GENERAL INTEREST — Quick Takes
IHS indexes show near-record high upstream costs
The costs of building and operating upstream oil and natural gas facilities set near-record highs in the first quarter of 2012, according to cost indexes developed by IHS.
The IHS Upstream Capital Cost Index, based on a 2000 benchmark, increased by 2.3% during the 6 months ending Mar. 31. The new index score of 227 means capital costs totaling $1 billion in 2000 would now be $2.27 billion. The index's high score remains 230, which was reached in third-quarter 2008, IHS said.
The capital cost index increased by 5.3% during all of 2011.
The new cost increases "were driven by strong oil prices that exceeded the threshold price of production for most projects, increasing demand for oil field goods and services," IHS said.
Increased day rates for deepwater rigs accounted for much of the increase. Also, development of onshore unconventional reservoirs put pressure on goods and services despite the shift to oil drilling that has accompanied a slump in prices of gas relative to crude oil prices.
Among 10 markets tracked in IHS's capital cost index the only two declines were for steel and engineering and project management.
The IHS Upstream Operating Cost Index rose 2.1% over the 6 months ending Mar. 31 to an index score of 189.
IHS noted increases in all component markets: operations, maintenance, logistics, and well services.
"Each of the markets were impacted by similar factors, namely an increase in activity due to high oil prices, tightness in supply chains for what can be very highly specialized services and equipment, and a worsening shortage of the labor necessary to deliver these goods and services," IHS said.
Rosneft, GE to jointly pursue oil, gas in Russia
OAO Rosneft and GE have signed a memorandum of understanding to jointly evaluate and develop commercial opportunities in oil and gas exploration and production in Russia.
The agreement calls for a collaboration in which technologies from GE Oil & Gas of Florence, Italy, will be used to help Rosneft improve efficiency and yields. The MOU also calls for the two firms to explore opportunities to jointly develop, manufacture, and sell equipment for use in Russia's oil and gas industry. GE and Rosneft plan to form a joint working group to identify short- and long-term opportunities, including equipment for Arctic offshore field development, enhanced oil recovery, and difficult reserve development.
Petronas unit to acquire Progress Energy
Petronas Carigali Canada Ltd. agreed to acquire Progress Energy Resources Corp. for $5.5 billion (Can.), including debt.
Progress owns shale fields in the provinces of British Columbia and Alberta. The combined company's Canadian operations are expected to remain in Calgary for upstream activities with a commercial office in Vancouver for LNG.
Last year, Petronas and Progress Energy formed a joint venture to develop a portion of Progress' Montney shale assets in the foothills of northeast British Columbia.
Both firms said they wanted to consider opportunities to develop LNG export capacity on British Columbia's west coast. Petronas and Progress also said they plan to build a terminal in Prince Rupert, BC.
Heritage to buy stake in Nigerian oil block
A unit of Heritage Oil PLC agreed to acquire a 45% stake in producing oil Block OML 30 and related assets in Nigeria from Shell Petroleum Development Co. of Nigeria Ltd. and partners for $850 million pending approval from shareholders.
Nigerian National Petroleum Corp. will retain its 55% interest in OML 30, which produces 35,000 b/d.
Heritage said the proposed acquisition provides it with more diversified assets, balancing exploration with production and extending Heritage's holdings within its core areas of Africa and the Middle East.
OML 30 is an onshore block in the Niger Delta about 50 km east of Warri in southern Nigeria. The lease covers 1,097 sq km and includes eight main producing fields with oil and gas in numerous stacked reservoirs.
The OML 30 lease is scheduled to expire in June 2019, and Heritage expects to renew the lease based upon conditions outlined by current Nigerian law.
Acquisition assets include a 45% interest in the Trans Forcados pipeline between the Eriemu manifold and the Forcados River manifold. This pipeline segment is known as the OML 30 Trans Forcados Pipeline.
Terms call for a reverse takeover by Shoreline Natural Resources Ltd., a special purpose private Nigerian company formed by Heritage, a UK independent, and its Nigerian partner, Shoreline Power Co. Ltd.
Partners with Shell Nigeria in the assets being sold are Total E&P Nigeria Ltd., and Nigerian Agip Oil Co. Ltd. The parent companies involved are Royal Dutch Shell PLC 30%, France's Total SA 10%, and Italy's Eni SPA, 5%.
Shell has been selling its onshore Nigeria interests to concentrate on developing offshore fields.
Exploration & Development — Quick Takes
Shell eyes Mackenzie Valley Canol shale oil play
Shell Canada Energy has taken a farmout from MGM Energy Corp., Calgary, to earn an interest in MGM's 466B exploration license in the Central Mackenzie Valley of Canada's Northwest Territories by funding the drilling of one or two wells in the Devonian Canol shale oil play.
