GENERAL INTEREST — Quick Takes
BSEE: Black Elk failed to oversee contractors in fire
Black Elk Energy Offshore Operations LLC failed to properly supervise its contractors, contributing to a series of events and decisions associated with a Nov. 16, 2012, explosion and fire on Black Elk West Delta Block 32 Platform E in the Gulf of Mexico about 17 miles off Grand Isle, La., the US Bureau of Safety and Environmental Enforcement said.
Three people died in the blast (OGJ Online, Nov. 16, 2012).
The incident resulted from numerous decisions, actions, and failures related to welding and construction by Black Elk and three contractors, said an investigation panel of US Coast Guard and BSEE representatives. The panel concluded BSEE safety regulations were not followed by Black Elk, Wood Group Production Service Network, Grand Isle Shipyard, and Compass Engineering Consultants.
"These failures reflect a disregard for the safety of workers on the platform and are the antithesis of the type of safety culture that should guide decision-making in all offshore oil and gas operations," said BSEE Director Brian Salerno.
Black Elk was the lease holder and operator of the D, A, and E platforms on West Delta Block 32, said the Nov. 4 investigation panel's report.
The panel recommended all operators of manned offshore facilities conduct a "safety stand down" in which operators ensure their operations are safe before Dec. 31. A safety stand down uses real world examples to illustrate consequences that can result from the failure to consider safety.
Salerno also requested that the American Petroleum Institute assist BSEE in improving safety. He asked API to help develop safer standards for "hot work" such as welding.
Previously, an 8-month investigation by ABSG Consulting found that, while production was shut in, workers welded on piping connected to a tank containing crude oil and flammable oil vapors without following Black Elk's safety practices (OGJ Online, Aug. 21, 2013).
The piping leading to the tank had not been isolated and made safe for welding activities as required by Black Elk safe work practices. The flammable vapors in the piping ignited and within seconds reached the first oil tank and two connected tanks.
Vermilion to buy gas producing fields in Germany
A subsidiary of Vermilion Energy Inc., Calgary, will acquire GDF Suez EUP Deutschland GMBH's 25% interest in an exploration license that contains four producing natural gas fields in northwestern Germany for $170 million.
The deal is subject to approvals and adjustments, is due to close by yearend, and will be effective as of Jan. 1.
The ExxonMobil Corp.-operated license was formed in 1956. Other partners are Wintershall Holding GMBH and the ExxonMobil-Shell joint venture BEB Erdgas & Erdol GMBH.
Vermilion will also receive a 0.4% equity interest in Ergas Munster GMBH, a joint venture created in 1959 to jointly transport, process, and market gas in northwest Germany. The EGM partners include ExxonMobil, Wintershall, BEB, RWE Dea AG, and GDF Suez.
The transportation interest will allow for Vermilion's proportionate share of produced volumes to be processed, blended, and transported to designated gas consumers through the EGM network of 2,000 km of pipeline.
The four gas fields span 11 production licenses, are expected to average 18 MMcfd net in 2013, and have consultant-estimated proved plus probable reserves of 10.1 million boe net as of yearend 2013.
The active wells produce from the Permian Zechstein Stassfurt carbonate and the Triassic Middle Bunter sandstone. The acquired assets have a relatively low effective decline rate estimated at 16%/year and a reserve life index of 9.2 years. The exploration and production licenses total 204,000 gross acres, of which 85% is in the exploration license.
Vermilion said Germany's E&P industry produces an estimated 165,000 b/d of oil and liquids and 1.1 bcfd of dry natural gas and is characterized by a limited number of well-financed intermediate-sized producers. The assets being acquired are 300 km east of Vermilion's Netherlands fields and share similar subsurface characteristics.
Manas seeking more oil fields in Tajikistan
Manas Petroleum Corp.'s DWM Petroleum AG subsidiary plans to acquire oil producing assets in Tajikistan, and its CJSC Somon Oil unit is negotiating with several experienced entities to farm out a majority of its existing interest in two exploratory blocks.
DWM is buying 65% for $10.1 million and seeking to acquire the other 35% of a Tajik company that operates fields that are producing 300 b/d of oil from below 100 m and have the potential through rehabilitation of being restored to earlier levels of 50 to 3,500 b/d/well or more.
Lack of investment and access to newer technology allowed the fields to become run down following Soviet Union break-up. Beyond rehabilitation, the fields have potential for further development, exploration, and appraisal. Manas did not give the names or locations of the fields.
About 100 wells are ready for workover, and DWM is analyzing more than 300 more wells and developing an initial work program.
Meanwhile, DWM is negotiating with several experienced groups from Russia, China, and the European Union to farm out as much as 70% of Somon Oil's 90% interest in two exploration blocks that it estimates to contain risked resources of more than 400 million bbl of oil. DWM is also discussing the possibility of combining the exploration project with the rehabilitation project.
