OGJ Newsletter

Dec. 19, 2005
Worldwide exploration and production expenditures are likely to rise “materially” in 2006, Lehman Bros. said in its annual E&P Spending Survey.

General Interest - Quick Takes

Global E&P outlays to rise ‘materially’ in ’06

Worldwide exploration and production expenditures are likely to rise “materially” in 2006, Lehman Bros. said in its annual E&P Spending Survey.

The report noted that the 325 companies surveyed plan to increase their worldwide E&P expenditures by 14.7% from 2005 levels to $238 billion in 2006.

In the US, E&P outlays by 247 of the surveyed companies are expected to rise by 14.9% to $57 billion. “All types of companies that operate in the domestic market-small-to-large independents and major oil companies-are budgeting significant increases in their 2006 budgets,” the study said.

Outside North America, E&P spending is forecast to increase 14.9% to $156 billion in 2006. This is up from $135 billion spent in 2005 by the 85 companies surveyed by Lehman Bros.

Canadian E&P spending is expected to rise 13.3% to $24.7 billion. “Larger E&P companies continue to drive spending growth in the country, with those companies that spend over $100 million expected to raise spending by 13.6% next year while those companies that spend less than $100 million are only budgeting increases of 7.1%,” the survey noted.

Lehman Bros. found that the prices at which companies would cut drilling budgets are “well below current commodity prices.” The survey found that companies would begin cutting budgets if oil prices fell below $45/bbl and if gas prices fell below $6-6.50/Mcf. E&P budgets for 2006 are based upon an average West Texas Intermediate oil price of $49.89/bbl and a gas price of $7.64/Mcf.

“We believe that budgeted spending gains will prove to be conservative due to oil and gas prices remaining high and drilling cost increases being above company forecasts,” Lehman Bros. said.

BP to invest $1 billion in refinery after explosion

BP Products North America Inc. Dec. 9 released its final incident investigation report on the Mar. 23 Texas City, Tex., refinery explosion and fire (OGJ Online, Mar. 23, 2005). The company said it plans to invest about $1 billion to improve and maintain the site over the next 5 years.

While many of the actions recommended by investigators are under way, some actions have been completed. Among the work, the company will install modern process-control systems on major units, transition to a more powerful maintenance management system, improve worker training, and remove blowdown stacks, the report said.

BP said that the investigation team “found no evidence of anyone consciously or intentionally taking actions or decisions that put others at risk.” However, “the team found many areas where procedures, policies, and expected behaviors were not met.”

According to the report, BP found that the “underlying reasons for the behaviors and actions displayed during the incident are complex” and that it was “evident that they had been many years in the making....”

Critical factors that led to the explosion were identified in an interim report published May 17 (OGJ Online, May 18, 2005). The final report also identifies the following underlying causes:

• “Over the years, the working environment had eroded to one characterized by resistance to change, and lacking of trust, motivation, and a sense of purpose. Coupled with unclear expectations around supervisory and management behaviors this meant that rules were not consistently followed, rigor was lacking, and individuals felt disempowered from suggesting or initiating improvements.

• “Process safety, operations performance, and systematic risk reduction priorities had not been set and consistently reinforced by management.

• “Many changes in a complex organization had led to the lack of clear accountabilities and poor communication, which together resulted in confusion in the workforce over roles and responsibilities.

• “A poor level of hazard awareness and understanding of process safety on the site resulted in people accepting levels of risk that are considerably higher than comparable installations. One consequence was that temporary office trailers were placed within 150 ft of a blowdown stack, which vented heavier than air hydrocarbons to the atmosphere without questioning the established industry practice.

• “Given the poor vertical communication and performance management process, there was neither adequate early warning system of problems, nor any independent means of understanding the deteriorating standards in the plant.”

ExxonMobil cites June accord in Cepu flap

ExxonMobil Oil Indonesia Inc. will fight state-owned PT Pertamina for operatorship of the Cepu Block, according to Pres.-Director Peter J. Coleman, who cited a memorandum of understanding signed in June.

“ExxonMobil will continue to hold out that position (as sole operator),” Coleman said. “Let’s go back to that [MOU]; that’s the basis, and we are ready to move forward,” he said, referring to the document that made ExxonMobil operator for the 30-year duration of the contract.

