OGJ Newsletter

Feb. 20, 2012
International news for oil and gas professional

GENERAL INTERESTQuick Takes

Swap dealer definition could harm some producers

A definition of swap dealer that the US Commodity Futures Trading Commission is expected to announce on Feb. 23 could hinder oil and gas producers and others using over-the-counter risk management tools, the Natural Gas Supply Association and National Corn Grows Association jointly said.

"A broad swap dealer definition appears imminent, given recent CFTC draft orders that progressively expand CFTC purview into physical commodity contracts used by commodity producers to hedge business risk inherent in the production of commodities," the two associations said in a Feb. 9 letter to White House Chief of Staff Jacob Lew and National Economic Council Director Gene B. Sperling.

The groups questioned the definition's breadth because entities designated as swap dealers cannot use the Dodd-Frank Law's enduser protections and will be subject to increased levels of margin and other collateral requirements and significant administrative burdens.

"If firms that are predominantly hedgers and traders are treated as dealers, $600 billion in capital currently at work in the economy as job creating investments by businesses with strong balance sheets and assets in the ground will be needlessly sidelined as collateral," NGSA and NCGA said in their letter.

Jenny Fordham, NGSA's vice-president for markets, said that as current envisioned, the CFTC's swap dealer definition would sweep producers and other businesses that use the OTC market to hedge into an unwieldy regulatory process that limits their access to risk management tools. "Ultimately these costs will find their way to consumers or come at the expense of business investment and growth," she suggested.

NGSA Pres. R. Skip Horvath said he was dismayed "that the CFTC is considering an action that is the exact opposite of what Congress intended when it created the Dodd-Frank Act."

Horvath said, "Rather than protecting consumers and reducing market risk, the CFTC will be raising market risk and raising consumer costs without any significant benefit to the US financial system."

Aramco, S-Oil sign long-term supply deal

Saudi Aramco has signed a rare long-term crude oil supply deal with S-Oil of South Korea in an apparent attempt to defray fears in the Asian country about supply losses from Iran.

Last month, the European Union's imposed sanctions (OGJ Online, Jan. 26, 2012).

The deal assures S-Oil, in which an Aramco unit is the largest shareholder with a 35% interest, of the crude it needs for its 669,000 b/d refinery at Onsan. Aramco has been filling most of the refinery's crude needs under contracts renewed annually.

The package of sanctions imposed by the EU in response to Iran's nuclear development, coupled with a toughening of sanctions in place in the US, embargoes purchase of Iranian crude by EU members and complicates financing by other countries.

South Korea recently has imported about 240,000 b/d of Iranian crude, about 10% of its supply.

PHMSA closes record number of enforcement actions

The US Pipeline and Hazardous Materials Safety Administration resolved a record number of enforcement actions during 2011, the US Department of Transportation reported.

DOT said PHMSA issued 102 final orders last year, the most in a single year following the 2002 passage of the original federal pipeline safety act.

PHMSA Administrator Cynthia Quarterman said that the increased enforcement stemmed from improved internal tracking procedures and rigorous investigations and inspections of pipeline facilities by the agency's field personnel.

"We will continue to conduct rigorous inspections to meet even more safety achievements in the future," she said.

DOT said that since 2008, PHMSA has issued 281 final orders to pipeline operators, constituting almost 40% of all the agency's final orders since 2002.

Exploration & DevelopmentQuick Takes

Lower Magdalena gets gas-condensate discovery

Pacific Rubiales Energy Corp., Toronto, said its Cotorra-1X well on the Guama block in Colombia's Lower Magdalena basin is a gas-condensate discovery in low-permeability Miocene Porquero Medio sands and silts.

Pacific Rubiales drilled Cotorra-1X following an earlier exploration success on the block, the Pedernalito-1X well drilled in 2010. Cotorra-1X, drilled to 7,210 ft, showed a total of 40 ft of net pay with average 20% porosity.

After cleanup while flowing through a ½-in. choke, Cotorra-1X reached a maximum 7.5 MMcfd of gas and 370 b/d of 56° gravity condensate followed by a three-stage isochronal and one extended flow test on a 12⁄64-in. choke that flowed at 2.6 MMcfd and 121 b/d at 3,137 psi wellhead pressure.

The well was perforated only in the deeper pay zone, across two intervals, leaving overlying pay zones untested for further evaluation.

Pacific Rubiales said the Cotorra discovery shows the potential of both the Guama block and the Lower Magdalena basin where the company has a large exploration acreage position and is looking to increase its gas reserves to support its initiative to export liquefied natural gas.

Woodside developing North West Shelf gas

Woodside Energy Ltd. is expanding development of North West Shelf Project natural gas fields off Western Australia and has begun letting contracts.