The exploratory project has two drill-ready prospects, and drilling is expected to start upon signing the agreements with the new partner. One target is located between two fields near producing wells. The second is a subsalt prospect with analogs in producing fields in Tajikistan and Uzbekistan.
In the past few months, all original seismic over the subsalt target has been reprocessed and the target relocated to a far less risky spot, Manas said.
Exploration & Development — Quick Takes
Montney marketables put at 449 tcf, 15.5 billion bbl
The Montney formation in British Columbia and Alberta is one of the world's largest hydrocarbon resources that could meet Canada's natural gas needs for 145 years at present consumption rates, the National Energy Board said Nov. 6.
The formation also contains more than 15.5 billion bbl of marketable natural gas liquids and crude oil, said NEB, the British Columbia Oil & Gas Commission, the Alberta Energy Regulator, and the British Columbia Ministry of Natural Gas Development in releasing the first estimate of the formation's marketable unconventional petroleum resources.
Recent advances in technology, such as multistage hydraulic fracturing, have made it possible to economically develop unconventional gas and liquids in the Montney for the past few years, but little had been known about its total potential.
The agencies estimate that the Montney contains 449 tcf of marketable natural gas, 14.5 billion bbl of marketable natural gas liquids, and 1.125 million bbl of marketable oil.
By combining the Montney's marketable gas estimate with prior assessments, the total ultimate potential remaining in western Canada is 632 tcf. This estimate is likely to increase as additional unconventional potential from other formations is estimated, NEB predicted.
The Montney formation lies roughly in Northeast British Columbia, south of Fort Nelson, and spread into northwest Alberta past Grande Prairie.
Quicksilver, Eni eye Delaware basin oil exploration
Quicksilver Resources Inc., Fort Worth, and Eni SPA will jointly explore for oil on 52,500 gross acres held by Quicksilver in the Delaware basin of West Texas.
Eni will pay up to $52 million representing 100% of seismic, drilling, and completion costs to earn a 50% interest in Quicksilver's Leon Valley acreage. Eni's investment will occur in three phases.
The first phase covers the drilling and completion of as many as three wells to commence by June 2014. The agreement also provides that, upon funding of the first phase, Eni will earn 50% of Quicksilver's interest in a 7,500 gross acre tract also in the Leon Valley area.
Eni will then have the option to fund the drilling and completion of two more wells and commit to a 3D seismic survey in order to fully earn a 50% interest in Quicksilver's Pecos County acreage. Following Eni's $52 million investment, the parties will share equally in all future revenue, operating costs, and capital outlays.
Members of each company will form a joint evaluation team to conduct exploration and development activities, with Quicksilver designated as operator.
The two companies have also formed an area of mutual interest covering Pecos and Reeves counties to pursue more opportunities in the basin.
Quicksilver noted that Eni has helped the Fort Worth firm improve gas recovery in the Alliance area of its Barnett shale development.
Drilling & Production — Quick Takes
Statoil begins production from Visund North field
Statoil ASA has started production from the Visund North oil and gas field in the North Sea. The project is the sixth of the 12 fast-track projects that Statoil has brought on production.
The scheduled startup date was 3-4 weeks earlier than the actual start of production, but completion of the first well and a production shutdown at the Visund A platform contributed to delays, Statoil said. The company invested 3.3 billion kroner ($550 million) in development of the field, which contains 29 million boe in total recoverable reserves. Statoil originally estimated a cost of 3.1 billion kroner (OGJ Online, Dec. 5, 2011).
Statoil used many of the same field development techniques at Visund North that have already been deployed at its Visund South field, the first development in the company's fast-track portfolio (OGJ Online, Nov. 27, 2012). Statoil developed Visund North using a standard, 4-well subsea template. Oil is transported in a pipeline to the Visund A platform for processing via a pipeline manifold and a subsea safety integrity valve under the platform.
Statoil added that resources in the northern Visund area have been proved with January's Rhea discovery that was drilled by an exploration pilot from one of the Visund North wells.
The five fast-track field developments in production along with Visund North are Skuld, Stjerne, Vigdis Northeast, Hyme, and Visund South. The seven remaining developments in the portfolio are Vilje South, Fram H-North, Svalin C, Gullfaks South oil, Oseberg Delta 2, and Gullfaks Rimfaksdalen. These 12 developments are scheduled to produce 200,000 boe/d by yearend 2014, with Statoil receiving a 100,000 boe/d share.
East Dome commissioned at North Urengoy field
A new gas treatment unit with a capacity of 6 billion cu m/year has been commissioned in the East Dome of the North Urengoy field, reports Gazprom Neft.
