OGJ Newsletter

July 5, 2010

General InterestQuick Takes

Senate panel votes to remove spill liability cap

The US Senate Environment and Public Works Committee passed Sen. Robert Menendez's (D-NJ) bill to increase the offshore oil spill liability limit, with an amendment proposed by chairwoman Barbara Boxer (D-Calif.) to eliminate the liability cap for a party deemed responsible for an offshore spill.

"The catastrophe in the Gulf of Mexico makes it clear that the companies responsible must be held fully accountable for the damages they cause to the economy and the environment," Boxer said following the voice vote.

Menendez's original bill, S. 3305, would have raised the liability limit established under the 1990 Oil Pollution Act to $10 billion from $75 million. The amended measure now heads to the full Senate.

The committee's ranking minority member, James M. Inhofe (R-Okla.), said in an opening statement that he was disappointed that a compromise he proposed was not considered. He said he used language originally offered by Lisa Murkowski (R-Alas.), the Energy and Natural Resources Committee's ranking minority member, which would have let the president set liability caps based on water depth, estimated well pressure, a well's proximity to emergency response equipment and infrastructure, and a company's safety record.

The American Petroleum Institute said in a statement that the committee's action would make insurance for exploration and production activities in the gulf unavailable, effectively pushing out more than 100 US companies that are operating there and leaving the area to a few multinational oil companies and state oil firms.

"The accident in the Gulf of Mexico has shown us that we need to focus on safety and environmental protection," API Pres. Jack N. Gerard said. "But legislative proposals that would make domestic resources unavailable or uneconomic, instead of focusing on improving safety, must be turned aside."

DOI postpones public meetings on next OCS plan

US Interior Sec. Ken Salazar announced that public meetings about the environmental impact statement in the 2012-17 Outer Continental Shelf program will be postponed until later in the year so that safety and environmental issues can be more fully reviewed.

"Offshore oil and gas will remain an important element of our nation's energy portfolio…but we must ensure that decisions made about development are based on safe operations, ensuring protection of the environment, using the best science, and engaging in an open and transparent process," he said.

DOI published a notice of intent to prepare an EIS for the proposed program on Apr. 2 and scheduled the meetings during June and July in coastal areas that potentially would be affected. It said it would publish a notice later this year identifying a new public comment period and locations and dates of the public meetings.

BP unit fined for false reporting on tribal lands

The US Bureau of Ocean Energy Regulation, Management, and Enforcement (BOE) has fined BP America Inc. $5.2 million for submitting false, inaccurate, or misleading reports of energy production on Southern Ute Indian tribal lands in southwestern Colorado.

The civil penalty is not related to the Gulf of Mexico oil spill from BP PLC's Macondo well, the US Department of the Interior agency noted.

The errors were initially discovered in 2007 by Southern Ute tribal auditors working under a cooperative agreement with BOE's Minerals Royalty Management (MRM) program, BOE Director Michael R. Bromwich said on June 30. They brought the matter to BP America's attention in August 2007 and were instrumental in documenting the ongoing errors, he indicated.

Tribal and MRM auditors discovered that BP America reported incorrect royalty rates and prices for royalty purposes, and reported production on leases other than those to which the production could be attributed, according to BOE.

It noted that the company, after receiving audit issue notices and an order, agreed with auditors' concerns and repeatedly promised to correct the problems, which it attributed to errors in its automated files.

Tribal and MRM auditors examined later production reports to determine if BP had resolved the issue, as it had agreed, and found the same reporting errors, "leading us to conclude that BP's continued submission of erroneous reports was knowing or willful," Bromwich said.

The company can challenge the assessment through a DOI hearing procedure, he noted.

Industry Scoreboard

Exploration & Development Quick Takes

Total says drilling due on block off Brazil

Total SA said exploratory drilling will begin later this year on deepwater license BM-S-54 off Brazil, in which it has acquired a 20% interest.