In Jakarta, Coleman told reporters that ExxonMobil has offered Pertamina key management positions associated with the Cepu Block and said that the offer addressed Pertamina’s aim for a larger role in the project (OGJ Online, Dec. 8, 2005).

Industry Scoreboard

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Exploration & Development - Quick Takes

Major oil discovery reported in western Iran

Norsk Hydro AS and Lukoil Overseas Holding Ltd. reported a “major oil discovery” on the Anaran exploration block in Ilam Province near Dehloran in western Iran (OGJ Online, Aug. 30, 2000).

Located in the Zagros belt, Iran’s most productive petroleum province, the 3,500 sq km Anaran block contains four prospects: Azar, Changuleh-West, Dehloran, and Musian.

An exploration well on the Azar prospect discovered Anaran field. The well produced crude at commercial rates in July. Norsk Hydro specialists said Anaran could be producing as much as 100,000 b/d of oil by 2010.

Lukoil Overseas, a 25% partner, said the discovery could become “one of the most significant oil finds over the past several years.” Norsk Hydro holds the other 75% of the block.

Norsk Hydro currently is drilling the Changuleh-West exploration well, the third of five wells required on the block, three exploratory and two appraisal.

The licensees hope to begin Anaran field development by March 2006 after National Iranian Oil Co. reviews the companies’ commercialization report.

Oil production starts from Yemen’s Block 9

Calvalley Petroleum Inc., Calgary, has started production from Hiswah oil field on Malik Block 9 in Yemen. Calvalley is the operator and has 50% working interest.

The Hiswah-6 horizontal well went on stream Dec. 10. Initial production is constrained to 2,000 b/d by the capacity of a terminal to which the oil is being delivered by truck. This bottleneck is expected to be relieved within 2 months, when Calvalley expects production of 10,000 b/d of oil.

Calvalley is designing and building a pipeline that it expects to be operational in the fourth quarter of 2006.

Four other Hiswah wells are expected to be brought on stream during the next few months. Calvalley completed its fifth horizontal development well in the Sayun-Masila basin last month (OGJ Online, Nov. 21, 2005).

Calvalley estimates full productive capacity from existing wells on Block 9 to be more than 20,000 b/d. The company declared Block 9 commercial after four discoveries (OGJ Online, June 23, 2005).

Seismic survey starts on Hassi Mouina block

A seismic survey is under way on the Hassi Mouina gas block in Algeria, reported Statoil ASA, the operator. Plans call for a wildcat to be spudded during 2006.

Statoil has 75% interest in the block, and Algeria’s state oil and gas company Sonatrach has 25% interest.

The block covers 22,993 sq km in the Timimoun basin. Sonatrach previously drilled one well in the block and discovered gas, which Statoil will develop (OGJ Online, July 28, 2004).

The work program in the 3-year mandatory exploration phase for the block covers two wells and acquisition of 400 km of 2D seismic data. In addition, Statoil will negotiate with Sonatrach on an appraisal program for the discovery. An optional 2-year exploration phase covers one well and 100 km of 2D seismic data.

Saipem to install six KMZ platforms for Pemex

Pemex Exploracion y Produccion has let contract to Saipem SPA for offshore transport and installation of six platforms in the Ku-Maloob-Zaap (KMZ) fields development project in the Bay of Campeche, 105 km northwest of Ciudad del Carmen, Mexico.

Pemex is installing a total of 18 platforms in the KMZ complex over 5 years to raise production to 800,000 b/d of oil and 600 MMscfd of gas (OGJ, Feb. 2, 2004, Newsletter).

Firms sign EPSAs for areas in and off Libya

ExxonMobil Libya Ltd. has signed an exploration and production-sharing agreement (EPSA) with Libya’s National Oil Corp. for the large offshore Cyrenaica basin Contract Area 44.

The area, with four blocks covering a total of 2.5 million acres in 100-10,000 ft of water, was offered in Round 2 of Libya’s EPSA IV licensing in October (see map, OGJ, Oct. 24, 2005, p. 42).

