OGJ Newsletter

Feb. 16, 2015
International news for oil and gas professionals

GENERAL INTERESTQuick Takes

Senators' bill aims to speed gathering line permit process

US Senators from North Dakota and Wyoming have introduced legislation that aims to capture methane and reduce flaring by expediting procedures for obtaining permits for natural gas gathering lines on federal and Indian lands.

The measure sponsored by John A. Barrasso (R-Wyo.), Heidi Heitkamp (D-ND), Michael B. Enzi (R-Wyo.), and John Hoeven (R-ND) would reduce flaring by making it easier to site gas gathering lines on federal and tribal acreage, its sponsors said.

Specifically, it would eliminate duplicative environmental reviews for gas gathering lines that are adjacent to or within an existing disturbed area or existing right-of-way corridor on federal and Indian land.

It also would require the US Interior Secretary to issue rights-of-way for gas gathering lines on federal land within 90 days unless the secretary finds the right-of-way would violate the Endangered Species Act or the National Historic Preservation Act.

The secretary also would be required to consult with states and tribes, and to report annually to Congress on progress made in expediting approval of permits and construction of gas gathering lines on federal and tribal land and identify obstacles impeding that progress.

"Rather than issuing more regulations, which will further drive oil and gas production off federal and Indian land, the [US] Department of the Interior should meet its current responsibilities," said Barrasso, who is an Energy and Natural Resources Committee member. "That includes issuing rights-of-way for natural gas gathering lines on federal and Indian land in a timely manner."

Heitkamp said, "Part of committing to an all-of-the-above energy strategy means staying mindful of commonsense solutions. We can do that by preventing our energy resources from getting unnecessarily bogged down by government red-tape."

PNR cuts capital spending nearly in half

Pioneer Natural Resources Co. (PNR), Dallas, plans to spend $1.85 billion in 2015 following a fourth quarter in which the company reported a net income of $431 million. The new budget represents a 45% reduction from 2014 capital spending for continuing operations, a change attributed to low oil prices (OGJ Online, Feb. 11, 2014).

Drilling activity and infrastructure build-out are the targets of the cuts, respectively receiving $1.6 billion and $250 million for water infrastructure, vertical integration, and facilities.

Infrastructure projects-including construction of the Spraberry-Wolfcamp area water system and expansion of the Brady sand mine-will be slowed down. Divestment of the Eagle Ford shale midstream business, meanwhile, continues to be pursued (OGJ Online, Nov. 4, 2014).

PNR says a 10% decrease in drilling costs has already been realized this year compared with last. That number is expected to rise to 20% by yearend.

PNR is reducing horizontal drilling activity in the Spraberry-Wolfcamp and Eagle Ford to 16 rigs by the end of February-a 50% reduction from yearend 2014-including six rigs in the northern Spraberry-Wolfcamp, four rigs in the southern Wolfcamp joint venture area, and six rigs in the Eagle Ford. Vertical drilling in the Spraberry-Wolfcamp will be shut down by the end of February.

The company notes, however, that it's prepared to add horizontal rigs later this year in response to reduced costs or an improvement in the oil price environment.

Production growth of 10% compared with 2014 from continuing operations for 2015 is forecasted based on capital budget and the high-graded drilling program. Growth is primarily weighted to the first half, with production in the fourth quarter expected to be essentially flat compared with fourth-quarter 2014.

Oil production is forecasted to increase 20% this year compared with last.

PACE survey finds wide support for crude oil exports

More than two thirds of registered voters responding in a nationwide telephone survey commissioned by Producers for American Crude Exports (PACE) supported allowing US producers to sell crude to customers in countries that have a trading agreement with the US.

The Feb. 2-5 poll of 1,025 voters by Washington, DC-based FTI Consulting found 69% favored such exports while 31% said the federal government should mandate that crude produced in the US be sold exclusively to US customers, PACE said as it released the survey on Feb. 10.

US crude exports were banned after the 1973 Arab Oil Embargo disrupted supplies. They presently are restricted to crude from beneath state waters in Alaska's Cook Inlet, Alaskan North Slope crude, certain US-produced crude destined for Canada, shipments to US territories, and California crude sold to customers in Pacific Rim countries, according to the US Energy Information Administration.

"There is a growing consensus of research from think tanks, universities, and government agencies that have studied this issue," PACE Executive Director George Baker said as the survey was released. "Each has determined that crude oil exports will grow the economy and provide broad-based consumer benefits."

He said, "This survey demonstrates that a significant majority of voters also believe the economy and consumers would benefit and America's strategic position in the world would be strengthened if US oil producers were permitted to sell crude oil to customers in countries [that] are trading partners."

Exploration & DevelopmentQuick Takes

Statoil well appraises discovery near Oseberg

The Norwegian Petroleum Directorate reported results from an appraisal well drilled in the North Sea by Statoil ASA, operator of production license 035.

