Chevron exec notes gulf permitting backlog
Despite new permitting by the US Bureau of Energy Management, Regulation, and Enforcement, the outlook for resumption of work in the Gulf of Mexico remains "challenging at best," says an executive of one of the region's most active deepwater operators.
Steve Thurston, vice-president of Chevron Corp.'s Deepwater & Projects Business Unit, reported his company's permit status Apr. 8 at the Decision Strategies Oilfield Breakfast Forum in Houston. He said Chevron sanctioned $14 billion in new Gulf of Mexico projects last year, when the fatal Macondo blowout on Apr. 20 and resulting oil spill halted activity and inaugurated a round of regulatory tightening and improvements by the industry to offshore well control and spill preparedness.
Chevron has 11 wells in the permitting process, Thurston said. It has two drillships back at work, one drillship waiting on a permit, and two drillships en route to the gulf.
A moratorium imposed after the blowout ended in October 2010 but has been followed by what Thurston called a "permitorium." He pointed out that BOEMRE issued its first new well permit on Feb. 28 and has issued only nine new permits so far. He said Chevron received its first drilling permit on Mar. 24.
The company has five revived exploration plans and one development plan in the permitting process now. Thurston said frequent requests for additional information keep plans from progressing to completion. BOEMRE issued its first exploration-plan approval last month.
Thurston said the outlook for further plan approvals remains uncertain because of new environmental assessment rules. "There's a huge backlog out there," he said.
"The industry can and will develop deep water safely," he said, adding that it needs "a regulatory system that can up its game."
Alta Energy Partners to develop unconventional assets
Alta Resources LLC and Blackstone Capital Partners agreed to form Alta Energy Partners to develop unconventional oil and natural gas assets. Specifically, the new company plans to acquire and develop shale oil and gas in North America. It will be backed by up to $1 billion.
Separately, Contango Oil & Gas Co. said it agreed to invest up to $20 million over 2 years in the joint venture with Alta Resources and Blackstone Capital.
Kenneth R. Peak, Contango's chairman and chief executive officer, noted his company already is a partner with Alta Resources and George P. Mitchell in the Fayetteville shale in Arkansas.
In Pennsylvania, Alta has a field office in Montrose and is leasing acreage. Its partners in Pennsylvania are George P. Mitchell and Centaurus Energy, founded by John D. Arnold.
Alta Resources is a private Houston company that was formed in 1999. Joseph G. Greenberg is Alta Resources president and chief executive officer.
In the past 9 years, Alta has drilled or participated in more than 150 wells in Arkansas, Texas, Louisiana, and Alabama with an overall success rate of 95%, Greenberg said.
ONGC Videsh reports production record
ONGC Videsh, the international operating unit of state-owned Oil & Natural Gas Corp. of India, set a company production record in fiscal 2010-11 at 9.433 million tonnes of oil equivalent.
The company holds interests in production in Russia, Syria, Vietnam, Colombia, Sudan, Venezuela, and Brazil. Its earlier production high mark was 8.87 million tonnes in 2009-10.
Including those not on production, ONGC Videsh has interests in 32 oil and gas projects in 13 countries.
Atrush is multipay oil find in Iraqi Kurdistan
An operating group has gauged a multizone oil discovery at the Atrush-1 exploratory well in northern Iraqi Kurdistan.
Three Middle and Upper Jurassic fractured carbonates flowed at a combined, equipment-limited rate of more than 6,393 b/d of 26.5° gravity oil. Well analyses show the intervals are capable of much higher rates when completed for production.
Ten drillstem tests were run across horizons in Cretaceous, Jurassic, and Triassic to establish reservoir pressure gradients, fluid content and properties, and reservoir deliverability.
Drilled to a total depth of 3,400 m, the well encountered a 726-m potential gross oil column in Lower Cretaceous and Jurassic with 120 m of net matrix pay in Jurassic. Drilling shows and log results indicate as much as 140 m of further potential net pay in the Upper Butmah and Cretaceous formations that will be further tested in later wells.
