OGJ Newsletter

Jan. 19, 2009
General Interest — Quick Takes

Oil, gas equipment sales likely to slow in 2009

Global oil and gas equipment sales are expected to be slow for much of 2009 because of the economy and slumping oil prices in late 2008, said Freedonia Group Inc., a Cleveland industry research group.

The oil field equipment market is forecast to increase 2.9%/year during 2008-12 to reach $85 billion in 2012. Freedonia said this growth rate is a drastic deceleration from the 15.2%/year growth during 2002-07.

In its world oil field equipment study, Freedonia said the most rapid equipment demand growth through 2012 will come from a few countries in the developing world, especially Brazil, China, and Kazakhstan.

Nigeria and Angola also hold strong growth prospects if regional politics and the economy remain relatively stable, Freedonia said.

Natural gas drilling is forecast to grow especially fast in China and Qatar. In contrast, field maturity and declining production in the US, Mexico, Venezuela, Norway, and UK will suppress equipment markets in those countries.

“In Mexico and Venezuela, growth could become stronger if foreign, technologically advanced energy companies are allowed greater rights to drilling and exploration activities, a domain that is currently monopolized by inefficient state-controlled entities in both countries,” Freedonia said.

Industry is expected to become more reliant on high-technology services such as directional drilling control and real time logging and measurement-while-drilling techniques.

“Despite the overall market exhibiting weak gains through 2012, prospects for certain products are more favorable, particularly for fixed-cutter drill bits and advanced well logging equipment,” Freedonia said.

Large tubular goods markets are expected to benefit from increased drilling efficiency and gains in casing demand being bolstered by a trend toward greater footage drilled per rig.

US, Georgia sign accord on defense, energy

The US and Georgia have agreed to step up physical security of energy transit across the trans-Caucasus to European markets as part of the US-Georgia Charter on Strategic Partnership signed Jan. 9.

“We intend to build upon over a decade of cooperation among our two countries and Azerbaijan and Turkey, which resulted in the Baku-Tbilisi-Ceyhan and Baku-Supsa oil pipelines and the Baku-Tbilisi-Erzurum natural gas pipelines, to develop a new Southern Corridor to help Georgia and the rest of Europe diversify their supplies of natural gas by securing imports from Azerbaijan and Central Asia,” the two nations said.

Before signing the document with her Georgian counterpart Grigol Vashadze, US Secretary of State Condoleeza Rice renewed US support for Georgia’s territorial integrity in an allusion to the 2008 war between Georgia and Russia.

“The US…will always support Georgia’s sovereignty and its territorial integrity, as well as its Euro-Atlantic aspirations and its integration into the institutions of the Euro-Atlantic,” Rice said.

Russia invaded Georgia in August 2008 after the Tbilisi government tried to retake the breakaway region of South Ossetia by force. The conflict saw considerable disruption in the transit of oil and gas across the region, with Russian warplanes said to have targeted pipelines and railways.

China, Japan negotiate East China Sea pact

Japan and China will proceed with joint exploration for natural gas in the disputed East China Sea, but further negotiation is scheduled on China’s continued unilateral activity in those waters.

In June 2008, the two sides agreed to explore jointly one area of the East China Sea, while continuing talks over development of two natural gas fields, Kashi and Kusunoki.

Earlier this month, Japan said it “cannot accept” China’s development of the Tianwaitian (or Kashi as it is known in Japanese) gas field (OGJ Online, Jan. 5, 2009).

Egypt’s proved gas reserves reach 76 tcf

Egyptian Natural Gas Holding Co. (EGAS) has announced that proved gas reserves in Egypt now total 76 tcf. This is up from the 2007 estimate of 72.3 tcf.

“Currently, the Mediterranean region contributes 81% of total gas reserves and will dominate over the coming years as the majority of large gas discoveries are expected to be achieved in this vital region,” said EGAS Vice-Chairman for production and development Eng. Atef Youssef.

“The Western Desert and Nile Delta contribute around 11% and 2% respectively of the remaining recoverable reserves, with the Gulf of Suez making up just 6%. Most of the gas in the Gulf of Suez is either associated with oil reserves or exist as gas cap in the oil fields,” Youssef said.

