General Interest — Quick Takes
China, Venezuela sign round of energy agreements
China and Venezuela signed five agreements, one concerning refining and two touching on exploration and development of oil fields in the Orinoco Belt.
At the signing ceremony in Caracas, China National Offshore Oil Corp. (CNOOC) agreed to help the Venezuelan government assess oil reserves in the Boyaca 3 oil block in the Orinoco belt.
Venezuela's state-owned Petroleos de Venezuela SA (PDVSA) and China Petroleum & Chemical Corp. (Sinopec) also signed an agreement to establish a mixed company to develop the Junin 8 Block.
CNPC and PDVSA agreed to set up a mixed company to develop a 400,000-b/d refinery in Cabruta that will refine oil from the Junin Block 8.
The two countries also signed an oil export agreement, which could see up to 560,000 b/d heading to China in 2010, as well as a deepwater technical advice agreement between CNOOC and PDVSA.
Analyst IHS Global Insight said the agreements indicate growing ties in the oil sector between the two countries, with Venezuela seeking to diversify exports away from the US and to secure finances to develop new oil reserves.
Global Insight also said China is keen to take advantage of the fall in crude oil prices and global demand over the past year to secure long-term supply deals from producer states like Venezuela as its own import dependence rises.
Earlier this year, Russia and Venezuela, during Venezuelan President Hugo Chavez's 2-day visit to Moscow, signed a similar package of energy agreements, including one to develop the Latin American country's Orinoco belt and its 235 billion bbl of heavy oil reserves (OGJ Online, Sept. 11, 2009).
Indonesia drops plan for cost recovery payments
Unable to attract enough investors to develop new oil and gas blocks, the Indonesian government plans to abandon its recently adopted practice of capping the annual cost recovery payment reimbursed to contractors.
"The policy of capping cost recovery is not appropriate. This is not supposed to be capped. We will fix this matter," said Coordinating Economic Minister Hatta Rajasa, referring to plans by the government to reimburse all contractor cost items within the scope of the cost recovery payment rules.
"We have corrected this," Hatta said. "The most important thing is not to cap the payment, but how to avoid moral hazard [in the payment]."
Under Indonesia's production-sharing contract regime, Jakarta must refund investors' full exploration costs once fields enter production.
However, to head off a potential budget shortfall, members of Indonesia's House of Representatives, urged the government's upstream watchdog BPMigas to reduce the cost recovery given to oil and gas contractors.
"For now, BPMigas should limit the amount of cost recovery," to $10 billion from $11.05 billion, said Suharso Manoarfa, vice-chairman of the House's budget committee, in a hearing with the government and the central bank (OGJ Online, July 28, 2009).
After allegations of insufficient transparency in the reimbursement process, Indonesia's parliament eventually imposed restrictions on cost recovery payments in 2009, capping the total budget for the scheme at $11.05 billion in 2009 and setting the cap at $12 billion for 2010.
However, these restrictions recently were singled out as a major contributory factor behind falling investment in the country. As a result, plans were announced by Evita Legowo, director general at the energy ministry, to encourage the finance ministry to abandon the caps.
"We as the player in this business fully support the government's decision," said Budi Basuki, president director of Medco E&P Indonesia.
While the decision to drop the caps may be welcomed by Budi and other members of the country's oil and gas industry, analyst BMI doubts the measure will do anything to improve Indonesia's efforts to attract investment.
"Although this is a step in the right direction, we doubt that it will be sufficient to stem the fall in upstream investment, and we expect the results of the country's next licensing round to be disappointing," said BMI.
Russia, Turkmenistan revise gas contract
Russia and Turkmenistan have agreed to new terms on gas trade while their presidents, Dmitry Medvedev and Gurbanguly Berdimuhamedov, signed a broader agreement on strategic energy cooperation.
Turkmenistan sells gas to Russia under the 25-year Interstate Cooperation Agreement signed on Apr. 10, 2003.