Separately, BG Group PLC has signed EPSAs for onshore Libyan Blocks 123 (1) and 123 (2), in the Sirte basin and onshore Area 171 (Blocks 1, 2, 3, and 4), in the Kufra basin (see map, OGJ, Oct. 24, 2005, p. 42).

BG owns 100% of and will operate the EPSAs for Blocks 123 (1) and 123 (2), which cover a total 4,750 sq km, and holds a 50% interest in the EPSA for Area 171, which covers 11,000 sq km, in partnership with Statoil ASA, the operator.

The EPSA work obligation for the two blocks involves acquiring seismic data and drilling one exploration well on each block. The EPSA work obligation for Area 171 involves acquiring seismic data and drilling two exploration wells.

MMS again proposes Cook Inlet Sale 199

The US Minerals Management Service again is soliciting indications of industry interest in Cook Inlet Sale 199, involving 2.5 million acres of federal land south of Kalgin Island 3-30 nautical miles off Alaska. Water depths are 30-650 ft.

It proposes a lease sale in May 2007. Earlier this year, MMS postponed initial plans for a May 2006 sale of leases in the area because of a lack of industry interest.

Cook Inlet Sale 191, held in May 2004, received no bids (OGJ Online, May 19, 2004).

Devon signs contract for block off China

Devon Energy Corp. has signed a production-sharing contract with China National Offshore Oil Corp. for South China Sea deepwater Block 42/05, subject to Chinese government approval.

The Oklahoma City independent will operate the block with 100% interest. CNOOC has the option to acquire a 51% interest in the event of a commercial discovery. Devon agreed to conduct a 3D seismic survey and to drill exploratory wells.

Block 42/05 covers 2,700 sq miles. Water depths are 650-6,500 ft.

Drilling & Production - Quick Takes

Rowan unit lets contract for Tarzan jack up

Rowan Cos. Inc. subsidiary LeTourneau Inc., Houston, has let a contract to Signal International LLC, Pascagoula, Miss., for a fourth Tarzan-class jack up (OGJ, July 14, 2005, p. 56).

LeTourneau will provide a license to Signal International and furnish the engineering and component kit for the elevating system, including 445 ft leg length. LeTourneau Ellis Williams Co. Inc., also a subsidiary of Rowan Cos., will provide the drilling equipment package.

The Tarzan IV will be built at Signal’s facility in Orange, Tex., with delivery scheduled for the third quarter of 2007.

South Texas tar cyclic steam pilot shapes up

A two-well cyclic steam pilot to test feasibility of producing shallow tar in the Maverick basin may be close to start-up.

Exploration Co., San Antonio, and Newmex Minerals Inc., Calgary, are awaiting regulatory approvals that Newmex said are expected shortly. TXCO drilled two wells to the Upper Cretaceous Lower San Miguel sandstone on its Chittim B lease earlier this year (see map, OGJ, Oct. 4, 2004, p. 30).

The companies, which have a large lease block in Maverick and Zavala counties, plan to apply cyclic steam stimulation and truck produced tar 100 miles to a heavy oil processing facility. If the pilot succeeds, the initial development plan takes in 514 sq miles.

Newmex said a report on its acreage prepared by consulting engineers described the tar as “one of the most dense, viscous, and sulphur-laden hydrocarbon deposits in the world.

“The gross thickness of sand varies from approximately 20 to 80 ft (6.1 to 24.4 m). The tar saturations range from 20% to 60% but seldom average greater than 55% in a continuous 25 ft (7.6 m) interval.”

Previous uneconomic pilot projects in earlier decades recovered tar of 2° to minus 2° gravity from accumulations at 2,000 ft or less in the San Miguel. Tar at one of the earlier pilots was essentially a solid at 95° F. reservoir temperature, had a 500° F. initial boiling point, and contained more than 10 wt % sulfur.

Transeuro to explore in Papua New Guinea

Transeuro Energy Corp., Vancouver, BC, opened an office in Port Moresby to support exploration and development of its four petroleum prospecting licenses in Papua New Guinea.

Preliminary mapping shows more than 80 prospects on the four blocks, many of which are in the main oil and gas discovery fairway and many of which have oil seeps and prominent surface features. Seismic remapping will start in early 2006.