Statoil drilled the well to delineate the 30/11-8 S discovery in 2011, about 25 km southwest of the Oseberg Sor field facility in the northern North Sea (OGJ Online, May 10, 2011).

Appraisal well 30/11-10 A was drilled north of the discovery well. The well encountered a total oil column of about 260 m in the Tarbert formation. Preliminary size is calculated at 8-13 million standard cu m of recoverable oil equivalent.

The Transocean Leader semisubmersible rig drilled to a vertical depth of 3,673 m below the sea surface, terminating in the Ness formation in the Middle Jurassic. Water depth is 105 m.

The well will be permanently plugged and abandoned. NPD said it was the ninth well related to exploration drilled in PL 035, which was awarded in the 2nd licensing round in 1969.

Beach, Drillsearch make gas find in Cooper basin

A joint venture of Beach Energy Ltd. and Drillsearch Energy Ltd. has made a wet gas discovery with its Ralgnal-1 wildcat well in retention lease 130 (formerly PEL 106) in South Australia's Cooper basin.

The well penetrated 6.6 m of net pay in the Permian-age Patchawarra formation and 3 m of pay in the underlying Tirrawarra sands.

Gas flowed to surface at 5.88 MMcfd during drillstem tests. Flow rates for condensate are still being evaluated.

The well will be cased and suspended as a discovery.

CNOOC inks S. China Sea PSCs with SK Innovation

China National Offshore Oil Corp. Ltd. signed two production-sharing contracts with SK Innovation Co. Ltd., Seoul, for two blocks in the Pearl River Mouth basin of the South China Sea.

The blocks lie in 50-100 m of water. Block 04/20 covers 5,138 sq km and Block 17/03 covers 7,686 sq km.

The companies will conduct 2D seismic surveys and drill exploration wells, they said.

Operator SK will cover 80% of the exploration costs. In a development phase, CNOOC has the right to as much as 60% working interest in any commercial discovery.

Drilling & ProductionQuick Takes

Fatalities confirmed after FPSO vessel explosion

As OGJ went to press last week, BW Offshore reported five fatalities-all BW Offshore employees-and four crew members missing following the Feb. 11 explosion onboard the Cidade de Sao Mateus floating production, storage, and offloading vessel, which was operating in Espirito Santos basin about 120 km offshore Brazil.

There were 74 people onboard the FPSO unit, operated by BW Offshore for Petroleo Brasileiro SA (Petrobras). Gas production from postsalt Camarupim and North Camarupim fields was halted immediately following the explosion. Search and rescue operations continued into the night.

BW Offshore said the remaining crew were all accounted for and received medical care where needed. Two were in critical condition. Next of kin had been notified and all personnel were attended to by a special support team established by BW Offshore Brazil. Most of the workers on the vessel were Brazilian nationals.

Output from the FPSO unit was about 2.2 MMcfd of gas.

Gas flow starts from Keathley Canyon Connector

Williams, through its general partner ownership of Williams Partners, and DCP Midstream Partners LP have started operations from their newly extended Discovery natural gas gathering pipeline system.

The newly built 20-in., 209-mile Keathley Canyon Connector deepwater system and the South Timbalier Block 283 junction platform lie in the central ultradeepwater Gulf of Mexico (OGJ Online, Feb. 13, 2012; Aug. 1, 2012).

Capable of gathering more than 400 MMcfd of natural gas, the new pipeline originates in the southeast portion of the Keathley Canyon protraction area and terminates into Discovery's 30-in. OD mainline at Discovery's new junction platform.

The pipeline was constructed in 7,200 ft of water 300 miles south-southwest of New Orleans.

Alan Armstrong, Williams president and chief executive officer, told OGJ in October that, with wall thickness a little more than 2 in., the pipe cost alone was roughly $1 million/mile, with the lay vessels used for those water depths-Allseas Group's Audacia-costing $750,000-1.5 million/day (OGJ Online, Oct. 7, 2014).

The companies first reported expansion plans in January 2012 (OGJ Online, Jan. 19, 2012).

The extension is supported by long-term agreements with the Lucius and Hadrian South owners, as well as the Heidelberg and Hadrian North owners, for natural gas gathering, transportation and processing services for production from those fields.

The new system is also in proximity to other high-potential deepwater Gulf of Mexico discoveries and prospects, Williams notes.

In addition to the offshore gathering system, the Discovery system includes the 600-MMcfd Larose natural gas processing plant providing market outlets to six interstate-intrastate gas pipelines and the 35,000 b/d Paradis fractionation facility.

Williams owns controlling interest in and is general partner of Williams Partners, which operates the Discovery system with 60% interest. DCP owns the remaining 40%.

