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The California Public Utilities Commission has approved a 50% increase in the working capacity of one of the state’s largest merchant-based underground natural gas storage facilities, Wild Goose Storage LLC, north of Sacramento. Regulators unanimously agreed that Wild Goose may expand its working capacity from 50 Bcf to 75 Bcf, the third expansion since it was opened as the state’s first competitive storage facility in 1999. Wild Goose is interconnected with two major gas transmission pipelines of San Francisco-based combination utility Pacific Gas and Electric Co., which operates its own network of underground storage facilities in Northern California, totaling more than 100 Bcf of working capacity.
A subsidiary of Royal Dutch Shell plc has signed a second, six-month extension for more time to decide whether to purchase property in western Pennsylvania that could ultimately be used for a “world scale” ethane cracker in the heart of the Marcellus Shale region. Zinc producer Horsehead Holding Corp. said Shell Chemical LP had signed an amendment to the original March 2012 option and purchase agreement for a 300-acre site near Monaca in Beaver County, PA (see NGI, March 19, 2012). Shell was granted a previous extension in December (see NGI, Jan. 7). Shell has indicated that it has no plans to proceed with any project in Pennsylvania or elsewhere before 2015.
Pacific NorthWest LNG has applied to the National Energy Board for a license to export up to 19.68 million tonnes a year (mmty) of liquefied natural gas for 25 years beginning in 2019 from its proposed facility in Port Edward, British Columbia (BC). The estimated $9-11 billion project is being developed by Calgary-based Progress Energy and new owner, Malaysia’s state-owned Petronas (see NGI, Jan 14). The project would be supplied with gas sourced primarily from Progress Energy Canada’s assets in northeastern BC. The export project is ultimately owned, through various subsidiaries, by Petronas, which has a 90% interest, and Japex, which has the remaining 10%.
The Deep Panuke natural gas production facility offshore Nova Scotia is “closer to natural gas production but not quite there yet,” according to an Encana Corp. spokeswoman. The facility was to have achieved first gas production at the end of June, more than two years late. “Final commissioning, the testing of systems and processes, is taking place offshore to ensure everything is working as it should,” said Lori MacLean. Gas “has been introduced to the platform from onshore via the pipeline. This gas is being used for the commissioning, in effect, to energize the platform prior to the opening of the wells…” Encana is unable to say how long commissioning may take. SBM Offshore NV, which was hired to build and operate the platform, in late May said the project was “on track” to begin producing gas within a month’s time (see NGI, May 27).
The West Virginia Department of Environmental Protection (DEP) regulators said no additional requirements are needed to protect the air quality from horizontal oil and gas drilling. In a letter to state Senate President Jeff Kessler (D-Marshall) and Speaker of the House of Delegates Tim Miley (D-Harrison), DEP oil and gas chief James Martin said regulators had completed an air impact study, which was the third and final report mandated under the state’s Natural Gas Horizontal Wells Control Act (see NGI, Feb. 4). “Based on a review of several completed air studies to date, including the results from the well pad development monitoring conducted in West Virginia’s Brooke, Marion and Wetzel counties, no additional legislative rules establishing special requirements need to be promulgated at this time,” Martin said.
Injection wells in Ohio handled 14.2 million bbl of wastewater from oil and gas drilling in 2012, more than in years past, especially from out-of-state sources in the Marcellus and Utica shales, but they are on pace to handle less of the material in 2013, according to the Ohio Department of Natural Resources. More wastewater came from out-of-state sources (8.2 million bbl, or 57.6% of the annual total) than from operations in Ohio (6.0 million bbl, 42.4%). The 2012 figures are a 12.4% increase from 2011, when 12.6 million bbl of wastewater was disposed of, 5.8 million bbl (45.7%) from Ohio sources and 6.8 million bbl (54.3%) from out of state. Only 3.3 million bbl of wastewater was handled in 1Q2013, including 1.8 million bbl (55.4%) of wastewater from out-of-state drilling, and 1.5 million bbl (44.6%) from Ohio. It was the smallest amount recorded for out-of-state wastewater since 2Q2011, when Ohio took in 1.6 million bbl.
Pacific Gas and Electric Co. (PG&E) told the California Public Utilities Commission in its second annual report in response to the 2010 San Bruno, CA, transmission pipeline failure that it has strength-tested 456 miles of its 6,750-mile gas pipeline system and installed 76 automated shutoff valves while validating the safe operating pressure for the entire system. In addition, the utility is pursuing gas safety certification under Publicly Available Specification 55, has established an employee-led safety committee and has a new corrective action program.
A preliminary state-federal analysis issued in June is casting renewed doubts about a proposed $4 billion commercial carbon capture and storage facility in California. California Energy Commission (CEC) and U.S. Department of Energy (DOE) staff in preliminary analyses and draft environmental impact statements (DEIS) concluded that the Hydrogen Energy California (HECA) project has “significant, and for the most part, unresolved issues.” HECA, dormant for several years, and was revived this year by SCS Energy LLC. If the CEC ultimately approves the project, DOE is committed to helping fund it. The agencies identified 15 technical sections with either “significant unmitigated impacts, noncompliance with applicable laws, ordinances, regulations and standards.” HECA proposes to gasify coal and petroleum coke to produce synthetic gas fuel. It would include an integrated gasification combined cycle power generation plant.
Norway’s Statoil SA has taken over operatorship of the eastern portion of the Eagle Ford Shale assets in Texas that it has held in a 50-50 joint venture (JV) since 2010 with Talisman Energy USA Inc. (see NGI, Oct. 18, 2010). The JV agreement initially gave Talisman full operatorship and specified that Statoil would operate its acreage at a later date. The Statoil-operated activities fall mainly within Live Oak, Karnes, De Witt and Bee counties; Karnes and De Witt are among the top oil-producing counties in Texas. Torstein Hole, senior vice president for U.S. onshore, said, “We now have operational activities in all our onshore assets, Bakken, Marcellus and Eagle Ford…”
A state-of-the-art terminal in northwestern Alberta to provide fracturing sand for unconventional drilling operations, with an annual throughput capacity of 550,000 tons, is set to open this November, Edmonton-based Di-Corp said. Canadian National Railway Co. (CN) would carry sand from Wisconsin to serve the 20-acre terminal north of Grand Prairie. The facility, designed to serve expected growth in demand in the Western Canadian Sedimentary Basin, would have three tracks capable of holding 44 rail cars for unloading. Di-Corp distributes specialty chemicals, parts and accessories that serve the energy, mining, and drilling industries across North America. CN, which provides Canada’s largest railway system, is investing significantly in the sand franchise. The company is working on the US$33 million upgrade of a 74-mile section of the Whitehall Subdivision line in Wisconsin that runs between Wisconsin Rapids and Blair to increase car-loading capacity and train velocity for growing supply chains.
Linde North America has begun construction of an air separation unit (ASU) plant in La Porte, TX, that would begin operations in 2015 as part of a $200 million investment to include a gasification train and supporting facilities. The German-based The Linde Group unit said it would be the largest single U.S. site investment in plant and equipment to date. Oxygen and nitrogen produced by the ASU would supply gasification assets at the Texas site, converting gas into synthetic gas and constituent products such as carbon monoxide, hydrogen and carbon dioxide, which are used to produce methanol, downstream chemicals and cleaner transportation fuels (see related story).
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