Shell has the option to terminate the farmout if MGM doesn't receive timely regulatory approval to drill the first well but will earn 75% interest in EL466B and become operator if it drills and completes both wells.
Shell will earn 37.5% interest after drilling a vertical well, which could be drilled as early as the winters of 2012-13 or 2013-14. The second well would be a horizontal penetration.
MGM would operate both wells. Shell and MGM have agreed to a drilling and completion program for both wells, including coring and a multistage frac.
MGM has applied for a land use permit and water license with the Sahtu Land and Water Board to drill a vertical well on EL466B and expects to receive a final decision in the near future.
Chief landholders in the play include Husky Oil Operations Ltd., ConocoPhillips Canada Resources Corp., MGM, Shell Canada Resources Ltd., and Imperial Oil Resources Ventures Ltd. (OGJ Online, Nov. 4, 2011). MGM noted that Husky Energy was first with activity in the play, having shot 220 sq km of 3D seismic and drilled and cased two vertical wells in the 2011-12 winter.
Total declares Azerbaijan Caspian gas find commercial
Total E&P Absheron has filed a notice of discovery and commerciality for the Absheron offshore block east of Shah Deniz field in the Caspian Sea offshore Azerbaijan.
The Absheron X-2 well, declared a discovery in September 2011, went to 6,874 m in 474 m of water. One of the hydrocarbon-bearing intervals was tested at 33.9 MMcfd of nonassociated gas and 2,500 b/d of 42.5° gravity condensate (OGJ Online, Sept. 9, 2011). Total said well results indicate a gas resource of 5-10 tcf of nonassociated gas with condensate in the Pliocene Balakhany and Fasila formations on the northern compartment of the structure. The elongated structure straddles 270 sq km, and the cumulative net pay is more than 160 m thick.
Total is sidetracking the well toward the northern part of the structure.
The discovery is 100 km southeast of Baku and could be developed with a limited number of wells for a first phase of development. The work program includes studies and surveys to "better dimension this development, Total said. A 3D seismic campaign will be shot in 2013, and more appraisal wells may be drilled to better assess the structure's extent and geometry.
Total E&P Absheron (TEP AB) is operator of the Absheron license with 40% equity. The partners are State Oil Co. of the Azerbaijan Republic 40% and GDF Suez 20%.
Statoil, Total discover gas-condensate near Ekofisk
Statoil ASA said a high-pressure high-temperature gas-condensate discovery on its King Lear prospect in the southern part of the Norwegian North Sea has recoverable volumes of 70-200 million bbl of oil equivalent.
The 2/4-21 exploratory well, drilled by the Maersk Gallant jackup in Production Licenses 146 and 333, found a 48-m gas-condensate column in the main wellbore and a further 70-m gas-condensate column in the 2/4-21A sidetrack.
Wells 2/4-21 and 2/4-21 A are the 11th and 12th wells drilled in PL146. Well 2/4-21 was drilled to a vertical depth of 5,344 m below sea level in 67 m of water, while 2/4-21A was drilled to a vertical depth of 5,237 m below sea level. The site is 20 km north of Ekofisk field.
Statoil will plan for appraisal drilling of the discovery as well as exploration drilling on other interesting prospects in the licenses.
Statoil as operator will evaluate whether King Lear should be developed as a stand-alone or as a tie-in to infrastructure in the area. This area, normally considered an oil province, may on the basis of this discovery and other gas resources form the basis for future gas development, the company said.
Interests in the licenses are Statoil 77.8% and Total E&P Norge 22.2%.
ATP group has Levant gas discovery at Shimshon
A unit of ATP Oil & Gas Corp., Houston, said the Shimshon wildcat in the Mediterranean offshore Israel is a natural gas discovery in the Levant basin.
ATP East Med BV said the well encountered more than 62 ft of natural gas pay in the Bet Guvrin sands. The Shimshon well went to 14,445 ft subsea in 3,622 ft of water. ATP said expects to provide more information about the discovery in this year's third quarter.
The well is south of the Noble Energy Inc. group's Tamar and Leviathan gas discoveries (OGJ Online, Apr. 30, 2012).
ATP East Med is operator a 40% working interest. Other interest owners in the well are Isramco Negev 2 LP 39%, Naphtha Exploration LP 10%, INOC Dead Sea LP 10%, and IOC-Israel 1%.
Drilling & Production — Quick Takes
Karachaganak field agreement takes effect
The Karachaganak Petroleum Operating BV (KPO) consortium and the government of Kazakhstan have completed an agreement giving the state an interest in the group and settling related disputes over giant Karachaganak natural gas and condensate field.
Under the agreement signed Dec. 14, 2011, Kazakhstan acquires a 10% interest for $2 billion cash and $1 billion noncash consideration before tax including settlement of all cost-recovery claims. Tax of $1 billion is payable on the gain arising on the disposal, according to consortium member and cooperator BG Group.
