GENERAL INTEREST — Quick Takes
ExxonMobil to invest $37 billion/year through 2016
ExxonMobil Corp. plans to invest $185 billion over the next 5 years to develop new supplies of energy to meet expected growth in demand, Chairman and Chief Executive Officer Rex W. Tillerson announced Mar. 8 in a presentation to investment analysts at the New York Stock Exchange.
Tillerson noted that even with significant efficiency gains, ExxonMobil expects global energy demand to increase by 30% by 2040, compared with 2010 levels. Demand for electricity will make natural gas the fastest-growing major energy source, and oil and gas are expected to meet 60% of energy needs over the next 3 decades, he said.
A total of 21 major oil and gas projects will begin production between 2012 and 2014. In 2012 and 2013, the company expects to start up nine major projects and anticipates adding over 1 million boe/d of net production by 2016. These projects include four in West Africa, Kashagan Phase 1 in Kazakhstan, and the Kearl Oil Sands project in Canada.
Downstream, the company has completed a large project at its Thailand refinery, which is expected to increase the supply of lower-sulfur motor fuels by more than 50,000 b/d, and additional projects are under way, including new facilities at ExxonMobil's Singapore refinery and at a joint-venture refinery in Saudi Arabia.
A major expansion at its Singapore chemicals facilities is nearing completion, ExxonMobil said. Commissioning and start-up activities are expected to continue through 2012, adding 2.6 million tonnes/year of additional capacity to help meet demand growth in the Asia-Pacific region.
API sues EPA over cellulosic biofuels requirements
The American Petroleum Institute sued the US Environmental Protection Agency over what API considers unachievable cellulosic biofuels use requirements in the 2012 Renewable Fuel Standard (RFS). API filed a petition for review on Mar. 12 in US Appeals Court for the District of Columbia.
"EPA's standard is divorced from reality and forces refiners to purchase credits for cellulosic fuels that do not exist," said Bob Greco, API director of downstream and industry operations. "EPA's unrealistic mandate is effectively a tax on manufacturers of gasoline that could ultimately burden consumers."
Greco said the Clean Air Act requires EPA to determine the mandated volume of cellulosic biofuels each year at "the projected volume available." EPA's 2012 rule requires that refiners and importers of gasoline and diesel must use 8.65 million gal of cellulosic biofuels despite a complete lack of commercial supply of the fuel, Greco said.
"EPA must set the requirement at a realistic volume, but [it has] not," he maintained. "This is regulatory absurdity."
API supports a realistic and workable RFS and continues to recommend that EPA base their prediction on at least 2 months of actual cellulosic biofuel production in the current year when establishing the mandated volumes for the following year, according to Greco.
This approach would provide a more realistic assessment of potential future production rather than simply relying on the assertions of companies whose ability to produce the cellulosic biofuel volumes EPA hopes for is questionable, he indicated.
Devon to settle claim for federal royalties
Devon Energy Corp. agreed to pay nearly $3.5 million to settle a federal claim that a company the Oklahoma City independent producer acquired in 1999 underpaid royalties on natural gas produced from federal and Indian tribal leases, the US Department of Justice and US Office of Natural Resources Revenue jointly announced on Mar. 12.
The agreement covers gas produced from federal offshore leases in the Gulf of Mexico and onshore leases along the US Gulf Coast from August 1986 through Dec. 31, 2008, according to DOJ and ONRR, which is part of the US Department of the Interior's Policy, Management, and Budget Office.
They said Devon acquired the operations when it bought PennzEnergy Co., formerly Pennzoil Co., in May 1999. The settlement covers federal allegations under the False Claims Act (FCA) that PennzEnergy improperly deducted from royalty values costs associated with boosting gas up to pipeline pressures and failed to report and pay royalties on gas used to fuel boosting compressors.
The resolution of this matter was one of the last in a series of settlements arising out of whistleblower litigation which has been pending for more than a decade, the two federal entities said. Under FCA's whistleblower provision, private citizens may sue on behalf of the US and share in any recovery, they explained.
Harrold Wright sued on this basis, and settlements from Devon and other producers in the case exceed $300 million, DOJ said. It said that his heirs will receive $908,040.38, or 26%, of the Devon settlement because Wright is deceased.
Exploration & Development — Quick Takes
Anadarko sees 100-200 MMcfd from Mozambique well
The first flow test of an Anadarko Petroleum Corp. well offshore Mozambique has provided "confidence in well designs that are capable of 100-200 MMcfd," the company said.
Anadarko said the Barquentine-2 well flowed at an equipment-constrained rate of 90-100 MMcfd with minimal pressure drawdown and exceptional flow characteristics.
The test "confirmed the deliverability of this reservoir and indicated a low density of development wells may be sufficient to produce the reservoir," said Anadarko Senior Vice-President, Worldwide Exploration, Bob Daniels.