Central starts gas sales from Palm Valley field

Central Petroleum Ltd., Brisbane, is to start sale of early natural gas from Palm Valley field to Northern Territory Power & Water Corp. under an agreement previously struck with Magellan Petroleum Australia.

Central will provide 2 terajoules/day of gas from its share of Palm Valley field in advance of gas being available from nearby Dingo field, which is still under development.

Central says Dingo will be brought onstream in the second quarter.

The advance gas sales will be incremental to current gas production from Palm Valley, which is under a separate sales agreement with field operator Santos Ltd. It will provide an acceleration of gas revenue with a small incremental operating cost.

Central bought its share of Palm Valley and Dingo from Magellan a year ago and this included the sales agreement for Dingo (OGJ Online, Feb. 19, 2014).

That agreement is for 30 bcf of gas on a take-or-pay basis over 20 years from Dingo and requires construction of a 50-km gas pipeline from the field to Alice Springs.

Central says Dingo will be brought onstream under budget.

PROCESSINGQuick Takes

Williams wraps Geismar olefins plant expansion

Williams Partners LP, Tulsa, has now commissioned and started production of ethylene for sale from its newly rebuilt and expanded Geismar, La., olefins plant following a series of setbacks occurring in the wake of a June 2013 explosion at the site (OGJ Online, June 13, 2013).

The commissioning effort alongside the beginning of ethylene production for sale from the site officially completes the rebuild and expansion project at Geismar, Williams Partners said.

"This is a significant milestone achievement in our effort to restore reliable operations at our plant for the benefit of our customers, employees, contractors, and the community," said John Dearborn, Williams Partners' senior vice-president of NGL and petrochemical services.

With the plant commissioned, the company will now direct its efforts to reaching full production rates on the base plant, and shortly thereafter, ramping up Geismar to its fully expanded ethylene production capacity of 1.95 billion lb/year, Dearborn said.

The company did not disclose current rates of ethylene production at the plant.

Start-up of the revamped and rebuilt Geismar plant faced a string of delays related to the implementation of about $20 million in additional safety and maintenance upgrades folded into the project as the company redoubled efforts to safeguard operations after the June 2013 explosion, which killed two workers (OGJ Online, Feb. 3, 2015).

Prior to the 600 million-lb/year expansion project, the Geismar plant had an ethylene production capacity of 1.35 billion lb/year.

MRPL increases ownership in aromatics complex

Mangalore Refinery & Petrochemicals Ltd. (MRPL), a subsidiary of Oil & Natural Gas Corp. Ltd. (ONGC), has increased its ownership interest in ONGC Mangalore Petrochemicals Ltd. (OMPL), an aromatics complex adjacent to-and fully integrated with-MRPL's 15 million-tonne/year refinery at Mangalore, India.

On Feb. 9, MRPL's board of directors approved the acquisition of an additional 43% interest in OMPL to raise its ownership stake in the petrochemicals enterprise to 46% from a previous 3%, MRPL said in a Feb.9 notice to India's BSE Ltd. (formerly Bombay Stock Exchange).

MRPL accomplished the share increase by purchasing fully paid-up equity shares from individual shareholders, the company said.

Prior to the transaction, ONGC and MRPL held a combined interest of 49% in OMPL, with ONGC originally holding a 46% stake in the venture. The remaining 51% equity in OMPL still is to be offered to public, strategic, financial, and retail investors, according to the most recent information available from ONGC.

Last year, MRPL said that it was examining the possibility of increasing its 3% equity stake in OMPL, according to a July 14, 2014, notice filed with BSE.

The OMPL complex produces 900,000 tpy of paraxylene and 270,000-300,000 tpy of benzene using a feedstock of naphtha and other aromatic streams from MRPL's nearby refinery.

Initially scheduled to be commissioned in 2010, the complex did not begin production until 2014, according to OMPL's most recent annual report to investors (OGJ Online, May 9, 2008).

Contract let for Louisiana methanol complex

Yuhuang Chemical Inc., a subsidiary of Shandong Yuhuang Chemical Co. Ltd., has let a contract to Air Liquide SA, Paris, to supply oxygen for its $1.85-billion methanol manufacturing complex to be built along the Mississippi River in St. James Parish, La. (OGJ Online, July 18, 2014).

Under the long-term agreement, Air Liquide will deliver Yuhuang Chemical's planned complex 2,400 tonnes/day of oxygen to be produced from a new air separation unit (ASU) that Air Liquide will invest about $170 million to build in the area, the French company said in a statement.

The energy-efficient ASU, which also will produce nitrogen and argon and connect to Air Liquide's extensive pipeline systems in Louisiana to ensure reliable supply, is scheduled to be commissioned by second-half 2017, the service provider said.