Transeuro holds PPL 259 in the foreland part of the Papuan fold belt adjoining the border with Papua, Indonesia, PPL 260 in the Papua New Guinea highlands, PPL 258 in the Sepik area of the North Niugini basin, and PPL 257 in the Cape Vogel basin.

Block 259 covers 6,480 sq km surrounding the Santos Ltd.-operated undeveloped Stanley, Elevala, and Ketu gas-condensate discoveries and is 50 km south of the undeveloped Pnyang gas-condensate find. It is 75 km west of the country’s main producing trend including the 5.4 tcf Hides gas-condensate discovery and the 3.33 tcf Angore and 1.56 tcf Juha discoveries, which will feed a planned gas pipeline to Queensland.

Transeuro sees geology on 6,237 sq km Block 260 being similar to that in the Papuan fold belt, which is producing 50,000 b/d of sweet crude and has 15 tcf of proved recoverable gas.

PPL 258 covers 1 million acres, and Block 257 covers 1.7 million acres.

Norne oil discharge larger than thought

The Nov. 23 oil spill at Norne oil and gas field in the Norwegian Sea was larger than initially reported, said field operator Statoil ASA.

Statoil’s calculations now show that about 2,140 bbl of oil, not 280 bbl, were discharged.

The new estimate is based on data from incident logs aboard the Norne production and storage ship. The first estimate was “calculated according to the dimensions of the slick” based on aerial observations by Statoil and the Norwegian National Coastal Administration, Statoil said.

Preliminary findings indicate failure of facilities being shut down to allow modification to the production’ vessel’s process control system (OGJ Online, Nov. 28, 2005). The failure allowed oil to enter the system that treats produced water and to be discharged into the sea.

Bad weather prevented collection of the oil. The area was monitored by helicopter until Dec. 4. No oil has been observed on the surface since Nov. 24, and satellite pictures show no further indications of a spill.

Processing - Quick Takes

Mombasa refinery upgrade design under study

Kenya Petroleum Refineries Ltd. (KPRL) has awarded a contract to Foster Wheeler Energy Ltd. to prepare the “basis of design” for an upgrade of its 85,500 b/cd hydroskimming refinery and for a products import terminal at Mombasa, Kenya.

The refinery, with two trains, has catalytic reforming capacity of 8,100 b/cd and catalytic hydrotreating capacity of 36,000 b/cd. The upgrade will allow production of products meeting specifications required under the Dakar Declaration whereby Kenya must begin using unleaded gasoline and low-sulfur diesel by January 2006. It is expected to satisfy Kenya’s future demand for products, including domestic consumption beyond 2015 and LPG for export.

The contract calls for Foster Wheeler to produce a technical definition and duty specifications for the licensed units, a project execution plan, and cost estimate for the upgrade.

KPRL shareholders are the Kenya government 50%, Royal Dutch Shell PLC 17.1%, BP PLC. 17.1%, and ChevronTexaco Global Energy Inc. 15.8%.

Japan Energy plans aromatics complex

Japan Energy Corp. will invest ¥70 billion to build a 580,000 tonne/year (tpy) aromatics complex and a 60,000 b/sd condensate splitter at the 190,000 b/sd Kashima Oil Refinery.

The new complex, which will use Axens technologies, is scheduled to start up in early 2008.

The complex will produce 410,000 tpy of paraxylene and 170,000 tpy of benzene from a feedstock of 20,000 b/sd of heavy naphtha from imported condensate.

Petrobras, PDVSA to build heavy-oil upgrader

Brazil’s state-run Petroleo Brasileiro SA (Petrobras) and Venezuela’s Petroleos de Venezuela SA plan to jointly build a heavy-oil upgrading plant in Venezuela that would cost about $1 billion, Petrobras announced.

The plant would convert heavy oil from Venezuela’s Orinoco belt into crude that can be processed at a refinery to be built as another joint project in northeastern Brazil, said Petrobras International Director Nestor Cervero.

The upgrader would treat production from a jointly operated field that is to start up at a rate of as much as 200,000 b/d in 2009, Cervero said.