State-owned KazMunaiGaz, which manages the government's interest, will allocate an additional 2 million tonnes/year of capacity on the Caspian Pipeline Consortium pipeline to the project. The allocation begins at 500,000 tonnes/year and will reach the full level as the pipeline is expanded in a project expected to be completed in 3 years.
The government also agreed to exempt Karachaganak production from export custom duties until 2038, when the current production-sharing agreement expires. The agreement settles tax and custom disputes through the end of 2009.
Changes in consortium-member interests accommodating the Kazakh stake are BG Group and Eni, the other cooperator, to 29.25% from 32.5% each; Chevron, to 18% from 20%; and Lukoil, to 13.5% from 15%.
Karachaganak, estimated to hold 5 billion boe of reserves out of 9 billion bbl of condensate and 48 tcf of gas initially in place, last year produced on average 239,000 b/d of liquids and 784 MMcfd of gas.
Halfaya oil production boost starts in Iraq
New facilities at supergiant Halfaya oil field in Iraq have started production in a development phase that will take output to 70,000 b/d. Subsequent phases will push production to a plateau rate of 535,000 b/d.
A group led by PetroChina has a 20-year service contract to develop the field, which was producing 3,100 b/d from four wells when the contract was signed in late 2009 (OGJ Online, Jan. 28, 2010).
The contract provides for cost recovery and remuneration of $1.40/bbl when production exceeds 70,000 b/d.
Former Iraqi Oil Minister Issam Al-Chalabi has estimated Halfaya reserves at 4.6 billion bbl and original oil in place at 16 billion bbl (OGJ Online, Dec. 11, 2009).
Petrochina, operator, holds a 37.5% interest. Total E&P Iraq and Petronas Carigali hold 18.75% each. State-owned South Oil Co. holds 25%.
Strike forces Statoil to shut production
Statoil has shut down production of about 150,000 b/d of crude oil from fields in the North Sea and Norwegian Sea offshore Norway and cut operations of related facilities onshore in response to a labor strike.
The company shut down the Heidrun platform in the Norwegian Sea and Oseberg Field Center in the North Sea after negotiations broke down with the Organization of Energy Personnel, Industri Energi, and Norwegian Organization of Managers and Executives.
Fields affected by idling of the Oseberg center are Oseberg C, Oseberg South and East, Huldra, Veslefrikk, and Brage.
Based on data from Statoil and the Norwegian Petroleum Directorate, Oil & Gas Journal estimates affected oil production at 94,000-99,000 b/d from the Oseberg area and 52,000 b/d from Heidrun. The fields also normally produce natural gas and gas liquids.
Statoil estimated value of the suspended production at 150 million kroner/day. Statoil also is closing the onshore Tjeldbergodden processing complex and parts of the Sture terminal north of Bergen.
PROCESSING — Quick Takes
Williams lets contract for West Virginia gas plant
Williams Partners, Tulsa, has let a contract to Exterran Holdings, Houston, for the design, fabrication, and installation of two gas processing plants in West Virginia. The plants are part of Williams Partners' Ohio Valley midstream operations in the NGL-rich Marcellus shale.
Included are engineering and fabrication of two cryogenic gas plants, each with a capacity of 200 MMcfd produced from the Marcellus. In addition, Exterran will provide site development, construction, installation, and start-up for the two plants as well as for a third 200-MMcfd cryogenic plant (OGJ, May 7, 2012, p. 88; Apr. 30, 2012, p. 26)
Exterran's announcement said its presence in the Marcellus and Utica plays includes several 2012 contract awards; this project brings total capacity of the company's projects there to more than 2 bcfd.
Exterran Partners LP owns and operates processing plants in Ohio and West Virginia under long-term services agreements.
Talisman Energy exits GTL project with Sasol
Talisman Energy Inc. decided against participating in Sasol Canada's gas-to-liquids project following completion of a feasibility study.
Sasol Canada is a unit of Sasol Ltd. of South Africa.
John A. Manzoni, Talisman president and chief executive officer, said Talisman continues joint development of its Montney shale in northeast British Columbia with Sasol.
Talisman's decision to exit the GTL project will not impact its upstream partnerships with Sasol.
Ecopetrol taps Axens for refinery units
State-owned Ecopetrol SA will use Axens technologies for the new hydrocracking and coker naphtha hydrotreating units to be installed in the upgrade and expansion of its 250,000-b/sd Barrancabermeja refinery in Colombia.
The hydrocracker will be able to process 80,000 b/d of a blend of straight-run vacuum gas oil and cracked gas oil. The coker naphtha hydrotreater will have capacity of 14,000 b/d.
The refinery's crude capacity will increase to 300,000 b/d (OGJ Online, Aug. 9, 2011).