Under the revised contract, Russian purchases of up to 30 billion cu m/year of Turkmen gas—about two-thirds the level of recent years—will resume Jan. 1, under a price formula based on the European gas market.
Medvedev said it will be the first link of Russian purchases of Turkmen gas to European prices.
Deliveries of Turkmen gas to Russia ceased 9 months ago after the rupture of the main Turkmen export pipeline. Turkmenistan blamed Russia for the incident, which came amid pricing disputes.
The energy-cooperation agreement will cover joint pipeline construction, according to a senior Russian official.
Earlier this month, Turkmenistan signed a long-term agreement for the supply of gas to China. At the time, Russia's Prime Minister Vladimir Putin said the agreement would not upset relations between his country and Turkmenistan (OGJ Online, Dec. 7, 2009).
Exploration & Development — Quick Takes
Dana Gas makes ninth discovery in Nile Delta
Dana Gas reported a natural gas discovery with its Orchid-1 well in the West Manzala concession of the Nile Delta. The find marks the firm's ninth discovery in the region in recent months.
Dana said Orchid-1 was drilled 1.3 km west of its Azhar-1 well, and was spudded on Dec. 15, 2009, reaching a total depth of 1,700 m in the Pliocene Kafr El Sheikh formation.
The well found 8.4 m of net pay of excellent sand reservoir of Kafr El Sheikh formation, and tested dry gas at 12.6 MMscfd.
Dana said it is currently studying the options for producing Orchid-1 through either its El Wastani or South El Manzala gas plants.
"The preliminary estimated recoverable reserves of the Orchid discovery range between 10-50 bcf of dry gas, pending further appraisal," the firm said.
Dana said the find follows its eight previous gas discoveries in Egypt announced in 2009: Salma-1, West Manzala-2, Azhar-1, Tulip-1, Sharabas-1, Sama-1, Faraskur-1, and Marzouk-2.
As a result of the finds, Dana said it has successfully achieved its yearend production target for Egypt operations by delivering a production rate "in excess of 40,000 boe/d."
Overall, Dana Gas Egypt said it has delivered an average production rate of 34,750 boe/d during 2009. Compared to 2008, this represents an increase of 27% on the end of year production rate and is a 20% increase on the average daily production rate.
Devonian zones indicate oil in Gaspe, Quebec
Petrolia, Rimouski, Que., reported light oil on drillstem tests in two formations of Devonian age at its Tar Point exploratory well on Quebec's Gaspe Peninsula.
The indicated discovery is 11 km southeast of the company's undeveloped 2006 Haldimand oil and gas discovery just southeast of Gaspe town. That well yielded 47° gravity oil (OGJ, July 10, 2006, p. 38).
The Tar Point well went to TD 2,434 m in tight, oil saturated sandstones, and Petrolia set casing to 2,201 m.
A drillstem test at 2,045-2,201 m in a highly fractured limestone in the Indian Cove formation of early Devonian age yielded a small flow of gas and 184 l. of fluid, mainly composed of drilling mud and light oil. A production test is planned in January.
Another drillstem test at 1,528-84 m in the Devonian York River formation produced a small flow of air at surface, 58.33 m (213 l.) of drilling mud with minor gas, and gassy mud with black oil from the sample chamber. The zone indicated low permeability, but Petrolia said it might frac the interval depending on results of work to be carried out at Haldimand in early 2010.
The two wells are 220 miles north of gas production at McCully field near Sussex, NB.
Petrolia holds interests in 3.7 million acres of leases or 18% of Quebec territory including Anticosti Island in the Gulf of St. Lawrence.
Origin group makes oil, gas find off Tasmania
The Origin Energy Ltd. group has made a natural gas and oil discovery in its Rockhopper-1 wildcat in Bass basin permit T/18P off northern Tasmania. The size and commercial significance of the find will be assessed following wireline logs and a test program.
Wireline pressure data has confirmed multiple hydrocarbon zones within interbedded sands and shales of the Lower Eastern View Coal Measures in the prospect. Selective wireline sampling also recovered oil from some sands and liquid-rich gas from others.