Royal Dutch Shell PLC holds the remaining interest and operates the 700-sq-km block, which lies in 2,000 m of water about 200 km south of Rio de Janeiro.

The Santos basin block is near the Tupi, Iara, and Iracema presalt oil discoveries.

Drilling is subject to regulatory approvals.

Total says well planned on Yemen Block 72

Total has acquired a 36% interest in the 1,821-sq-km Block 72 production-sharing agreement in the southern Masila basin of Yemen and said an exploratory well is planned in the fourth quarter.

DNO Yemen AS operates the block. Other partners are TG Holdings Yemen Inc., Ansan Wikfs (Hadramaut) Ltd., and The Yemen Co. Total didn't report terms of the acquisition.

Block 72 abuts the southern border of Block 71, in which Total acquired a 40% interest in 2007. It's 150 km north of Bahlaf, site of the 6.7 million-tonne/year Yemen LNG liquefaction plant. Total holds a 39.62% in Yemen LNG.

Total operates East Shabwa Block 10, which abuts Block 71 to the east and holds interests in Marib region blocks—one of which, Block 18, produces gas piped to the LNG plant—to the west.

Colombia gets oil, gas find on Putumayo block

Gran Tierra Energy Inc., Calgary, will appraise the Moqueta-1 two-zone oil and gas discovery on the operated Chaza block in Colombia's Putumayo basin.

Gran Tierra will drill an appraisal well from the same pad and shoot 3D seismic on the block. Early production is to start in the first quarter of 2011.

Natural flow rates at the discovery well were as much as 349 b/d of 29° gravity oil on a 32⁄64-in. choke with 0.2% water cut from Caballos at 3,950-70 ft. The zone had 26 ft of net oil pay. The well also has a shallower Caballos zone with 27 ft of net gas pay.

The well also flowed 13 MMscfd of gas on a 48⁄64-in. choke from Villeta T sandstone perforated at 3,734-46 ft measured depth. The Villeta zone has 55 ft of net gas pay.

Gran Tierra plans to lay an 8-km pipeline to tie Moqueta-1 into the Costayaco infrastructure, with anticipated initiation of long term oil testing and early production in the first quarter of 2011.

Bottomhole location of Moqueta-2 will be 270 m east of Moqueta-1. The objective is to delineate the volume of the lower Caballos oil pool by targeting the reservoir 60 ft deeper down the flank of the structure. Moqueta-2 will also test the potential for a gas-oil contact in the Villeta U, Villeta T, and upper Caballos zones downstructure.

Pending results from Moqueta-2, Moqueta-3 would be drilled from a new pad 1.5 km southwest of the Moqueta-1 surface location.

Gran Tierra will shoot 230 sq km of 3D seismic over the Moqueta discovery and adjacent prospects and leads. This survey will overlap existing 3D surveys that cover Costayaco field; Juanambu, Toroyaco, Linda, Mary, and Miraflor fields in the adjacent Gran Tierra-operated Santana and Guayuyaco blocks; as well as the upcoming Verdeyaco 3D survey on the Chaza and Guayuyaco blocks.

Slawson, Voyager ink Niobrara oil venture

Voyager Oil & Gas Inc., Billings, Mont., will explore and develop 48,000 net acres prospective for oil in Cretaceous Niobrara held by Slawson Exploration Co. in the northern Denver-Julesberg basin.

Slawson will begin a continuous drilling program in early July with an initial series of three test wells expected to be completed by October. If results are good, Slawson will target 57 more locations throughout 2011. The acreage is in Weld County, Colo., near high-rate, horizontal Niobrara completions.

Voyager has purchased a 50% working interest in the 48,000-acre block for $7.5 million and will participate on a heads-up basis on all wells drilled, as well as participate for its proportionate working interest in all other acreage acquired in an area of mutual Interest consisting of all of Weld County and Laramie County, Wyo.