The launch of the East Dome will raise production at North Urengoy to its design level in 2014, exceeding 10 billion cu m of gas and 1.4 million tonnes of gas condensate.
CJSC Northgas, a joint venture of JSC Novatek and the Gazprom group, said 18 production wells have been drilled at East Dome. Infrastructure also includes gas gathering networks and a gas pipeline and condensate pipeline that lead to West Dome.
West Dome has been producing commercially since 2001. During this year's first 9 months, some 2.9 billion cu m of commercial-grade gas and 290,000 tonnes of gas condensate were produced. Gas condensate is shipped to the Purovsky plant for processing (OGJ Online, Oct. 17, 2013).
Proven reserves at North Urengoy field at yearend 2012 were 157.3 billion cu m of gas and 21.1 million tonnes of liquid hydrocarbons.
Apache reports new water release in Alberta
Apache Canada Ltd. is investigating a second release of produced water at facilities in northern Alberta.
An operator on Oct. 25 discovered the new release on a water-injection pipeline at Shekilie oil field, about 50 km northwest of Zama City, while investigating a volume discrepancy.
Internal data indicate the release began Oct. 3. Apache estimates volume of the release at 1,800 cu m of produced water and size of the affected area at 5.09 ha. The water contained trace amounts of hydrocarbons.
The cause is under investigation.
Earlier, Apache reported stress corrosion cracking of a water-injection pipeline as the likely cause of a June release of produced water at its Zama operations, which include an enhanced oil recovery pilot based on injection of carbon dioxide (OGJ Online, Oct. 22, 2013).
Neither release endangered the public, Apache said.
The company said it is installing real-time monitoring involving supervisory control and data acquisition to its four water-injection systems in the Zama operations area.
PROCESSING — Quick Takes
Lone Star NGL places second fractionator into service
Lone Star NGL LLC, a joint venture of Energy Transfer Partners LP (ETP) and Regency Energy Partners LP, has placed into service its 100,000 b/d Lone Star Frac II fractionator at its Mont Belvieu, Tex., facility.
Including the Frac I, completed in 2012, Lone Star now has two natural gas liquids fractionators, bringing the total Mont Belvieu fractionation capacity to 200,000 b/d (OGJ, May 7, 2012, p. 88). Both fractionators receive NGLs from several sources, including Lone Star's West Texas NGL pipelines and ETP's Justice NGL pipeline.
Lone Star said as shippers increase production from the Permian basin, Eagle Ford shale, and other producing regions under long-term contracts, volumes on Lone Star's pipeline system and the 130-mile ETP Justice pipeline will continue to ramp up. Lone Star added that an increase in fractionator volumes will provide additional value with the export of butane, ethane, and propane for international markets.
Lone Star started service on its 16-in., 570-mile Lone Star West Texas Gateway NGL Pipeline in December 2012. The pipeline originates from Winkler County in West Texas and reaches ETP's Jackson County processing plant with an initial capacity of 209,000 b/d (OGJ Online, Dec. 7, 2012). That month, operations began on its Justice pipeline, which connects the Jackson processing facility to Mont Belvieu (OGJ, May 7, 2012, p. 104).
"The increased fractionation capacity will increase the supply of purity NGL products for our downstream customers through our storage facilities, Houston Ship Channel pipelines, and our recently announced LPG export terminal with Sunoco Logistics," commented Steve Spaulding, Lone Star's executive vice-president. The Sunoco pipeline would connect the Lone Star fractionator to Sunoco's Nederland terminal (OGJ Online, Feb. 27, 2013).
"We continue to evaluate opportunities to add fractionation capabilities at Mont Belvieu." Spaulding added. "Earlier this year, we filed an air permit to construct a third fractionator at the site to ensure we are positioned to meet the critical needs of producers as production in the Permian basin and the Eagle Ford continues to increase."
Lone Star's assets include 1,640 miles of NGL pipelines and 43 million bbl of storage capacity at Mont Belvieu.
Chevron Phillips to increase olefin capacity
Chevron Phillips Chemical Co. LP has completed its study to expand normal alpha olefin capacity at its Cedar Bayou plant in Baytown, Tex., and has received approval to proceed with detailed engineering, design, and procurement of long-lead equipment.
The company will seek final project approval in first-quarter 2014, with construction slated to begin later that quarter. The project would be completed in second-quarter 2015.
Chevron Phillips announced earlier in the year that it already let an engineering, procurement, and construction contract for a 1.5 million tonne/year ethane cracker at Cedar Bayou (OGJ Online, Oct. 4, 2013).
OxyChem-Mexichem JV plans ethylene plant
A joint venture of Occidental Chemical Corp. (OxyChem) and Mexichem SAB de CV will build a 1.2-billion-lb/year ethylene cracker on the site of an OxyChem plant at Ingleside, Tex.