The new methanol manufacturing complex will produce about 5,000 tonnes/day of methanol, Air Liquide said.

First announced last year, Yuhuang Chemical's project is to include two methanol plants with a combined capacity of 3 million tonnes/year, as well as a methanol derivatives plant for production of intermediate chemicals.

Construction on the complex is slated to begin in 2016, with the first phase of the methanol project scheduled for start-up by 2018, Yuhuang Chemical said.

Yuhuang Chemical previously awarded contracts to China Huanqiu Contracting & Engineering Corp. for delivery of engineering work on the project, and to Air Liquide Global E&C Solutions for its proprietary MegaMethanol process technology, which the complex will use to convert natural gas to methanol.

While most of the complex's methanol production will be exported by oceangoing vessels for use in Shandong's production of downstream chemicals in China, about 20-30% will be shipped by barge and rail to be sold to North American markets, Yuhuang Chemical said.

TRANSPORTATIONQuick Takes

NCOC lets $1.8-billion contract for Kashagan field

North Caspian Operating Co. (NCOC) has let a $1.8-billion engineering and construction contract to ERSAI Caspian Contractor LLC, a subsidiary of Saipem SPA, for two 95-km, 28-in. pipelines to serve the Kashagan field project in the Kazakh section of the Caspian Sea.

The pipelines, which will connect D island in the Caspian Sea to the Karabatan onshore plant in Kazakhstan, will be made of carbon steel, internally cladded with a corrosion-resistant alloy layer. Each will have an offshore length of 65 km.

The overall scope of work includes engineering, welding materials, conversion and preparation of vessels, dredging, installation, burial, and precommissioning of the two pipelines. Some of the work will be executed with specialized subcontractors, Saipem says.

Construction will be completed by yearend 2016.

Production from Kashagan began in 2013 (OGJ Online, Sept. 11, 2013). The field represents the largest oil accumulation in the North Caspian Sea with estimated reserves of 35 billion bbl OOIP and 9-13 billion bbl recoverable.

AOPL releases 2015 safety and planning report

The Association of Oil Pipe Lines is committed to further improvements despite a 99.99% safe petroleum liquids delivery rate, AOPL Pres. and Chief Executive officer Andrew J. Black said as the organization released the 2015 API-AOPL Annual Liquids Pipeline Safety Performance Report & Strategic Plan on Feb. 5. AOPL compiles the report annually with the American Petroleum Institute.

"Even with that delivery rate for crude oil and products pipeline, we are pushing for further safety improvements through a host of industry-wide efforts from leak detection to emergency planning and response," Black said.

In 10 Key Pipeline Performance Results Takeaways, the report listed declines since 1999 of 50% in liquids pipeline incidents along pipeline rights-of-way, 76% in corrosion-caused pipeline incidents, and 78% in incidents caused by third parties. AOPL said most incidents in 2013 were small: 35% were under 1 bbl, two-thirds were 5 bbl or less, and only 20 were larger than 500 bbl.

It said the petroleum liquids pipeline industry's 2015 Pipeline Safety Improvement Strategic Goals & Initiatives are based on stakeholder engagement, safety expert recommendations, review of safety data and results, and lessons learned from pipeline incidents. Operators plan to improve inspection technology capabilities, enhance threat identification and response, expand safety culture and management practices, and boost response capabilities, AOPL said.

"In 2015, pipeline operators will complete development of industry-wide recommended practices (RPs) begun in 2014 on pipeline crack detection and management, pipeline safety management systems, leak detection program management, and emergency planning and response," it said. "Industry-wide implementation of these RPs is a central theme of 2015."

Pipeline operators also will develop industry-wide guidance on the appropriate uses of hydrostatic pressure pipeline testing and an RP for pipeline construction quality management systems, AOPL added.

Study finds FLNG scheme 'viable' for Pandora field

A recent study has found that Cott Oil & Gas Ltd's plans to use a floating LNG vessel for development of Pandora gas field in the Gulf of Papua are technically and commercially viable.

A concept study by Wison Offshore & Marine evaluated the FLNG option as well as a near-shore LNG solution and found the former was the more attractive.

Cott said FLNG technology was becoming increasingly sophisticated in terms of cost-reduction, making it increasingly viable both commercially and technically for gas fields that cannot be developed by more conventional means.

The company added that Papua New Guinea is a growing LNG hub for Asia, and Pandora will be able to supply this market. Several vessel owners and infrastructure partners have expressed interest in a build-own-operate model for gas owners.

Pandora contains an estimated 800 bcf of gas resources. The reservoir is a buried reef structure in 120 m of water midway between Port Moresby and Daru in the Papua New Guinea sector of the Gulf of Papua.

The field was found in 1988 by International Petroleum Corp., but the presence of hydrogen sulfide in the gas and the uncertain gas market precluded development at that time.