Voyager will fund the purchase price and initial drilling commitments out of cash on hand and cash flow from current production. Voyager remains fully funded through 2010 with no debt and $12.5 million of cash on hand.

Voyager controls 147,000 net acres in the following five primary prospect areas:

• 24,000 core net acres in the Bakken formation in North Dakota and Montana.

• 24,000 net acres targeting the Niobrara formation in Colorado and Wyoming.

• 640 net acres on a Red River prospect in Montana.

• 33,500 net acres in a joint venture targeting the Mississippian Heath shale formation in Musselshell, Petroleum, Garfield, and Fergus counties, Mont.

• 65,000 net acres in a joint venture in Tiger Ridge gas field in Blaine, Hill, and Chouteau counties, Mont.

Drilling & ProductionQuick Takes

Hurricane Alex forces evacuations in gulf

Operators removed workers from platforms and rigs in the Gulf of Mexico in anticipation of Hurricane Alex last week.

The US Bureau of Ocean Energy Management, Regulation, and Enforcement (BOE) reported on June 29 that 28 platforms and 3 rigs had been evacuated, resulting in the shut-in of 396,000 b/d of oil and 600 MMcfd of gas production.

The shut-in production's shares of gulf totals are 25% of oil and 9% of natural gas.

Before the evacuations, 51 rigs were work in the gulf, which has 634 manned platforms.

The storm was expected to make landfall in northern Mexico late June 30. It did not disrupt work on the oil spill from the Macondo well blowout off Louisiana.

Venezuela threatens to nationalize H&P rigs

Venezuela's Petroleos de Venezuela SA last week sought permission from the country's National Assembly to seize control of 11 drilling rigs owned by Tulsa-based Helmerich & Payne.

"There are rig owners that have refused to discuss with
PDVSA the payment rates for services and preferred to hide the rigs for a year in Anaco, Anzoategui state," said Oil Minister Rafael Ramirez. "It's the specific case of H&P, a US multinational."

Ramirez, who is also president of PDVSA, said "sectors opposed" to the Venezuelan government are trying to "stymie the production of crude in the country," while PDVSA said that seizure of the H&P rigs "will foment national hydrocarbon production and strengthen the policy of full oil sovereignty."

H&P said it idled the rigs due to "unpaid invoices corresponding to services rendered in prior years" and that that it would be "willing to enter new drilling contracts for drilling work in Venezuela if and when significant progress was achieved in terms of such receivable collections and currency conversion."

According to H&P Chief Executive Officer Hans Helmerich, "Our dispute with PDVSA has never been very complicated and our position has remained clear: We simply wanted to be paid for work already performed. We stated repeatedly we wanted to return to work, just not for free. We have worked in Venezuela for 52 years and wanted to continue under reasonable conditions.At the same time, H&P has reduced its number of rigs in Venezuela in half since 1998. At that point, almost 30% of our land rigs were in that country, as compared to under 5% of our land rigs today."

The US government said Venezuela must compensate H&P if its seizure of the rigs goes through. "We would call on them if they did make such a move to compensate the owners of those wells," said Mark Toner, acting deputy spokesman at the US Department of State.

Toner said this latest move by President Hugo Chavez's government to nationalize assets of foreign companies "doesn't speak well or bode well for the investment climate" in the Latin American nation.

DOE extends stripper well consortium to 2015

The US Department of Energy extended to 2015 the Stripper Well Consortium, which has provided and transferred technological advances to small independent oil and gas producers for the past 9 years, DOE's Fossil Energy Office announced on June 23.

FEO said the industry-driven consortium, which was initiated in 2000, aims to keep wells that produce fewer than 10 b/d of oil or 60,000 cfd of natural gas operating in an environmentally safe manner. In addition to small upstream independents, it said that the group includes service and supply companies, trade associations, universities' petroleum engineering departments, industry consultants, and entrepreneurs.

