OGJ Newsletter

Nov. 29, 2010
International News for Oil and Gas professionals

PTTEP buys stake in Statoil's Canadian oil sands

Thailand's PTT Exploration & Production (PTTEP) plans to pay Norway's Statoil $2.2 billion for a 40% interest in an Alberta oil sands project.

Statoil plans to keep 60% ownership of the Kai Kos Dehseh project, which it operates. Statoil Canada Ltd. will continue handling and marketing the production.

The transaction, subject to Canadian regulatory approvals, is expected to close in first-quarter 2011.

Statoil got involved with the Kai Kos Dehseh project through its 2007 acquisition of a private Calgary company North American Oil Sands Corp., which was developing 275,200 gross acres of oil sands leases in the Athabasca region.

Since then, Statoil has constructed steam-assisted gravity drainage facilities and related infrastructure for the Leismer demonstration project, which is Kai Kos Dehseh's first-phase development (OGJ, July 19, 2010, p. 39).

Statoil initiated steam injection at Leismer on Sept. 3 and expects to move into the production phase next year. Statoil's schedule calls for Kai Kos Dehseh to produce 100,000 b/d of bitumen around 2016 and more than 200,000 b/d by 2020.

Firm to buy ExxonMobil gulf shelf properties

Energy XXI (Bermuda) Ltd., Houston, will buy Gulf of Mexico shelf assets from ExxonMobil Corp. for $1.01 billion in a deal that makes the purchaser the third-largest shelf oil producer.

The nine fields being acquired, generally between Energy XXI's core South Timbalier and Main Pass operations in 470 ft of water or less, are producing a net 20,000 boe/d, 53% oil. The six largest fields have 89% of the production.

Energy XXI will operate 94% of the acquired properties. The purchase includes 130,853 net acres of offshore leases.

Reserves being acquired are 30.1 million bbl of oil and 116.1 bcf of gas, 68% proved developed, or a 65% reserves boost for Energy XXI.

The purchase is subject to preferential rights-to-purchase held by other working interest owners in the properties and to customary closing conditions and adjustments. The effective date is Dec. 1 with closing expected by Dec. 20.

Energy XXI listed $414 million in future development costs associated with the properties, including $313 million associated with proved reserves.

The six main fields being acquired are South Timbalier 54, West Delta 30 and 73, Grand Isle 43 and 16, and South Pass 89.

Williams expands in Marcellus; buys Cabot assets

Williams Partners LP is expanding its midstream business in Pennsylvania's Marcellus shale, acquiring Cabot Oil & Gas Corp.'s midstream assets in Susquehanna County, Pa., for $150 million. The assets include about 75 miles of gathering pipelines and two compressor stations, with the transaction expected to close in the fourth quarter, subject to customary closing conditions and regulatory approval. The acquired Cabot assets gather about 230 MMcfd of Cabot's natural gas production.

Williams Partners also added more than $150 million of expansion capital to fund 2011 construction of additional gathering assets, including compression and dehydration, augmenting the assets acquired from Cabot. The partnership says it will continue to invest additional capital beyond 2011 to further expand the system, with the combined gathering system being capable of delivering roughly 1.2 bcfd of gas over the next 2-3 years.

The new system will connect with Williams Partners' previously announced Springville gathering pipeline in Susquehanna County. The Springville system is under construction and expected to be operational mid-2011.

The partnership also agreed to a new long-term dedicated gathering agreement with Cabot for its production in the northeast Pennsylvania area of the Marcellus shale. The 25-year agreement covers 138,000 gross acres.

Williams Partners plans to fund both the $150 million purchase and the subsequent capital projects with cash on hand, borrowings from its credit facility and capital market transactions.

Group slams proposed UK migration limits

Proposed UK migration limits would slow oil and gas development off the country, an industry group warns.

Under pressure to cut net migration, the government Migration Advisory Committee has recommended that the Border Agency of the UK Home Office tighten limits on skilled and highly skilled migrant workers admitted to the UK from outside the European Union.

It proposes to limit visas for professional migrants next year to 27,400-43,700, compared with 50,000 in 2009. The action covers Tier 1 visas for highly skilled workers and Tier 2 visas for sports people, religious ministers, and industrial workers in categories such as shortage occupations and transfers within companies.

Oil & Gas UK said the proposed limits would hurt the ability of oil and gas companies to assemble specialist teams. "We are particularly concerned that companies using intracompany transfers (ICT) to bring in the necessary skills and expertise not found in the UK will be included in that cap," said Malcolm Webb, OGUK chief executive.

He said a temporary cap on skilled migration "is already causing delays to major UK offshore and gas projects on which, paradoxically, hundreds of jobs for UK residents depend."