The Greater Western Flank (GWF) Phase 1 Project will develop Goodwyn GH and Tidepole gas fields with a subsea tieback to the Goodwyn A platform, which stands in 131 m of water (see map, OGJ, Oct. 17, 2005, p. 35).

The fields lie in 70-130 m of water about 130 km northwest of Karratha. They are among 16 fields southwest of Goodwyn A estimated to hold a total of as much as 3 tcf of recoverable natural gas and 100 million bbl of recoverable condensate.

Woodside expects production from Goodwyn GH and Tidepole to begin early in 2016. It didn't disclose rates.

The North West Shelf Project encompasses a gas plant and five-train LNG liquefaction and export complex at Karratha and delivers dry gas for domestic use.

For the GWF Phase 1 Project, FMC Technologies Inc. has a contract to design, manufacture, and supply six subsea production trees, six wellheads, two manifolds, subsea and topside controls, and flowline connection systems.

Technip will load out, transport, and install 16 km of 16-in. gas flow line between the Tidepole manifold and Goodwin A platform.

San Leon logs more potential gas pays in Poland

San Leon Energy PLC has cased its Siciny-2 well in Poland's Southwest Carboniferous basin after logging a previously unseen fourth potential Carboniferous section and a fractured tight gas sandstone.

Drilled to 3,520 m on the 100% owned, 800,000-acre Gora concession 70 km southeast of Zielona Gora, the Siciny-2 well had an initial goal of collecting core and downhole geophysical data focused on understanding the unconventional gas potential of the Carboniferous section. The well has achieved that goal, the company said.

The Carboniferous is known to be the source rock for the significant gas production in the overlying Permian Rotliegendes formation in Poland.

The stratigraphic test well reached TD of 3,520 m after penetrating some 1,000 m of Carboniferous section. More than 265 m of continuous core were collected across three prospective intervals identified in the Siciny-1 well. The previously unseen fourth potential Carboniferous shale section and a fractured tight gas sandstone were also encountered below 3,200 m.

San Leon will perform tight rock analysis on the core to evaluate the potential for commercial shale gas and tight gas sand production. It also obtained valuable data in drilling the complex structure of the Carboniferous section, allowing the company to reduce the time and cost of drilling future wells.

While drilling, continuous gas shows (C1-C3) were encountered across the four prospective shale intervals as well as through the tight sandstone interval. Evaluation and interpretation of the core and logs is expected to take 3-4 months in preparation for future production testing.

San Leon said the well encountered a total of more than 500 m of potential reservoir and that the complex nature of the Carboniferous source rock, including natural fracturing, shows real promise for gas production.

GeoPark acquires private Colombian explorers

GeoPark Holdings Ltd. has acquired Winchester Oil & Gas SA and La Luna Oil Co. Ltd., private exploration and production companies operating in Colombia, for $30 million cash adjusted for working capital.

The agreement also provides for certain contingent payments from production revenues as a result of successful future exploration.

GeoPark said it is acquiring the Winchester and Luna assets to form a nucleus around which it plans to build a meaningful long-term business in Colombia and to complement its expanding upstream business in Chile and Argentina.

The acquisition of Winchester-Luna provides GeoPark with 5-75% interests in eight blocks totaling 131,000 gross acres in the Llanos, Magdalena, and Catatumbo basins. GeoPark will operate two of the blocks. It plans to spend $20-30 million and drill 10 wells in Colombia in 2012.

The blocks produce 800 b/d net (1,230 b/d gross) from a net 2 million b/d of net proved and probable reserves and contain a mix of low-risk development potential and attractive exploration upside.

GeoPark operates nine blocks totaling 4 million gross acres in Chile and Argentina that produce 9,200 b/d of oil equivalent. GeoPark's 2012 work program of $100-120 million in Chile includes drilling 17-20 wells and shooting 600 sq km of 3D and 147 line-km of 2D seismic surveys.

Drilling & ProductionQuick Takes

Milnesand San Andres horizontal infill drilling nears

Enhanced Oil Resources Inc., Houston, has permitted five horizontal 20-acre infill wells in its 4,800-acre Milnesand San Andres Unit in Roosevelt County, NM, where 40-acre development is estimated to have recovered 14% of original oil in place.

EOR Inc., which owns San Andres legacy oil fields that cover a total of 25,000 acres, plans to drill laterals as long as 2,000 ft. It will drill the first three and review results, production, and economics. If successful the firm may drill as many as 30 more lateral locations in Milnesand and up to 100 in Chaveroo field.

Meanwhile, the company and Kinder Morgan CO2 Co. LP amended to Sept. 1, 2015, the initial date for deliveries of carbon dioxide to Milnesand and Chaveroo fields. Construction of a 40-mile, 8-in. pipeline to the fields from the Cortez CO2 pipeline would take 9 months. A path has been identified, and the company has negotiated right-of-way options.

The company also plans to drill wells this year in order to book reserves at the 20,000-acre Chaveroo field, where it carries no reserves at present.

