the Montney gas-producing region near Dawson Creek, BC, to LNG Canada's proposed LNG export facility near Kitimat, BC (OGJ Online, June 5, 2012).

The initial build of Coastal GasLink will include as many as three meter stations and one compressor station. The initial capacity of the pipeline will allow the shipment of 2-3 bcfd of gas, with an expansion capability to about 5 bcfd through the addition of as many as seven compressor stations.

The EAC for the project contains 32 conditions, the majority of which reflect current best practices for gas pipeline construction and operation.

Next steps for the proposed project include detailed engineering and construction planning, as well as ongoing consultation with Aboriginal groups and the public.

Pending the receipt of all required regulatory approvals and a positive final investment decision from LNG Canada, the start of pipeline construction is expected in 2016, with an in-service date by the end of the decade.