EGAS said that Egypt has adopted a process for reserves estimation and documentation in which EGAS and Egyptian General Petroleum Corp. (EGPC) are closely involved from the early stages of the exploration planning and approval process. Before drilling any exploratory well by the production sharing contract partner, approval must be given by EGAS or EGPC. Following the declaration of any discovery, the contractor must deliver a summary technical report including well data, proved reserves, and testing results to EGAS and EGPC.

EGAS and EGPC will review the report and then meet with the contractor to discuss reserves and appraisal plans. EGAS and EGPC then present a technical report on the reserves added by the discovery on a P90 basis, which is equivalent to the proved category, to the Supreme Committee for Petroleum Wealth to discuss, review, approve, and declare the official figure of reserves.

Industry Scoreboard
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Exploration & Development — Quick Takes

Verenex adds 10th find in Libya’s Ghadames

Combined maximum flow from the first 10 discoveries and two appraisal wells in Area 47 in Libya’s Ghadames basin totaled 99,320 b/d of oil and 92.7 MMcfd of gas, said Verenex Energy Inc., Calgary.

The tenth discovery, H1-47/02, tested oil and gas from Ordovician Memouniat and Silurian Acacus. Verenex will release results from an 11th discovery, Il-47/02, the first well drilled in the central 3D seismic survey area in northwestern Block 2, after National Oil Corp. reviews them.

The company is preparing to test the K1-47/02 new field wildcat and is drilling the L1-47/02 new field wildcat.

The tenth find, H1-47/02, gauged 1,315 b/d of 42-64° gravity oil and 16.2 MMcfd of gas on 32/64-in. to 48/64-in. chokes. Tested were 73 ft of Memouniat sandstone and two intervals totaling 82 ft of Lower Acacus sandstone. TD is 10,475 ft.

Il-47/02, which went to TD 10,925 ft, extends the Lower Acacus and Memouniat play fairways into northwestern Block 2.

Formation evaluation of Jl-47/02, in southern Block 2, indicated hydrocarbons in Lower Acacus Basal Sand 1 and Upper Shoreface intervals. It is to be tested in late January.

In Basal Sand 1, the results indicated a thick oil column of 66 ft with an underlying water-oil contact that is at a different subsea depth than the contacts found in A1 field and the F1 well, suggesting that the J1 structure may be isolated. Testing may help confirm this interpretation.

Basal Sand 1 contains the majority of the contingent resources in A1 field and in other fields in southern Block 2.

The L1-47/02 new field wildcat that was spud Jan. 2 is 5 km southeast of the A1-47/02 oil and gas discovery on a prospect identified on 2008 2D seismic.

E.On Ruhrgas assumes Huntington operatorship

Oilexco North Sea Ltd. has lost operatorship of the Huntington license in the UK North after its partners voted unanimously to transfer it to E.On Ruhrgas UK Exploration & Production Ltd.

Ernst & Young has become the administrator of Oilexco, which failed to secure a loan from the banks amid the credit crunch for its drilling and development program.

“The operatorship change will ensure progression on the development in line with the partnership’s plans,” said Norwegian Energy Co. ASA, a partner in the field.

Huntington is potentially one of the largest discoveries in the last 5 years; it was put on a fast track to come on stream early in 2010. It is estimated to have up to 150 million bbl of oil in place.

Oilexco will become a nonoperating partner in the license, according to Noreco. The operatorship change became effective Jan. 12.

Buru Energy defers Canning exploration work

Buru Energy Ltd., Perth, has decided to defer its 2009 drilling program in the onshore Canning basin in the Kimberley region of northwest Western Australia to conserve cash while the company reviews its entire exploration portfolio.

Buru will use the deferral to try and identify drilling targets in areas closer to its existing oil fields, or in areas that enable cost-effective development using existing oil production infrastructure.

This includes the possibility of acquiring 3D seismic coverage over its Blina and Sundown oil fields about 100 km east of Broome in the hope of delineating low-risk drilling targets.