TRANSPORTATION — Quick Takes
Shah Deniz picks Nabucco West as Central Europe line
The Shah Deniz consortium has selected the Nabucco West project, which extends from the Turkish-Bulgarian border to Baumgarten in Austria, as the single pipeline option for the potential export of Shah Deniz II gas to Central Europe. Development of the South East Europe Pipeline (SEEP) project—assembled by Shah Deniz partners along with Bulgaria, Romania, and Hungary—will cease.
The consortium described Nabucco's greater maturity as giving it the best chance of being developed and delivered on the same yearend 2017 timeline as Shah Deniz II. The consortium said it will now cooperate with the Nabucco West project on scope, technical studies, and commercial terms.
The consortium selected the Trans-Adriatic Pipeline (TAP) in February as the potential route for Shah Deniz II gas to Italy and since concluded a cooperation agreement with TAP. Shah Deniz will make a final decision between these projects and conclude related gas sales agreements ahead of the Shah Deniz final investment decision planned for mid-2013.
Turkey and Azerbaijan agreed earlier this week to build the Trans-Anatolian Pipeline, which could potentially deliver Azeri gas to Nabucco West (OGJ Online, June 28, 2012).
Shah Deniz II will add 16 billion cu m/year of gas production to the roughly 9 bcm/year from Shah Deniz Stage 1. Field development, some 70 km offshore Baku in the Azerbaijan sector of the Caspian Sea, will include two new bridge-linked production platforms; 26 subsea wells to be drilled with 2 semisubmersible rigs; 500 km of subsea pipelines built at up to 550 m of water; a 16 billion cu m/year upgrade for the South Caucasus Pipeline; and expansion of the Sangachal Terminal.
PHMSA proposes record fine for Enbridge in spill
The US Pipeline and Hazardous Materials Safety Administration proposed a record $3.7 million fine and 24 enforcement actions against Enbridge Energy Partners LP for a July 2010 crude oil spill near Marshall, Mich. Enbridge has 30 days to respond to the notice of probable violation, the US Department of Transportation agency said on July 2.
It said PHMSA investigators found multiple violations of the agency's hazardous liquid pipeline safety regulations related to integrity management, failure to follow operation and management procedures, and reporting and operator qualification requirements.
Enbridge's Line 6B of its Lakehead System ruptured on the evening of July 25, 2010, while the pipeline was in the process of a scheduled shutdown, according to PHMSA. Despite control center alarms, there were several attempts to restart the line, resulting in more pressure which expelled more oil, it said. A local natural gas company employee notified Enbridge's control center about the spill on July 26 after more than 20,000 bbl of crude had been spilled, PHMSA said.
Enbridge deployed up to 2,000 people to clean up the banks of Talmadge Creek, where the rupture occurred, and the Kalamazoo River, and bought about 30 homes in the area over the next 2 months. Primary cleanup was completed by Sept. 27 and documentation submitted to the US Environmental Protection Agency as extended restoration and maintenance of the affected waterway banks began.
UAE begins operating Abu Dhabi-Fujairah crude line
The United Arab Emirates has inaugurated its 230-mile Abu Dhabi Crude Oil Pipeline (ADCOP) from Abu Dhabi to Fujairah. Oil exports from Fujairah will pass through the Gulf of Oman, bypassing the Strait of Hormuz. Initial runs occurred at 1 million b/d, but ADCOP will eventually carry 1.5 million b/d, expandable to 2 million b/d.
ADCOP also includes 12 million bbl of storage, three subsea pipelines, a main pumping station, intermediate pumping station, and three single-point mooring buoys for deepwater tanker loading. China Petroleum Engineering & Construction Corp. was ADCOP's main engineering, procurement, and construction contractor (OGJ Online, May 27, 2009).
Start-up of the pipeline has been delayed repeatedly since an initial 2009 target. ADNOC expects to begin full operations later this month.
Efforts to develop alternative outlets for Persian Gulf crude, avoiding the Strait of Hormuz, were reinvigorated earlier this year when Iran threatened closure of the waterway.
Liquids pipeline operators adopt safety principles
US liquids pipeline operators adopted eight safety principles following the Association of Oil Pipe Lines and American Petroleum Institute Pipeline Subcommittee's joint summer leadership meeting on June 24.
The principles, which evolved from operator experiences and API's Pipeline Performance Tracking System program, will help focus and improve industry safety programs and performance, officials said.
The principles emphasize zero incidents, organization-wide commitments, a culture of safety, continuous improvement, learning from experience, systems to measure success, technology employment, and full communication with the public and other stakeholders.
API Pipeline Director Peter Lidiak said, "Our members have worked hard to measure their performance and identify ways to improve. While we've seen great improvement, more is needed to move us towards a goal of zero incidents."
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