"Using preset gauges in an offset well, we were able to confirm connectivity and reservoir continuity over a distance of more than 3 km. The test also proves the reservoir has very high permeability, meeting the quality specifications for the partnership's LNG development plans.
"This is a very encouraging way to start our testing program, which is an important component in the reserve certification process, as we focus on achieving FID (final investment decision) around the end of 2013," Daniels said.
Barquentine-2 is in 5,400 ft of water in Offshore Area 1 of the Rovuma basin. The drillstem test was conducted by the Deepwater Millennium drillship, which is expected to be mobilized to the Barquentine-1 location for a second flow and interference test in the complex. The 2012 test program also includes drillstem tests in the Lagosta and Camarao areas south of Barquentine.
Anadarko is operator of 2.6-million-acre Offshore Area 1 with a 36.5% working interest. Coowners are Mitsui E&P Mozambique Area 1 Ltd. 20%, BPRL Ventures Mozambique BV 10%, Videocon Mozambique Rovuma 1 Ltd. 10%, and Cove Energy Mozambique Rovuma Offshore Ltd. 8.5%. Empresa Nacional de Hidrocarbonetos EPs 15% interest is carried through the exploration phase.
Anadarko starts Caesar/Tonga Green Canyon oil flow
An Anadarko Petroleum Corp. group has started oil production from its Caesar/Tonga development in the Green Canyon area of the deepwater Gulf of Mexico.
Output is expected to ramp up to 45,000 b/d of oil equivalent from the first three subsea wells, and a fourth well is to be drilled and completed later in 2012 as part of the planned first development phase. The resource base is estimated at 200-400 million boe.
The group is producing Caesar/Tonga through Anadarko's 100% owned Constitution spar floating production facility. The development also included the gulf's first application of steel lazy wave riser technology.
The Constitution spar, in 5,000 ft of water on Green Canyon Block 680, began production in 2006 with a capacity of 70,000 b/d of oil and 200 MMcfd of gas. Anadarko began modifying Constitution's topsides in 2009 to accommodate production from Caesar/Tonga 10 miles to the east.
Al Walker, Anadarko president and chief operating officer, said, "Our ability to safely achieve cost savings of almost $1 billion by leveraging our existing, operated infrastructure in the deepwater Gulf of Mexico continues to demonstrate the value of our hub-and-spoke approach to exploration and development."
Anadarko operates Caesar/Tonga with 33.75% working interest. Statoil Gulf of Mexico LLC has 23.55%, Shell Offshore Inc. 22.45%, and Chevron USA Inc. 20.25%.
Egypt Western Desert concession gets fourth find
Kuwait Energy PLC reported its fourth discovery on the Abu Sennan concession in Egypt's Western Desert.
Initial tests at the El Salmiya-1 well yielded commercial flow rates from the Cretaceous Abu Roash E and C members. The E member flowed at 400 b/d of oil and the C member made 2,500 b/d of oil and 17 MMscfd of gas.
The El Salmiya discovery follows the company's GPZZ-4 and Al Ahmadi-1 gas-condensate discoveries in August 2011 and the Al-Jahraa-1X oil discovery in January 2012.
Kuwait Energy is operator with 50% working interest, Dover Investments Ltd. has 28%, and Beach Petroleum (Egypt) Pty. Ltd. has 22%.
Since its formation in 2008, Kuwait Energy has made 16 discoveries in Egypt, where it operates Area A, the Burg El Arab development lease, and Abu Sennan and has interests in the Mesaha concession and the East Ras Qattara Petroshahd development lease.
Ministry: Shale gas policy near for India
With a new assessment by the US Geological Survey in hand, India's Ministry of Petroleum and Natural Gas is moving toward announcement of a regulatory regime for shale gas exploration and production.
Shri Jaipal Reddy, the petroleum minister, told the upper house of India's parliament, the Rayja Sabha, that a shale gas policy might be ready by Mar. 31, depending on "completion of the consultation process with all the concerned authorities, including environmental safeguards."
One shale gas well has been reported in India—by state-owned Oil & Natural Gas Corp. working with Schlumberger near Durgapur, West Bengal (see map, OGJ, Dec. 5, 2011, p. 90). The well, RNSG No. 1, was shut down after encountering problems with casing, high water-cut production, and high surface pressure.
The Directorate General of Hydrocarbons has directed Central Mine Planning & Design Institute Ltd. to assess shale gas potential in the Damodar and Sohagpur basins, the ministry said.
In January, USGS published shale gas assessments for the Bombay, Cauvery, and Krishna-Godavari geologic provinces. Its mean estimates of technically recoverable resources:
• For the Cambay Shale Gas South Assessment Unit of the Bombay province, 924 bcf of gas and 31 million bbl of NGLs.