The company will also review its plans for the more isolated central and southern parts of the Canning basin that have high potential prospectivity, but greater exploration costs due to difficult access as well as native title and other approval issues.

In addition, Buru plans to halve its production at Blina and Sundown from a total of 200 b/d to 100 b/d to reduce field operating costs.

At present the company has cash reserves of $60 million (Aus.) and is scrutinizing a number of opportunities that have been offered by third parties outside its Canning base.

Buru was formed last year from the demerger of Arc Energy’s Canning assets from the merger of Arc and Australian Worldwide Exploration.

Corridor sees busy 2009 in New Brunswick

One priority in the $59.9 million 2009 budget of Corridor Resources Inc., Halifax, is to drill an exploration well 4 km southeast of the 2008 South Branch G-36 (Caledonia) oil discovery.

This exploration well would evaluate the oil and gas potential of the Upper Hiram Brook formation and the shale gas potential of the Frederick Brook formation.

Corridor also plans to drill a step-out to the Caledonia discovery, where it shot 3D seismic last fall, and drill four McCully gas field appraisal and development wells.

The company also hopes to frac and test the Green Road G-41 well to evaluate Frederick brook shale gas potential in the Elgin subbasin. G-41 went to 2,422 m and cut 785 m of Frederick Brook gassy shale, siltstone, and minor sandstone. That included a massive, predominantly siltstone interval at 1,753-1,906 m that is friable and had strong shows of gas while drilling. Another 10 m of sheared, fractured black shale at 1,919-29 m was recovered as conventional core.

Other goals are to seek a joint venture partner to accelerate work at Elgin and other areas in the basin, and run a site survey at a proposed drilling location on the 45,000-acre Old Harry structure in 1,400 ft of water in the Gulf of St. Lawrence off Quebec (see map, OGJ, Sept. 28, 1998, p. 107).

Drilling & Production — Quick Takes

Ithaca installs Jacky facilities in UK North Sea

Ithaca Energy (UK) Ltd. has installed the wellhead platform and pipelines for its Jacky field in the Inner Moray Firth of the UK North Sea.

Two months of bad weather in the North Sea had caused a delay, so Ithaca hired, on short notice, the Hermod Heavy Lift Vessel to progress the project and ensure that the schedule for the pipelay and for finishing the well completion on time was not impacted. The company said these activities and the delay likely will increase development costs by 20-24% above the original estimate of £59.7 million because of shifts in the exchange rates of the UK pound, US dollar, and euro.

Jacky initially will produce 7,500 b/d in mid-March once the well completion and production well tie-in is finished.

The company will use the Ensco 92 jack up to enter the already-drilled Jacky in mid-February or early March to complete the well work, depending on previous well timing. Jacky will be an unmanned facility with the single well tied back to nearby Beatrice field facilities.

The Beatrice facility will be modified to accommodate Jacky’s production, a company spokesman told OGJ. Ithaca plans to add another well at the end of the year if Jacky performs as expected, he added.

As part of the Jacky development project, Ithaca also is reinstating production from the closed-in Beatrice Bravo platform. The Bravo facility was producing about 800 b/d when Talisman Energy UK Ltd. shut in the facility in July 2007 because of corrosion of the pipeline between Bravo and the Alpha platform.

Jacky is owned by operator Ithaca, which has a 67.3% interest, and its partners Dyas 22.7% and North Sea Energy 10%.

Processing — Quick Takes

BP to supply Vietnam’s Dung Quat refinery

BP PLC has signed an agreement with state-run Petrovietnam Oil Corp. and operator Binh Son Refinery Co. to supply oil to Vietnam’s 130,000-b/d Dung Quat refinery starting on Feb. 25.

Petrovietnam will negotiate with BP over the purchase of as much as 70,000 b/d of crude, which will gradually replace output from Vietnam’s Bach Ho (White Tiger) field.

Analyst BMI said delivery of the crude will “pave the way” for BP to acquire at least part of the 49% stake open in Dung Quat. BMI cited a statement by Petrovietnam Chairman Dinh La Thang that international partners committed to supplying crude would be given preference as stakeholders in the facility.