The thickness of individual sands varies from 1 m to 5 m. Reservoir quality also appears to be variable.
No definitive water-bearing sands were encountered in the target horizons and the joint venture is now contemplating drilling a sidetrack into a down-flank location to establish hydrocarbon column heights.
The well has been drilled by the Kan Tan semisubmersible and is close to the Trefoil and Yolla gas fields.
Origin of Sydney has 39%. Other partners are AWE, Sydney, 47.5%, CalEnergy Gas 8.5%, and Innamincka Petroleum, Brisbane 5%.
New Brunswick shale gas play draws attention
PetroWorth Resources Inc., Calgary, divested all interests in Alberta natural gas wells to concentrate activity in eastern Canada.
The decision is based on recent shale gas developments adjacent to PetroWorth's 41,000-acre Rosevale block in New Brunswick.
The company holds 129,000 acres, including Rosevale, south of Moncton that bracket Stoney Creek oil and gas field.
The Rosevale block lies east of McCully gas field and an emerging gas play in Mississippian Frederick Brook shale, in which Apache Canada Ltd. has joined Corridor Resources Inc., Halifax (OGJ Online, Dec. 8, 2009).
Drilling & Production — Quick Takes
Rigless ESP nears commercial installation
ConocoPhillips has scheduled its first commercial installation of a rigless electric submersible pump during the second or third quarter, according to Artificial Lift Co. Ltd.
ALC in cooperation with ConocoPhillips developed the rigless ESP during the last 5 years.
A paper given at the 2009 SPE ATCE in New Orleans (Patterson, J.C., et al., "First 4.5-in. Through-Tubing ESP with Downhole Wet Connect," Paper No. SPE 123996) said ConocoPhillips was interested in developing the rigless pump in order to lower the cost for replacing pumps in sanded up wells in the West Sak Unit on Alaska's North Slope.
The paper noted that wireline-conveyed through-tubing pump sections have been available but these still needed a workover rig to deploy or retrieve the pump's motor, which was run on tubing.
The rigless ESP has a slim ALC designed permanent-magnet motor connected to the pump section that a wireline unit can deploy or retrieve in 4.5-in. tubing with a 3.833-in. drift ID.
The initial pump installation still needs a workover rig for deploying the electric cable conventionally on the tubing string. A wet connector in the bottomhole assembly of the tubing string links the cable to the wet-connector system on the ESP.
ALC also said the production engineering and well services department of Saudi Aramco has plans to install a rigless ESP in early 2010.
Concession awarded for Adriatic gas field
Production from Guendalina natural gas field in the northern Adriatic Sea will start by June 2011 under a concession awarded this month to operator Eni SPA by the Italian Ministry of Economic Development, according to 20% interest holder Mediterranean Oil & Gas PLC (MOG).
MOG earlier expected production to begin in the last quarter of 2010 (OGJ, May 18, 2009, p. 34).
It now says Eni expects to begin development this month or in February, install the platform in 20 m of water 25 km off Ravenna, Italy, this year, and complete the drilling of two wells in the first half of 2011.
MOG says Eni studies indicate Guendalina production will be about 20 MMcfd. Proved and probable reserves are 22 bcf.
Statoil to upgrade Snorre complex
Statoil ASA will invest more than 5 billion kroner to ensure increased production and continued profitability from its Snorre field. The field "has the largest remaining reserves of Statoil's fields on the Norwegian Continental Shelf," said Torstein Hole, senior vice-president of the firm's western exploration and production operations in Norway.
"A number of extensive modifications have been carried out in recent years to make the installations more robust for increased production and an extended lifetime up until the year 2040," Hole said in an article published on Statoil's web site. "We are the NCS field carrying out most modifications in 2009-10. Total capital expenditure for Snorre in 2009 and 2010 amounts to 5 billion kroner, of which health, safety, and environmental measures account for over 50%," he said.