EOR Inc. said, "The acquisition of legacy oilfields comes with tremendous opportunity for reserves and production growth, yet at the same time, we have to deal with poor well bore and surface conditions left by prior operators. Last year alone, we spent considerable time, effort and finances working over approximately 60 well bores, bringing 38 wells back to production and plugging and abandoning 12 wellbores.

"During 2012 we have allocated up to $1.7 million to work over, reactivate and plug several wells across our fields, with a focus towards getting our Chaveroo field into compliance. While we do not expect significant production growth from these endeavors, we expect that our considerable effort to right the wrongs of previous operators will ultimately reward us, longer term, with the required approvals to expand our infill programs across our fields and CO2 flooding of both Milnesand and Chaveroo."

The company may also make acquisitions near its existing fields, which produced a combined 900 b/d of oil in December 2011 and January 2012.

Noble's 2012 plans emphasize Marcellus drilling

Noble Energy Inc. plans to invest $1.25 billion in the Denver-Julesburg basin to expand its Niobrara horizontal drilling program and to spend $500 million in the Marcellus shale this year as part of a $3.5 billion budget that the firm outlined for 2012.

The capital program allocates 51% to onshore US, 7% to deepwater Gulf of Mexico, 22% to the Eastern Mediterranean and 14% to West Africa. Global exploration and appraisal activity is expected to receive 16%.

Charles D. Davidson, Noble Energy chairman and chief executive officer, said developments in the Niobrara and Marcellus continue to gain momentum and are expected to deliver consistent growth for years (OGJ Online, Nov. 15, 2011).

"Exploration remains a key component of the 2012 program as we plan to test a number of prospects throughout our focus areas," Davidson said.

Noble Energy plans to drill 173 horizontal wells and to maintain an active vertical well program in Wattenberg in 2012.

In the Marcellus shale where it has a joint venture with Consol Energy Inc., Nobel plans to support the drilling of 99 wells, targeting 39 operated wells in the liquids-rich area of the play.

In the deepwater gulf, Noble Energy expects to spend $250 million. Noble Energy's core international programs in West Africa and the Eastern Mediterranean represent $500 million and $750 million, respectively. Capital also was allocated to China, the North Sea, and several new venture opportunities.

Work to start on Tengiz field expansion

Tengizchevroil LLP expects to begin front-end engineering and design this year on a 250,000-300,000 b/d expansion of crude oil production capacity at supergiant Tengiz field in Kazakhstan, reports 50% partner Chevron Corp.

Average Tengizchevroil production in 2010 was 567,000 b/d of crude oil, 822 MMcfd of natural gas, and 44,000 b/d of natural gas liquids, Chevron says.

The expansion will use sour gas injection technology applied in a project under way since 2008. The technology separates about a third of the sour gas contained in the crude and reinjects it at very high pressure into the Tengiz reservoir.

Tengizchevroil also has begun FEED on a wellhead pressure management project to support current operations.

The expansion, pressure management, and drilling program will cost $20-25 billion, according to early estimates.

PROCESSINGQuick Takes

DCP Midstream plans gas plant for Permian basin

DCP Midstream LLC, Denver, will build a 75-MMcfd natural gas processing plant, dubbed the Rawhide plant, in Glasscock County, Tex., along with associated low-pressure gathering to handle Wolfberry production in Permian basin, the company announced today.

As part of the project, DCP also plans to expand its high-pressure gathering system to link its Goldsmith-Fullerton system with its Triad system. The Rawhide plant and gathering systems are to be in operation by mid-2013.

"Our strategy is to keep pace with the growth from this new phase of oil-driven development in the Permian," said Wouter van Kempen, president of DCP Midstream's gathering and processing business.

The Rawhide processing plant is the second phase of DCP's expansion for the liquids-rich Permian. That expansion began with plans to build the Sand Hills NGL pipeline that will move liquids from the Permian to fractionation along the Texas Gulf Coast and the Mont Belvieu, Tex., market hub by summer 2013 (OGJ Online, June 13, 2011). The expansion could also include construction of additional processing in the region if producer drilling continues to accelerate, said the announcement.

The plant and the gathering systems will expand DCP's footprint in the Permian, where it already owns and operates 17 processing plants with total capacity of 1.25 bcfd and produces more than 135,000 b/d of NGLs.

Tatarstan refinery to KBR conversion method

TAIF Group of Kazan, Tatarstan, Russia, has let a contract to KBR for licensing and engineering services to upgrade its Nizhnikamsk refinery with Veba Combi Cracker (VCC) technology (OGJ Online, Jan. 21, 2010).

The unit will boost the refinery's conversion depth to 90-95% and allow an increase in crude capacity to 7.3 million tonnes/year (tpy).