The existing OxyChem plant produces vinyl chloride monomer (VCM), chlorine, and caustic soda. The new 50-50 joint venture is Ingleside Ethylene LLC.
Under a long-term supply relationship, the ethylene produced from the cracker will feed existing VCM manufacturing capacity. Mexichem will use the VCM to produce polyvinyl chloride (PVC) and PVC piping systems.
OxyChem, a wholly owned subsidiary of Occidental Petroleum Corp., will build and operate the cracker, which will take advantage of growing supplies of low-cost feedstock from shale-gas development. Construction also will include pipelines and storage at Markham, Tex.
For the ethylene plant, it has completed front-end engineering and design, received draft permits from the Texas Commission on Environmental Quality, and applied for US Environmental Protection Agency permits.
It expects to let the engineering and construction contract in the fourth quarter this year. Construction is to begin in mid-2014. Commercial operations are to begin in first-quarter 2017.
TRANSPORTATION — Quick Takes
Chevron doubtful about Gorgon LNG fourth train
Citing cost blowouts and changes within the Australian government, Chevron Corp. Chief Financial Officer Patricia E. Yarrington has casts doubts on the fourth train expansion of the Gorgon LNG project in Western Australia.
Yarrington said the cost structure is different today than in 2009 when the first three trains were taken to final investment decision. She said the cost structure has "elevated" and that has put at risk some of Australia's global competitiveness.
Yarrington also said the change in government had to be considered, adding that Chevron wants to see a "little bit of settling down and stability there."
She said, "From a Chevron standpoint, we are going to look at Train 4 and assess it under those new conditions and look at it relative to other opportunities in our portfolio. Obviously Gorgon Train 4 has certain brownfield advantages, but we need to take those advantages, lay in the new macro-conditions that we see in Australia, and take a look at the whole portfolio activity," she said.
Despite this, Chevron will continue with environmental approvals for Train 4. Chevron also wants to have 70% of Train 4 committed under long-term contracts by the time it reaches the FID point.
For existing construction work, Gorgon is 70% complete with 14 of the 21 LNG Train 1 process modules installed, three more in transit, and the remainder scheduled to follow rapidly.
Three of five gas turbine generators also have been installed at the Barrow Island facility, 43 of the 56 jetty caissons are installed, and mechanical completion has been reached for the gas pipeline.
Offshore the pipe lays are complete on the 30-in. Io-Jansz pipeline and three wells at Io-Jansz field are ready to flow gas. Seven wells have been completed at Gorgon field.
Calumet lets contract for Eagle Ford crude line
Calumet Specialty Products Partners LP's wholly owned subsidiary Calumet San Antonio Refining LLC has signed TexStar Midstream Logistics LP to build, own, and operate a 30,000 b/d crude oil pipeline system that will supply at least 10,000 b/d of Eagle Ford shale crude oil to Calumet's San Antonio, Tex., refinery.
Under the 15-year agreement, TexStar will install and operate the Karnes North Pipeline System (KNPS), an 8-in. OD, 50-mile pipeline that will move crude from Karnes City, Tex., to Calumet's Elmendorf, Tex., terminal, a supply hub for the San Antonio refinery. Calumet expects the pipeline to enter service fourth-quarter 2014. Calumet currently receives crude oil at its San Antonio refinery by truck.
The company earlier this quarter completed a project allowing the San Antonio refinery to blend heavy reformates, light naphtha, and ethanol to produce up to 3,000 b/d of finished gasoline, having previously produced ultralow-sulfur diesel, jet fuel, specialty solvents, reformates, naphtha, and vacuum gas oil. It expects early in first-quarter 2014 to complete a crude unit expansion at the San Antonio refinery, increasing total capacity to 17,500 b/d from 14,500 b/d, and boosting production of jet fuel, diesel fuel, and gasoline.
Calumet bought the refinery in December last year from NuStar Energy LP. NuStar had the previous month purchased crude oil pipeline, gathering, storage, and NGL assets in the Eagle Ford shale from TexStar (OGJ Online, Nov. 9, 2012).
Contracts awarded for Russian Far East project
Rosneft and ExxonMobil Corp. have let a contract to a subsidiary of Foster Wheeler AG to undertake the initial phase of the front-end engineering design (FEED) for a proposed Russian Far East LNG project (OGJ Online, Feb. 13, 2013).
Foster Wheeler is one of two companies to be let separate contracts for the initial FEED work before selection of a single contractor for the second FEED phase.
The company will undertake preliminary engineering and execution planning for the LNG plant and associated gas pipelines, infrastructure and marine facilities.
The work will include location and concept studies, design-basis definition, main technical solutions development, constructability assessment, definition of project execution strategies, and preparation of preliminary information for submission to the Russian authorities.