The flotel "Safe Scandinavia" is to arrive at Snorre A next summer and will increase the field's sleeping capacity for 6 months for more workers for additional projects and maintenance. The accommodation quarters on Snorre will be upgraded in that period, with more single-occupant rooms to be built and noise-reduction measures implemented.
The two platforms at the Snorre field will be upgraded and the present fire and gas alarm will be replaced with a modernized system at a cost of 450 million kroner. Apply Sorco AS was awarded the main contract for the upgrade.
"We will get a completely revamped, modern system with a much improved coverage compared to the current one. This will make the platform's warning system more robust and will represent a big safety improvement," said Hole.
The comprehensive project will extend 3 years to 2012. "While the platform is in full operation, and the current warning system is operative, some 1,700 detectors will be removed and 2,000 new ones installed; 36 km of cable will be taken out and 47 km of new cable installed," Hole said.
Processing — Quick Takes
FEED pact let for Venezuelan ethylene plant
A Brazilian-Venezuelan joint venture has let a reimbursable front-end engineering design (FEED) contract to Technip for a 1.3 million tonne/year ethylene plant at Jose, Venezuela.
The JV is Polimerica, owned 49% each by Venezuela's state-owned Pequiven and Braskem of Sao Paulo, Brazil. Coramer, Caracas, and Sojitz, Tokyo, hold 1% each.
The ethylene plant is to be part of a petrochemical complex Pequiven and Braskem plan to build at Jose through two JVs they agreed to form in 2007 (OGJ Online, Apr. 19, 2007).
One JV is to build the ethane cracker covered by the new contract as well as a 1.1 million tpy polyethylene plant. The other JV is to build a 450,000 tpy polypropylene plant.
Technip said FEED activities for the ethylene plant are to be completed by second quarter 2011.
CBF NGL plant to be expanded at Mont Belvieu
Targa Resources Partners LP, Houston, plans to expand capacity of its majority-owned Cedar Bayou Fractionators LP (CBF) natural gas liquids fractionation facility at nearby Mont Belvieu, Tex.
The maximum gross fractionation capacity of the facility is to be expanded by 60,000 b/d to 275,000 b/d, increasing the partnership's maximum gross NGL fractionation capacity along the Texas and Louisiana Gulf Coast to 439,000 b/d.
The CBF expansion is to be supported by a long-term firm space fractionation agreement at market-based fees with Oneok Partners LP. CBF and Oneok executed a letter of intent with completion of final documentation and board approvals expected in the near future.
The expansion will increase Targa Resources' fee-based percentage of operating income, said Rene Joyce, chief executive of the partnership's general partner and of Targa Resources.
The expansion should be operational in the first quarter of 2011, subject to regulatory approvals, with no disruption of existing operations during construction. Total cost for the expansion will be significantly lower than a greenfield fractionation facility because the new capacity will be integrated with existing fractionation capacity, utilities, infrastructure, and footprint at Mont Belvieu.
The partnership's total capital expenditures for 2010 are budgeted for $130 million with maintenance capital expenditures accounting for 25%. Expected expenditures include the CBF fractionation expansion as well as other projects in its gas gathering and processing and NGL logistics and marketing businesses. The 2010 capital expenditure forecast does not include "growth opportunities under development that are uncertain with respect to timing and other factors," officials said.
Transportation — Quick Takes
Putin launches first phase of ESPO oil line
Russian Prime Minister Vladimir Putin, eyeing the emergence of new markets in Asia-Pacific, launched the first phase of the East Siberia-Pacific Ocean (ESPO) oil pipeline.
"It is a strategic project, which enables us to enter the growing markets of the Asia-Pacific region," Putin said in a ceremony at the port of Kozmino on Russia's Pacific Coast.
At the ceremony, Putin initiated the loading of the first tanker, The Moscow University, which was set to deliver the ESPO-brand crude to Hong Kong, according to Nikolai Tokarev, president of Russia's pipeline monopoly OAO Transneft.