The more than 396,000 US marginal, or "stripper" oil wells account for nearly 800,000 b/d, or about 10% of production in the Lower 48 states, FEO indicated. More than 392,000 stripper gas wells produce more than 1.7 tcfd, or 9% of the gas recovered in the Lower 48, it added.

Nearly 100 projects have been funded since the consortium's initiation, according to FEO. It said that successes include the Gas Operated Automatic Lift PetroPump developed by Brandywine Energy Co., which removes fluid from the well bore more consistently than traditional plunger lift systems; Vortex Flow Tools LLC's vortex flow unit, which operates in a manner similar to a tornado and uses produced gas to accelerate water velocity, reduce water friction, and assist in lifting and removing fluids; and Pumping Solutions Inc.'s new hydraulic diaphragm submersible pump to continuously clean stripper wells.

Oil production starts from Maule in North Sea

Houston independent Apache Corp. reported that its Maule field in the UK North Sea has started oil production at 11,750 b/d. The field, in which Apache holds 100% interest, was brought on production 8 months following the October 2009 discovery, the company said.

"The Maule discovery, which is an Eocene-age reservoir located above the main Forties Paleocene reservoir, was identified by Apache's North Sea geoscience team using its extensive experience with seismic interpretation in the area. We were able to develop the field quickly via our existing infrastructure within the Forties field," said James L. House, region vice-president and managing director of Apache North Sea Ltd. "The viability of the project was enhanced by the UK government's incentives aimed at encouraging development of smaller fields in the North Sea."

Apache plans a second well at Maule.

Apache also reported that it will proceed with development of the Bacchus field, a Jurassic discovery 4 miles northeast of the Forties Alpha platform. Apache is planning three horizontal subsea wells tied back to Forties Alpha via a pipeline bundle. Apache owns a 70% working interest at Bacchus. Other partners include Royal Dutch Shell PLC 20% and Endeavour 10%. First oil is expected in mid-2011.

Processing— Quick Takes

Appalachian oil runs drop laid to Marcellus

A shift in drilling emphasis from conventional to unconventional plays the past 2 years, particularly the Marcellus shale, has resulted in a substantial drop in crude oil production available to refiners in the Appalachian basin, said Ergon Oil Purchasing Inc.

Ergon, which operates refineries in West Virginia, Arkansas, and Mississippi, said the average load volume of crude oil it purchases from tank batteries in the basin is shrinking.

The company enacted a tier posted price schedule under which it pays $2-3.50/bbl less than its posted price to truck less-than-full loads from leases. The changes took effect June 1.

Ergon said, "To remain competitive with our finished products, it is important that we deliver crude oil to our Newell, W.Va., refinery at a price competitive to refineries with lower gathering, storage, handling, and transportation costs. This is extremely difficult due to the age and geography of the Appalachian basin."

The 20,000-b/d Newell refinery processes 100% Appalachian grade paraffinic crude oils, particularly Pennsylvania grade gathered from 40,000 points throughout Ohio, Pennsylvania, West Virginia, Kentucky, and New York, Ergon said.

Ergon pays full posted price for loads of 156 net bbl of crude oil or more from one or more tanks at a single location. If basic sediment and water exceeds 2%, however, the price paid is subject to tier two posting.

Tier two posting covers loads of 60-155.99 net bbl of crude oil from one or more tanks at a single location at $2/bbl less than Ergon's posted price, and tier three posting applies to loads of 30-60 net bbl of crude oil at $3.50/bbl less.

Transportation — Quick Takes

PetroChina lets contract for WEPP 3 line

PetroChina awarded Rolls-Royce a contract to provide three RB211 natural gas turbine compressor systems for its third West-East Pipeline Project (WEPP 3), bringing 15.5 billion cu m/year of gas from Shaanxi in western China to Beijing.

The units will be installed at the pipeline's first compressor station in Yulin, Shaanxi province. The 820-km pipeline will cross three provinces before terminating in Beijing. Gas transported will originate from supplies in Turkmenistan shipped via the Central Asia-WEPP 2 pipeline and from China's Tarim basin via WEPP 1.