Adoption of the proposed limits would "jeopardize investment in the development of the UK's oil and gas resources, with the related risk to employment and security of energy supply in the medium and long term," he said. "We call on the government to ensure that entry of skilled migrants via the Tier 2 route and particularly ICT is protected."

Exploration & Development - Quick Takes

Anadarko Brazil postsalt find heads for presalt

Anadarko Petroleum Corp. has a two-zone postsalt oil and gas discovery at its Itauna-1 exploratory well in the BM-C-29 block in the Campos basin off Brazil.

The well is at 15,250 ft and has encountered more than 275 net ft of oil and gas pay in two separate postsalt zones. The company called the discovery substantial and has filed show reports with Brazil's ANP on the two formations.

Anadarko said, "The already significant postsalt pay count could increase when we perform a bypass to obtain additional information that should address the unconsolidated formations in the existing hole. We are drilling ahead to test two targeted presalt objectives and expect to complete activities in the well by the end of the year."

Itauna-1, in 250 ft of water, is to continue to nearly 18,000 ft. The rig will then work for another operator before returning to Anadarko in 2011 for appraisal drilling on the block.

Anadarko operates BM-C-29 with a 50% working interest, and Colombia's state Ecopetrol owns the other 50% through its affiliate Ecopetrol Oleo e Gas do Brasil Ltda.

ConocoPhillips ramps up Eagle Ford position

ConocoPhillips plans to sharply hike capital spending in the Southeast Texas Eagle Ford shale play in 2011.

The investment level, although not yet approved, likely will be $1-1.5 billion in 2011 compared with $300 million in 2010, management said last week. The 2011 amount is for drilling and completions, not to add acreage.

The company holds more than 240,000 net acres southeast of San Antonio in Live Oak, Bee, Karnes, DeWitt, and Gonzales counties and expects to be running 10 rigs by the end of 2010.

Results from wells drilled so far are very encouraging, with 30-day averages of 1,500 boe/d at a cost of $8-9 million/well.

The company expects its activity to pick up in the fourth quarter from the nine rigs now running. It drilled 15 wells and completed eight in the quarter ended Sept. 30.

ConocoPhillips intends for the Eagle Ford play to contribute 65,000 boe/d of net production in the long term. Meanwhile, the company plans to boost its North Dakota Bakken rig count to more than eight rigs in 2011, and it also has a position in the North Barnett shale play in Texas.

GeoPark sees potential at Guanaco in southern Chile

GeoPark Holdings Ltd., Buenos Aires, added an oil well in Guanaco field on the Fell block in the Magallanes basin in Chile, where it holds 100% working interest. Guanaco-6 went to 2,760 m and flowed 1,578 b/d of oil through a 12-mm choke with 654 psi wellhead pressure from a 12-m perforated interval in Lower Cretaceous Springhill sandstone at 2,551 m. Projected rate is 600-800 b/d; the well is on production.

GeoPark said well results and preliminary interpretation of available seismic data provide evidence that the Guanaco structure covers 6 sq km with a preliminary internal estimate of 6-7 million bbl of proved and probable reserves, 3-4 million bbl higher than previous estimates. Multiple drilling opportunities are evident.

The field is in the south-central part of the block, and a 3D seismic survey shot this year suggests the possibility of finding traps and more resources south of the Guanaco structure, GeoPark said.

Meanwhile, the company will run a hydraulic frac stimulation on Springhill in the Dicky-18 well after it flowed at low initial rates.

Iraq Miran West-2 well under test program

Heritage Oil PLC is conducting tests of its Miran West-2 well in southern Iraqi Kurdistan after the well encountered indications of hydrocarbons in Cretaceous, Jurassic, and Triassic intervals below 2,500 m.

Shooting of 550 sq km of 3D seismic is under way on the 1,015 sq km Miran block. The seismic results and extensive field work that started in October 2010 will help establish future drilling locations to exploit the reserviors' fracture networks, Heritage said.

Miran West-2 went to a total depth of 4,426 m. Test results are expected in about 2 months. The well is 4 km northwest of Miran West-1, suspended as a future producer. It went to 2,935 m and encountered oil shows over a 1,100-m interval including the three principal proven reservoir formations in the region.

Heritage said it is looking to contract at least one rig to continue drilling on the block in 2011, including an exploratory well on the Miran East structure.

Quetzal group testing Llanos oil discovery

A group led by Quetzal Energy Ltd., Calgary, has tested 20.7° gravity oil at the rate of 2,225 b/d from Lower Mirador at a discovery well in Colombia's Llanos basin.

The Canaguay-1 well on the Canaguaro block went to 15,850 ft total depth. Upper Mirador, which had the majority of the indicated oil pay on well logs, is to be tested in coming weeks. The company has run cased-hole drillstem tests on several formations.