In October, officials at Russia's energy ministry said the new ESPO-brand crude will be light and medium-sour, superior to Urals export blend but inferior to Siberian Light (OGJ Online, Oct. 12, 2009).
Transneft last month completed the first 2,757-km stretch of the pipeline which runs from Taishet in the Irkutsk region to Skovorodino near the Chinese border.
At Skovorodino, oil is currently being loaded on to railcars for transport to Kozmino, which lies 2,100 km further east. The rail connection will be phased out in 2012 when Transneft completes the second section of the pipeline from Skovorodino to Kozmino.
The first phase of the line is capable of carrying up to 30 million tonnes/year of oil, about half of it earmarked for China via a 67-km pipeline spur from Skovorodino to the Chinese border, and the other half destined for export from Kozmino. The full ESPO line will eventually carry up to 80 million tpy of oil.
The first phase of the ESPO project cost $12.1 billion, while another $2 billion was spent on construction of the Kozmino terminal.
Transneft will spend another $10 billion to build the pipeline extension to Kozmino, which analysts said will become Russia's third largest seaborne oil outlet after Primorsk on the Baltic Sea and Novorossiisk on the Black Sea.
Mackenzie Valley pipeline gets federal approval
Canada's federal Joint Review Panel approved the Mackenzie Valley natural gas pipeline after considering its environmental and social effects.
The JRP was created in 2001 to streamline regulatory processes around the pipeline. In 2006, it launched public hearings in the Northwest Territories with the expectation of submitting a report by mid-2007. However, the deadline was extended at least twice as the panel analyzed its findings.
The pipeline would stretch more than 750 miles to transport Mackenzie River Delta gas to Alberta and beyond. Plans call for initial capacity of 1.2 bcfd, expandable to 1.9 bcfd.
Imperial Oil Ltd. (34.4%), ConocoPhillips Canada (15.7%), Shell Canada (11.4%), and ExxonMobil Canada (5.2%) launched the project in 2000. The consortium also includes aboriginal partners, known as the Aboriginal Pipeline Group Inc., consisting of five First Nations tribes and their financial backer TransCanada Pipelines Inc., which seeks to move the gas south to US markets.
TransCanada Corp. Chief Executive Officer Hal Kvisle estimates the regulatory delays contributed $3 billion (Can.) to the project's $16.2 billion total cost. Costs include $7.8 billion for the Mackenzie Valley mainline, $3.5 billion for the gas gathering system, and $4.9 billion for anchor-field development (OGJ, Feb. 9, 2009, p. 54).
FERC issues final EIS for proposed Bison pipeline
A proposed 301-mile natural gas pipeline in Wyoming, Montana, and North Dakota would result in some significant environmental impacts that could be mitigated to acceptable levels, the US Federal Energy Regulatory Commission said on Dec. 29.
The 30-in. Bison Pipeline Project—which a TransCanada Corp. subsidiary plans to build from the Powder River basin to a connection with the Northern Border Pipeline in Morton County, ND—would be designed to transport as much as 477 MMcfd of gas, FERC's staff said as it issued a final EIS environmental impact statement on the proposed project.
It said environmental impacts would be significantly reduced if the proposed project, which includes one compressor station, two meter stations, 19 mainline valves, and three pig launching and receiving facilities, is built and operated under applicable laws and regulations, Bison's stated mitigation plan, and additional measures recommended in the EIS.
The pipeline would be colocated with existing utility rights-of-way for about 53 miles, or 17.6% of its total route, FERC said. "The proposed route has been significantly influenced by agency recommendations to avoid sensitive wildlife habitats and vegetation types," it indicated. "Bison has been responsive to landowner requests for minor route modifications and has adopted many of these into the proposed route evaluated in this final EIS."
Bison Pipeline LLC, the TransCanada subsidiary planning to build the project, said its daily capacity could be expanded to 1 bcf, and that future development plans include expansion and extension of the pipeline into Rocky Mountain basins. It plans to begin construction in 2010 after receiving the necessary regulatory approvals, with a proposed Nov. 15 in-service date.
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