Petrovietnam had planned to run the Dung Quat refinery on domestically produced Bach Ho oil, but it decided instead to bolster its foreign exchange earnings by using more imported Middle East oil and reserving Bach Ho for export markets.

The Dung Quat refinery, which is scheduled to begin operations on Feb. 25, is designed to process 3.5 million tonnes of oil during 2009, while its capacity is eventually set to increase to 6.5 million tonnes/year.

When it is fully operational, the Dung Quat refinery will meet 30% of domestic demand, producing LPG, propylene, 90RON and 92RON gasoline, kerosine, Jet A1, diesel oil, and fuel oil.

Earlier this week, Petrovietnam announced plans to build a 2 million-tonne underground storage facility at Long Son in Ba Ria-Vung Tau Province that is designed to hold products from the Dung Quat refinery.

Pertamina wins loan to expand Balongan refinery

A consortium of international banks has committed to provide Indonesia’s state-owned PT Pertamina with $225 million financing, enabling it to build a polypropylene unit at its 125,000 b/d refinery in Balongan, West Java.

“The deal is for project financing,” said Pertamina finance director Ferederick Siahaan, who added that Japan’s Nippon Export & Investment Insurance (Nexi) would act as guarantor for the project.

In addition to Nexi, Ferederick said the consortium is comprised of a number of banks, including HSBC Holdings PLC, BNP Paribas SA, and Sumitomo Mitsui Banking Corp.

Pertamina last year announced plans to build the unit.

“The prospects for the polypropylene market are good,” said Pertamina chief Ari Soemarno in May. “That is why we plan to build a polypropylene unit to meet domestic demand [for] plastic.

“We are seeking a partner,” Ari said, adding that the new unit would turn Balongan’s propylene into polypropylene to increase its value, while another company official said the plant would cost about $200 million and would have a production capacity of 200,000 tonnes/year.

In January 2008, Pertamina signed a contract with Japan’s Toyo Engineering and Indonesia’s Rekayasa Industri for an expansion project aimed at upgrading the refinery’s residue catalyst cracking unit to switch from ethylene output to propylene.

Meanwhile, this month, officials expected the Balongan refinery, which has been shut since last October, to resume operations by Jan. 9. According to Pertamina Vice-Pres. Anang Rizkani Noor, “Everything is smooth and on schedule.”

Pertamina shut the refinery on Oct. 18 to upgrade the RCC unit, and 10 days later, there was an explosion at the refinery’s 58,000 b/d atmospheric hydrodemetalization unit. The refinery was restarted Dec. 17 but was shut again Dec. 21 due to what officials called “technical problems.”

CSB to investigate Utah refinery blast, fire

A four-member team will travel to Woods Cross, Utah, to investigate a Jan. 12 explosion and fire that injured four people, the US Chemical Safety and Hazard Investigation Board said Jan. 13.

The fire at the Silver Eagle Refining Inc. refinery injured two employees and two contract workers who were standing about 10 ft from a tank filled with flammable hydrocarbons when it exploded, CSB said. All were hospitalized for treatment of second and third-degree burns.

Fire crews evacuated other employees and residents within a half-mile radius soon after the blast, which occurred around 5:30 p.m. MST. Evacuees waited at a high school before they were permitted to leave 4 hr later. The fire was extinguished by 3:45 a.m. on Jan. 13.

An official for Silver Eagle Refining, which bought the 10,250 b/d plant from ConocoPhillips in 2003, said the company would begin working immediately with federal and local investigators to determine the explosion and fire’s cause.

CSB said that its crew, which was scheduled to arrive the afternoon of Jan. 14, would be lead by investigator supervisor Donald Holmstrom.

Transportation — Quick Takes

EU considers action against Gazprom, Nafttogaz

European Commission Pres. Jose Manuel Barroso advised European companies “to take the matter to the courts” if OAO Gazprom and Naftogaz don’t resume soon the movement of Russian gas to Europe via Ukraine.

Barroso also called for concerted action by European Union states to find alternative energy supplies if the “unacceptable and incredible” problem isn’t resolved soon.

Barroso reiterated that EU members should use the ¿5 billion in the community budget to finance interconnections with other energy supplys.