Une/Lower sandstone at 15,469-484 ft flowed gas too small to measure, and the pressure data indicated relatively poor permeability. Quetzel reverse-circulated 50 bbl of 37° gravity oil after the test.

Une/Gacheta at 15,353-359 ft indicated poor permeability and recovered a small sample of 27.4° gravity oil.

Gacheta at 15,231-248 ft indicated poor permeability, and no hydrocarbons were recovered. Barco at 14,724-736 ft indicated fair zonal permeability but produced no hydrocarbons.

Quetzal perforated Lower Mirador at 14,292-297 ft, ran coiled tubing to 6,000 ft, and pumped 500 scf/min of nitrogen to remove the fluid cushion and achieve a 17% drawdown. Fluid production rates averaged 2,225 b/d of 20.7° gravity oil with a trace of water.

Drilling & Production - Quick Takes

API: US oil production broke October record

US crude oil production averaged 5.5 million b/d in October, a record for the month and 0.1% higher year-to-year, the American Petroleum Institute said in its latest monthly statistical report. Crude inventories increased for a fourth consecutive month to 366 million bbl as of Oct. 31, also a record for the month, it indicated on Nov. 19.

Production in the Lower 48 states averaged 4.86 million b/d, roughly comparable to previous months and 0.2% above October 2009's average, according to API. Alaskan crude production, which averaged 654,000 b/d last month, was higher following the summer maintenance season but 0.6% lower year-to-year, it added.

"The growth has been particularly strong in the Bakken shale area of Montana and North Dakota—to the point that North Dakota has become the nation's fourth largest crude oil producer," API Chief Economist John C. Felmy told OGJ. "We're also starting to see development in the Eagle Ford area, but the real growth has been in North Dakota."

Baker Hughes Corp. reported on Nov. 5 that October's monthly US rig count of 1,668 was 13 more than September's 1,655 and 624 than October 2009's average of 1,044. Its figures include rigs drilling for gas and oil.

The US Energy Information Administration forecast on Nov. 9 in its short-term energy outlook that US oil production will climb 140,000 b/d this year to an average 5.5 million b/d. This would follow a 410,000 b/d increase in 2009 and precede a 40,000 b/d decline in 2011 to an average 5.46 million b/d, it indicated.

EIA said its latest monthly forecast included decreases during 2011 of an average 160,000 b/d from US Gulf of Mexico leases and 50,000 b/d in Alaska, and a 170,000 b/d increase in domestic production outside those two areas.

Floating production system numbers continue to rise

The number of floating production systems continues to increase, according to International Maritime Associates Inc.'s latest floating production report.

IMA now tracks 196 offshore projects at various stages of design or planning that potentially will require a floating production or storage system.

Regarding the current fleet, IMA found that in service worldwide are 250 floating production units. This compares with 117 units in service 5 years ago, and 119 units in service 10 years ago.

The 250 floating production units include 155 floating production, storage, and offloading vessels, 42 production semisubmersibles, 22 tension-leg platforms, 18 production spars, 8 production barges, and 5 floating storage and regasification units.

IMA noted that the current order backlog consists of 49 production floaters, which includes 35 FPSOs, 6 production semis, 1 TLP, 3 FSRUs, and 4 floating LNG (FLNG) vessels.

Brazil continues to dominate orders for production floaters. IMA said that of the 49 production floaters on order, 19 are for use off Brazil. It also noted that 7 units are on speculative orders and do not have a field destination at this time. The 7 include 4 FLNGs, 1 FPSO, and 2 FPSOs where work has been slowed, according to IMA.

Regarding available units, IMA said 11 floaters are not on a field and are looking for work as of mid-November. It noted that not all of these units will likely find new work and some are candidates for scrapping but at least a half dozen FPSOs appear capable of being modified and competitively redeployed.

Of the units in the field, IMA said that many FPSOs are reaching the end of the field life with 3 having been stationed on a field more than 20 years, 8 for more than 15 years, and 27 for more than 10 years.

IMA expects that at least half of these units are redeployment candidates, particularly 15 that have operated in the North Sea for more than 10 years and 2 that have operated off Australia for more than 10 years.

In the US Gulf of Mexico, according to Jim McCaul, head of IMA, developments have not stood still because of the moratorium on drilling.

He noted that during the moratorium several major deepwater projects in the gulf have moved to the development stage. These include a contract for a production semi on Tubular Bells and contracts for production floaters on three projects (Olympus TLP, Jack-St. Malo production semi, and Bigfoot TLP) that moved to the contract-imminent stage, McCaul said.