• For the Sattapadi-Andimadam Shale Gas Assessment Unit in the Cauvery province, 1.123 tcf of gas and 39 million bbl of NGL.
• For the Raghavapuram Shale Gas Assessment Unit of the Krishna-Godavari province, 4.08 tcf of gas and 90 million bbl of NGL.
Drilling & Production — Quick Takes
Aker Solutions to design Norwegian Sea spar
Statoil SA has let contract to Aker Solutions for front-end engineering and design of a novel spar platform for Luva gas and condensate field on the Norwegian Continental Shelf in the Norwegian Sea, which has been renamed Aasta Hansteen.
Aker Solutions says the structure, called a belly spar, will be the world's largest spar platform, the world's first with condensate storage capacity, and the first spar offshore Norway.
With a hull length of 193 m and a draft of 170 m, the spar also will be the first production platform on the NCS with steel catenary risers, according to Henning Ostvig, head of front-end and technology at Aker Solutions.
The spar will be moored in 1,300 m of water with a set of polyester lines, housing accommodation facilities and processing equipment to handle production from wells completed subsea (OGJ Online, Jan. 30, 2012).
ERCB approves Gemini oil sands project
Koch Oil Sands Operating ULC has received conditional approval to build and operate the Gemini thermal oil sands project near Beaverdam in the Cold Lake area of Alberta.
The province's Energy Resources Conservation Board approved a two-stage recovery scheme based on steam-assisted gravity drainage to produce as much as 10,000 b/d of bitumen.
The first stage includes drilling of a SAGD well pair and two observation wells and construction of a processing facility and related pipelines, leading to production of 1,200 b/d.
The second stage includes drilling of as many as 23 additional well pairs from five pads and construction of pipelines and a second-stage processing facility, as well as drilling of at least 15 observation wells.
The conditions set special requirements for groundwater monitoring and for a plan to mitigate potential effects on surface water near two of the drilling pads.
Review starts of Laricina's Germain expansion
Alberta's Energy Resources Conservation Board has begun its review of applications by Laricina Energy Ltd. for expansion of the Germain commercial demonstration oil sands project in the west Athabasca region.
The expansion would increase production capacity in phases from 5,000 b/d of bitumen in an initial phase under construction now to 155,000 b/d.
Laricina plans to use a combination of steam-assisted gravity drainage and solvent-cyclic SAGD. It expects solvent injection with steam to lower the steam-oil ratio and carbon emission intensity.
The company filed expansion applications with ERCB and Alberta Environment and Water last November.
It expects steam injection to begin in second quarter of 2013 in the 5,000-b/d phase in progress.
The new applications cover a second phase with 30,000 b/d of capacity and third and fourth phases of 60,000 b/d each. Depending on approvals and financing, construction of the second phase could start in 2013, of the third phase in 2016, and of the fourth phase in 2018.
Laricina estimates cost of the second phase at $1.1-1.5 billion (Can.), most of which awaits financing.
The company says the main reservoir at Germain is the Grand Rapids formation, part of the Lower Cretaceous Upper Mannville Group. Encountered at an average depth of 225 m, the Grand Rapids is a clean sandstone with a homogeneous and continuous pay zone 10-25 m thick.
A secondary target is the Late Devonian Winterburn carbonate complex about 200 m below the Grand Rapids. Laricina says Winterburn development would use existing infrastructure and thermal recovery such as cyclic-steam stimulation or modified SAGD.
Laricina holds a 96% working interest in 17,920 hectares in the Germain area, which is 130 km southwest of Fort McMurray.
CNRL restarting Horizon bitumen upgrader
Canadian Natural Resources Ltd. has begun to restart the Horizon bitumen upgrader, which it shut down Feb. 5 for unplanned maintenance on the fractionating unit (OGJ Online, Feb. 15, 2012).
The upgrader, at CNRL's oil sands mining operation north of Fort McMurray, Alta., can produce 110,000 b/d of synthetic crude oil and is scheduled for expansion in phases to 232,000-250,000 b/d.
Suncor upgrader gets unplanned maintenance
Suncor Energy expects one of its two bitumen upgraders in Fort McMurray, Alta., to be offline for 3-5 weeks while it conducts unplanned maintenance related to fractionator performance.
It projects oil sands production during the period at 140,000 b/d. Its Fort McMurray upgrading facilities can produce 350,000 b/d of synthetic crude oil.
Suncor reported average oil sands production last year of 304,700 b/d.
PROCESSING — Quick Takes
Chesapeake group plans Utica NGL project
Chesapeake Midstream Development LP, M3 Midstream LLC, and EV Energy Partners LP have formed a partnership to build a midstream services complex with capacity to process 600 MMcfd of natural gas for the Utica shale play in eastern Ohio (OGJ Online, Feb. 29, 2012).