Sabic lets EPC contracts for Yansab plants

Saudi Arabia’s Saudi Basic Industries Corp. (Sabic), Riyadh, has awarded a contract to Technip Italy of Rome for the engineering, procurement, and construction (EPC) of an ethylene and propylene plant at its Yansab complex at Saudi Arabia’s Yanbu Industrial City.

When completed, the Yansap Red Sea complex will produce 1.3 million tpy of ethylene and 400,000 tonnes/year (tpy) of propylene. Production is scheduled to start in 2008.

Sabic also awarded Toyo Engineering Corp. of Japan an EPC contract for a 700,000-tpy ethylene glycol plant at the site (OGJ Online, July 20, 2005).

Yansab will be one of the world’s largest petrochemical industrial complexes, with a total capacity of more than 4 million tpy of various products, including 900,000 tpy of polyethylene, 400,000 tpy of polypropylene, 250,000 tpy of benzene, xylene, and toluene, and 100,000 tpy of butene-1 and butene-2.

Yansab is owned 55% by Sabic and 10% by its affiliates Ibn Rush and Tayf (17 Saudi and Persian Gulf companies). Sabic plans to offer the remaining 35% for public subscription.

Transportation - Quick Takes

NGPL signs A/G line-expansion contracts

Natural Gas Pipeline Co. of America (NGPL), a subsidiary of Kinder Morgan Inc., has signed long-term contracts with shippers for an expansion of capacity of a 95-mile section of its 800-mile Amarillo, Tex., to Gulf Coast pipeline (A/G line).

The $16 million project includes installation of 9,500 hp at a new compressor site in Morris County, Tex. It will increase capacity by 139,000 dekatherms/day to 801,000 dekatherms/day.

The project is expected to be commissioned by Oct. 31, 2006, subject to regulatory approvals.

NEGP gas line construction begins in Russia

Construction of the 917 km onshore portion of North European Gas Pipeline Co.’s (NEGP) pipeline to carry Siberian gas to Germany began Dec. 9 at Babayevo, Russia, 800 km east of St. Petersburg.

The 56-in. onshore line will connect existing pipelines from Siberian gas fields with a planned transmission line across the Baltic Sea from Vyborg, Russia, to near Greifswald, Germany.

NEGP is a consortium of Russia’s OAO Gazprom, with 51% interest, and Germany’s BASF AG and E.ON AG, 24.5% each.

The onshore system will include seven compressor stations delivering an operating pressure of 100 bar.

The planned subsea pipeline will be longer than 1,200 km and have a diameter of 48 in. and an operating pressure of 210 bar.

When commissioned in 2010, the system capacity will be 27.5 billion cu m/year (bcm/year). A possible second pipeline would double capacity (OGJ Online, Sept. 21, 2005). Total capital expenditure for the offshore part of the project, if both pipelines are built, would exceed €4 billion.

NEGP said it will conduct further economic, technical, and ecological studies for construction of the subsea pipeline.

In other systems delivering Russian gas to Europe, expansion of the existing Jamal-Europe pipeline through Belarus and Poland has increased gas transport capacity to 29 bcm/year from 22 bcm/year. In a final expansion phase, capacity will increase further to 33 bcm/year following start-up of an additional compressor station in 2006.

New deal near for sale of Gorgon LNG

Chevron Australia Pty. Ltd. and Japanese power company Osaka Gas Co. Ltd. have signed a heads of agreement for the sale of 1.5 million tonnes/year (tpy) of LNG from Gorgon project in Australia over a period of 25 years, beginning in 2010.

Chevron’s announcement did not disclose terms of the deal, but the firm said the parties are also discussing the potential transfer of an equity interest in the Gorgon project-an arrangement similar ones it has made with other Japanese power companies.

The agreement with Osaka follows one struck by Chevron in November to sell 1.5 million tpy of LNG to Chubu Electric Co. from the Gorgon development, and another one struck by Chevron in October to sell 1.2 million tpy of LNG to Tokyo Gas Co. (OGJ, Nov. 28, 2005, Newsletter).

Gas for the project will come from the Gorgon complex of fields 130 miles off Western Australia (see map, OGJ, Oct. 17, 2005, p. 35).