PROCESSING - Quick Takes

Rise noted in downstream construction costs

Design and construction costs for refining and petrochemical projects increased for the third 6-month period in a row, according to the IHS CERA Downstream Capital Costs Index (DCCI). The third-quarter 2010 index rose to 180 from 175 in the first quarter of 2010. The DCCI uses 2000 costs as the base year with a value of 100.

The index peaked in the third quarter of 2008 at 187 and fell to 170 in the first quarter of 2009.

IHS CERA attributed recent cost increases to a weakened US dollar and rising commodity prices driven by global economic recovery and increased construction activity.

The firm cited "robust" construction in China, India, and the Middle East. It noted record refining and ethylene capacity additions in 2009 and a large number of projects planned or under construction.

"This trend is expected to continue until 2015," IHS CERA said in a press release. "Government policies encourage investment in the downstream sector in anticipation of increasing demand for transportation fuels, plastics, and fibers."

IOCL lets contract for Paradip refinery

Indian Oil Corp. Ltd. let a contract to Essar Projects (I) Ltd. for work on the 300,000-b/d grassroots refinery being built at Paradip, Orissa, on India's east coast (OGJ Online, Mar. 12, 2009). Essar Projects will conduct residual process design, detailed engineering, procurement, construction, commissioning, and performance testing of core processing units.

The lump-sum turnkey contract covers the atmospheric vacuum, straight run LPG treating, naphtha hydrotreating, naphtha fractionator, continuous catalytic reforming, sour water stripper, and amine regeneration units. The full-conversion refinery will be able to process all heavy, sour crudes. IOCL expects to begin commissioning in March 2012.

Enterprise buys HSC isobutylene plant

Enterprise Products Partners LP, Houston, paid $38.5 million for a plant on the Houston Ship Channel that produces high-purity isobutylene (HPIB).

It can produce more than 300 million lb/year of HPIB, much of which is under contract, according to the Enterprise report. HPIB is used in the manufacture of tires, lubricants, and other petroleum-based products.

The plant, bought out of bankruptcy and previously owned by Bigler LP, also provides terminal services for refined products and petrochemicals. On a 250-acre site, the plant also affords access to multiple transportation options, including marine, rail, truck, and pipelines.

Opened in 2009, the plant has four pressurized spheres for storing HPIB and butanes. In addition, more than 450,000 bbl of storage capacity is available for a variety of refined products and is currently accessible by barge.

The plant is equipped with multiple truck and rail racks for product movements, along with rail car storage for as many as 105 rail cars. And it is near Enterprise's liquids pipelines that transport NGL and refined products.

"This acquisition complements our existing natural gas liquids, petrochemical services and refined products businesses and is a natural extension of our nearby Mont Belvieu operations, which will provide the raw materials for the plant," said Pres. and CEO Michael A. Creel.


DCP requests EOI for Sandhills NGL line

DCP Midstream has requested a nonbinding expression of interest for its proposed DCP Sandhills Pipeline. The 130,000-b/d NGL pipeline will extend more than 700 miles from West Texas to fractionation and storage facilities along the Texas Gulf Coast including Mont Belvieu.

Sandhills Pipeline will service NGLs produced from the Avalon shale in West Texas and the Eagle Ford shale in South Texas, helping relieve capacity constraints. DCP expects Sandhills to enter service in 2013, with expansion possible to meet customer needs. Expressions of interest must be submitted by Dec. 9.

Meritage continues Eagle Ford gathering expansion

Meritage Midstream Services has completed its Fasken Ranch natural gas lateral pipeline, an extension to the company's Eagle Ford Escondido Gathering System in Webb County, Tex.

The 14½-mile, 12-in. OD pipeline extends Meritage Midstream's gas-gathering system to the northwest into Swift Energy Co.'s Fasken operating area. Swift Energy will have up to 40 MMcfd firm capacity on the new pipeline. Swift has set a preliminary 2011 capital budget of $430-450 million, 75-80% of which it plans to spend in South Texas.

Meritage is also building a 10½-mile, 16-in. OD extension to the southeast to increase takeaway capacity in the Eagle Ford shale. The company expects this line to enter service early-2011.

Meritage says it will expand treating capacity at its South Calahan facility as volumes on the gathering system increase.

TAP system begins route refinement in Greece

The Trans Adriatic Pipeline (TAP), designed to deliver natural gas from the Caspian region to Europe via Greece, Albania, and Italy, has begun its route refinement study in Greece in preparation of the environmental and social impact assessment required by the European Bank for Reconstruction and Development.

A team of 28 experts—from TAP, E.On Ruhrgas, and national and international consultants—will take 3 months examining proposed TAP routing and possible alternatives in Greece, surveying various 2-km wide corridors along the 500-km TAP route to determine the pipeline's optimal path.

TAP shareholders are Statoil, EGL, and E.On Ruhrgas.

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