The project joins other midstream ventures recently announced in conjunction with rapid development of the liquids-rich gas resource (OGJ Online, Mar. 7, 2012).
Under new definitive agreements, Chesapeake will build and operate natural gas gathering and compression facilities, and M3 Midstream will build and operate processing, NGL fractionation, loading, and terminal equipment.
The cryogenic processing plant will be in Columbiana County, southwest of Youngstown.
NGLs will move from there south to a central NGL hub in adjacent Harrison County with initial storage capacity of 870,000 bbl, fractionation capacity of 90,000 b/d, and a rail-loading facility. Gas processing and fractionation are to start in second-quarter 2013.
Chesapeake Energy Corp. said the partnership plans to invest $900 million over 5 years, most of it in the first 2 years.
Total E&P USA Inc., a 25% partner with Chesapeake in Utica shale wet gas acreage, has an option to participate in the midstream project (OGJ Online, Jan. 3, 2012).
Thai refinery lets contract for cat cracking unit
Thailand's IRPC PLC let contracts to Shaw Group Inc. to provide process design and technology license to add a 30,000-b/d deep catalytic cracking unit at IRPC's 215,000-b/d refinery in Rayong. No contract value or timetable was divulged.
The upgrade project will "maximize production of polymer-grade propylene and recovery of polymer-grade ethylene for feedstock for petrochemical derivative units at the same site," Shaw Group said. It also said the company would function as the "superlicensor" for four additional supporting technologies provided by Axens.
Shaw Group is the exclusive licensed provider of DCC technology outside of China and together with the technology's developer, China's Sinopec Research Institute of Petroleum Processing, has licensed a total of 16 DCC units.
TRANSPORTATION — Quick Takes
EPP, Enbridge, Anadarko advance Texas Express
Enterprise Products Partners LP, Enbridge Energy Partners LP, and Anadarko Petroleum Corp. will move ahead with their Texas Express NGL pipeline, having executed long-term contracts for 232,000 b/d of its capacity. Starting near Skellytown in Carson County, Tex., the 20-in. OD TEP mainline will extend about 580 miles to Enterprise's NGL fractionation and storage complex at Mont Belvieu, Tex., also providing access to other third-party facilities in the area (OGJ Online, Sept. 6, 2011).
Production from the Rockies, Permian basin, and Midcontinent will be delivered into TEP through Enterprise's existing Mid-America Pipeline System, running north through Oklahoma into Conway, Kan., and south into the Permian basin. Enterprise described the project as a bolt-on expansion, enhancing the value its midstream assets.
The joint venture also includes two new NGL gathering systems. The first will connect TEP to natural gas processing plants in the Anadarko-Granite Wash production area in the Texas Panhandle and Western Oklahoma. The second NGL gathering system will connect the new pipeline to Barnett shale natural gas processing plants in central Texas.
Enterprise will build and operate the pipeline, while Enbridge will construct and operate the new gathering systems. TEP's contracted shippers, which include unaffiliated shippers, have tendered 15-year, ship-or-pay transportation agreements for the 232,000 b/d. The contracts also include an option allowing shippers to increase their volume commitment.
Enterprise is conducting community outreach, surveys, and negotiating right-of-way agreements and expects the pipeline and related gathering systems to begin service second-quarter 2013, subject to regulatory approvals.
Shell calls for shippers on reversed crude line
Shell Pipeline Co. LP requested shipper commitments for plans to reverse its Houma-to-Houston (Ho-Ho) crude oil pipeline system. The reversed pipeline would connect the Houston and Port Arthur, Tex., markets with the Louisiana markets in early 2013, subject to regulatory approval. Service from Houma, La., to St. James, La., will continue to flow that direction.
The reversal will allow barrels from the Eagle Ford, Barnett, and Bakken production areas, as well as supplies from storage in Cushing, Okla., improved access to the full breadth of the Houston-to-Louisiana refining complex, moving up to 300,000 b/d across the region depending on the crude types shipped (OGJ, Jan. 9, 2012, p. 24).
Commitments from interested shippers are due Apr. 20.
Contract let for Dominican Republic terminal
Complejo GNL del Este, a consortium of Dominican and Colombian energy companies, has awarded a contract for an LNG terminal and jetty in San Pedro de Marcoris in the Dominican Republic to a subsidiary of Foster Wheeler AG's global engineering and construction group.
No contract value was given for the basic design and front-end engineering contract, whose work is to be completed in September.
Foster Wheeler's announcement said it had previously completed a feasibility study for selection of the most suitable technology for the terminal, which will have a sendout capacity of 240 MMscfd with an LNG storage tank of 160,000 cu m. The design will also consider future expansions of as much as 700 MMscfd.
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