The EU gas coordination group met Jan. 9 to identify helpful measures for countries suffering most from gas shortages, but concluded only inadequate short-term measures are available. Those measures include increased production from European countries, sharing larger withdrawals from storage, fuel switching, and limiting industrial consumption of gas. Even LNG would be of little help as terminals with spare capacity are not connected to those countries most in need of supply.

In an extraordinary session Jan. 12, energy ministers agreed on the need to develop transparency of physical gas flows, enhance storage capacity, increase strategic stocks, and make regional and bilateral solidarity arrangements.

An assessment of network connections identifying gaps and diversified routes and sources is to be submitted at the Feb. 19 energy council.

Transneft: ESPO’s first stage on track for yearend

The first stage of Russia’s East Siberia-Pacific Ocean pipeline (ESPO-1) will come on stream on Dec 25, 2009, according to Nikolai Tokarev, the head of the state-owned pipeline operator OAO Transneft.

“There are grounds to assume we will succeed,” Tokarev said, adding that the revised budget for ESPO-1 had been approved at 390 billion rubles ($12.5 billion), with an extra 60 billion rubles ($1.94 billion) to be invested in the Kozmino terminal on Russia’s Pacific Coast.

According to Tokarev, the estimated cost of building ESPO-1 rose 21% to 390 billion rubles from the original estimate of 322 billion rubles following an adjustment for inflation at yearend 2008.

ESPO-1 will extend 2,757 km from Taishet in East Siberia to Skovorodino in the Amur Region near the border with China, while the line’s second stage, ESPO-2, will extend a further 2,100 km from Skovorodino to the port of Kozmino on Russia’s Pacific Coast.

Altogether, ESPO-1 is designed to transport as much as 220.5 million bbl/year of oil to Skovorodino, while the combined ESPO-1 and ESPO-2 lines will transport as much as 367.5 million bbl/year of oil. While awaiting construction of ESPO-2, oil will be transported by rail from Skovorodino to Kozmino.

Tokarev said Transneft is ready to begin construction of ESPO-2 by yearend, but that the line’s feasibility study is currently under scrutiny by Russia’s State Environmental Review Agency.

In December, Natural Resources Minister Yury Trutnev said his ministry planned to conduct an analysis of the resources needed to fill the ESPO line, underlining his concerns that the global economic crisis could affect development of the necessary oil resources in Eastern Siberia.

“Just a couple of years ago, we gathered oil producers and received from them absolutely confident statements of production volumes, summed them up and received an absolutely calm picture of resources supply,” Trutnev said.

“Today we are confident that this work needs to be done again. We need to make sure that everything is okay. Otherwise we may have concerns and therefore need to take appropriate measures,” Trutnev said, adding, “We will do that in February.”

Meanwhile, in making his announcements, Tokarev said that OAO Transneft will not be able to begin the construction of a proposed pipeline spur from Skovorodino to the Chinese border until 2010 at the earliest.

“We will complete the construction quickly and efficiently, but it won’t be in 2009 since the issue of financing has yet to be resolved,” Tokarev said, referring to a breakdown in negotiations with China that took place late last year.

Transneft and OAO Rosneft, which were expecting Chinese loans of $10 billion and $15 billion, respectively, for construction of the spur and for oil deliveries, were unable to complete talks with China National Petroleum Corp. by yearend 2008.

In early December, China said it expected to sign the agreements before yearend 2008, but the talks broke down due to a disagreement over interest rates for the loans, with China insisting on a floating rate, while Russia waning a fixed rate. Talks between the two sides are scheduled to resume in February, about the time the resources ministry plans to announce its revised analysis of the resources needed to fill the ESPO line.


The subhead for a story about ExxonMobil Corp.’s world demand outlook to 2030 should have read: World energy demand to reach 310 million boe/d in 2030 (OGJ, Jan. 12, 2009, p. 30). Also, the start of the third paragraph of that story should read as follows: Driven by growing populations and expanding economies, global energy demand is expected to increase to the equivalent of 310 million b/d in 2030 compared with the equivalent of 229 million b/d in 2005.