The refinery has a catalytic cracking unit brought on stream in 2006-07 but yields 28-29% low-quality heating oil, called mazut in Russia, which typically sells at prices below oil costs.

The VCC complex will have four inline hydrocracking units, three to upgrade bitumen and vacuum residue into a synthetic crude and a fourth functioning as a traditional hydrocracker yielding light products.

It will be able to process 2.7 million tpy of vacuum resid and 1.6 million tpy of distillates into petrochemical feedstock and Euro 5 diesel.

KBR licenses VCC technology under an agreement with BP, which absorbed the German firm Veba, developer of the method, in 2002.

KBR said the Tatarstan project is the third and largest VCC contract it has signed since entering the agreement with BP in January 2010.

Horizon bitumen upgrader idle until March

Canadian Natural Resources Ltd. said its Horizon Oil Sands Plant will be idle longer than initially expected after operations were suspended Feb. 5 for unplanned maintenance on the fractionating unit.

The bitumen upgrader can produce 110,000 b/d of synthetic crude oil. CNRL plans to increase output capacity in phases to 232,000-250,000 b/d (OGJ Online, May 2, 2011).

The company initially expected production to resume by mid-February but now believes the plant won't reach full production until mid-March. It said damage to the fractionator is "somewhat more extensive than originally thought."

It has lowered its projection for average 2012 production to 93,000-103,000 b/d of synthetic crude from 105,000-115,000 b/d because of the unscheduled downtime. Production in January averaged 81,000 b/d, down from 103,000 b/d in fourth- quarter 2011.

Last year, a Jan. 6 fire in the coker shut down the Horizon upgrader until Aug. 16 (OGJ Online, Aug. 23, 2011).

TRANSPORTATIONQuick Takes

Saddle Butte proposes Bakken oil pipeline

Saddle Butte Pipeline LLC, Durango, Colo., has begun a binding open season for capacity commitments on a proposed oil pipeline connecting Bakken shale production in North Dakota's Williston basin with a transport hub at Clearbrook, Minn.

The pipeline would be operated by Saddle Butte subsidiary High Prairie Pipeline LLC.

The 450-mile, 16-in. main pipeline would connect Alexander, ND, with existing pipeline and terminal facilities near Clearbook. High Prairie also proposes two laterals, one of 17 miles between Johnson's Corner, ND, and the proposed pipeline and the other of 8 miles connecting Robinson Lake, ND.

The system would have capacity of 150,000 b/d.

John Earley, Saddle Butte president and chief executive officer, cited projections that Bakken production will double to more than 1 million b/d by 2020.

Enterprise to expand ECHO crude oil terminal

Enterprise Products Partners LP purchased 37-acres of land adjacent to its Enterprise Crude Houston (ECHO) crude oil terminal, currently under construction in southeast Harris County, Tex., allowing expansion of the facility to 6 million bbl.

EPP said it is developing ECHO as a regional pricing point for the US Gulf Coast crude market and expects the project to begin service in the second quarter. ECHO's initial site, announced in late 2010, covered 150 acres (OGJ Online, Nov. 11, 2010) and had a planned 4.5 million bbl capacity.

ECHO will also serve as the receipt point for crude delivered from the Eagle Ford shale in South Texas. EPP is nearing completion of a 147-mile, 350,000-b/d pipeline also expected to begin service in the second quarter. Phase II of this pipeline, including an 80-mile extension into the far southwest portion of the Eagle Ford shale, is expected to enter service first-quarter 2013. Long-term contracts with shippers anchor both phases.

EPP cited ECHO's proximity to two large-diameter oil pipelines, including the Seaway system, as enhancing shipper flexibility in both Houston and Cushing, Okla.

EPP and its Seaway joint-venture partner Enbridge Inc. recently concluded an open season for capacity on both Seaway and a new pipeline running from ECHO to the Port Arthur-Beaumont refining center (OGJ Online, Jan. 5, 2012).

Discovery Gas lets Foster Wheeler offshore contract

Discovery Gas Transmission LLC awarded Foster Wheeler Upstream a contract to provide design, engineering, and technical services for a junction platform, facilities, and associated pipelines within the Discovery system at South Timbalier Block 283, in the Gulf of Mexico.

The platform, in 350 ft of water, will be a four-pile structure with a two-level deck. The platform will be designed as an unmanned structure with a control system designed to shut down in case of an upset. The new infrastructure will enable the existing Discovery pipeline to operate at a higher pressure, before and after connection of the new Keathley Canyon pipeline.

Williams Partners LP and DCP Midstream Partners LP plan to expand Discovery in the deepwater gulf by building the Keathley Canyon Connector, a 215-mile, 20-in. OD subsea gas gathering pipeline for production from the Keathley Canyon, Walker Ridge, and Green Canyon areas (OGJ Online, Jan. 19, 2012). Williams owns 60% of the Discovery system and operates it. DCP Midstream owns 40% of the system.

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