PetroChina expects to bring WEPP 2 into service late this year or in early 2011. The Chinese trunkline section covers 3,400 miles, connecting Xinjiang province to Guangzhou and Shanghai. The development also calls for 1,240 miles of branch lines. WEPP 2 will transport 30 billion cu m/year (OGJ, Feb. 15, 2010, p. 46).

This latest order brings to 28 the total number of units supplied by Rolls-Royce to PetroChina for pipeline service.

Enbridge to pursue Waupisoo pipeline expansion

Enbridge Inc. announced June 28 entering into shipper commitments totaling 229,000 b/d of capacity on the Waupisoo Pipeline, part of its Regional Oil Sands System. Enbridge will undertake a $400 million expansion of the Waupisoo to its maximum capacity to accommodate these commitments, which include additional volumes announced February.

The Waupisoo line expansion will provide about 65,000 b/d of additional capacity in second-half 2012 and a further 190,000 b/d when fully in service in second-half 2013.

The 380-km Waupisoo system entered service in 2008 with an initial capacity of 345,000 b/d. This expansion will bring the line to its 600,000 b/d design capacity between Enbridge's Cheecham terminal, south of Fort McMurray, and Edmonton, via the company's Stonefell terminal near Bruderheim, Alta. The pipeline links oil sands producers to their upgraders and refineries in the Edmonton area as well as to connections with Canada's interprovincial oil pipeline systems.

Enbridge said that based on development activity under way within the oil sands on both existing and new projects it expects to see further opportunities for expansion of its system moving forward.

BG Group gets approval for CSG-LNG project

BG Group has received conditional approval from the government of Queensland for its proposed 8.5 million tonne/year coal seam gas-to-LNG project on Curtis Island near Gladstone on the state's east-central coast.

The government has completed its review of the project's environmental impact statement and has given approval, pending some strict conditions.

These include community and social benefits such as the provision of affordable housing for Gladstone and the surrounding region. BG also will have to develop a plan to maximize participation by local and Queensland suppliers.

BG's board is expected to consider a final investment decision before yearend. Federal government approval is expected by mid-2011.

The LNG plant will be fed by gas production from coal seam gas fields in the Surat and Bowen Basins to the west flowing through a 540-km pipeline network to the Curtis Island plant.

Production is expected to begin in 2014, underpinned by supply agreements including a 20-year, 3.6 million tpy deal with CNOOC; a 2-year, 1.7 million tpy agreement with Chile; and a 20-year agreement to supply as much as 3 million tpy to Singapore.

Timor Leste continues fight for Greater Sunrise

Timor Leste continues to push for the Woodside Petroleum Ltd. joint venture's Greater Sunrise LNG project to be developed on its shores.

Government spokesman Agio Pereira said recently that he expects to present a development plan later this year for a $3.8 billion LNG plant to be built on the country's southern coast.

This runs in the face of Woodside's April 2009 announcement that the JV has decided on floating LNG (FLNG) as the preferred processing option for Greater Sunrise in the Joint Petroleum Development Area of the Timor Sea. This would use Shell's FLNG technology, which Woodside said would deliver the best commercial benefits to Australia and Timor Leste.

Woodside believes that piping gas to Timor Leste across the Timor Trench would cost $5 billion more than the FLNG option. It also presents major technical risks surrounding the construction, maintenance and operation of a pipeline in the trench because of the deep water and the region's seismic activity.

The fields lie 450 km northwest of Darwin and contain an estimated 5 tcf of gas and 226 million bbl of condensate.

A final investment decision is expected for the project in 2012 with first LNG scheduled for 2016.

Analysts suggest that diplomatic tensions will be an ongoing issue, some suggesting the project has only a 30% chance of going ahead.

The JV comprises Woodside 33.4%, ConocoPhillips 30%, Shell 26.6%, and Osaka Gas 10%.

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