The Atrush block covers 269 sq km, and the discovery well is 13 km northeast of Gulf Keystone Petroleum Ltd.'s early 2010 Shaikan oil discovery well.
The Atrush well was operated by the joint venture company General Exploration Partners Inc., which owns an 80% interest in the block. A unit of Marathon Oil Corp. owns the other 20%. GEP is held two thirds by Aspect Energy International LLC and one third by a unit of ShaMaran Petroleum Corp., Vancouver, BC.
Ophir, RAK Gas to explore Tanzania coastal block
A unit of Ophir Energy PLC struck a deal with Ras Al Khaimah Gas Tanzania Ltd. to acquire 70% interest in and operatorship of the East Pande onshore-offshore license in the Rovuma basins in southern Tanzania.
The license covers more than 7,500 sq km and partly adjoins to the west blocks 1, 3, and 4 in which Ophir holds 40% interest. An Ophir-BG International combine has made three sizable deepwater gas discoveries, two on Block 4 in the Mafia Deepwater basin and one on Block 1 in the Rovuma basin (OGJ Online, Apr. 4, 2011).
The East Pande block extends from onshore in the Rovuma basin in the south to as much as 2,000 m of water in the Mandawa subbasin in the north. The production sharing agreement was awarded to RAKGas in 2006.
RAKGas shot 1,800 line-km of 2D seismic data in the offshore part of East Pande in late 2010. The data indicate the continuous nature of the geology between East Pande and the prospective Ophir acreage to the east, Ophir said.
Subject to partner and government consent, Ophir intends to shoot a 3D seismic survey in the offshore part of the block. Ophir will fund 100% of the cost of the survey and reimburse certain back costs. If Ophir elects to drill, it will carry RAKGas through the first exploratory well.
Ophir and RAKGas are also partners in the Berbera PSA in Somaliland.
Noble cites casing wear, moves rig off Leviathan
Noble Energy Inc. suspended drilling the deeper part of its Leviathan-1 giant Miocene gas discovery well in the deepwater Mediterranean off Israel and is moving the rig to drill a development well at its Tamar discovery.
Noble Energy's announcement didn't elaborate on the nature of mechanical issues that led it to suspend drilling at Leviathan. The company said it "identified wear on the wellbore casing, requiring additional material and equipment necessary to complete the drilling" that are not available in Israel.
The company said it is working to secure the needed items.
Leviathan-1 is in 1,645 m of water in the Levant basin 130 km off Haifa and 47 km southwest of the Tamar discovery well (see map, OGJ, Oct. 4, 2010, p. 54).
The Leviathan well had reached 5,170 m at the end of December 2010, and drilling was to continue to 7,200 m to evaluate two more intervals.
The company is preparing to move the Sedco Express semisubmersible to Tamar field to spud a development well in about a week. Tamar development remains on schedule for commissioning in late 2012, Noble Energy said.
Noble Energy operates Leviathan in the Rachel license with a 39.66% working interest. Other interest owners are Delek Drilling and Avner Oil Exploration with 22.67% each and Ratio Oil Exploration with 15%.
Noble Energy also operates Tamar in the Matan license with 36% interest. Its partners there are Isramco Negev 2 with 28.75%, Delek and Avner, 15.625% each, and Dor Gas Exploration 4%.
Drilling & Production — Quick TakesIn Salah partners sign $1.15 billion EPC contract
In Salah Gas Ltd., a partnership of Statoil, BP PLC, and Algeria's Sonatrach, has signed a $1.15 billion engineering, procurement, and construction (EPC) contract with Petrofac International (UAE) LLC for work on the In Salah southern fields development project in Algeria.
The In Salah central processing facility at Krechba will process the gas from the southern fields and remove the carbon dioxide for underground sequestration before the gas is piped to the national gas grid.
The EPC contract is part of the Phase 2 development of the In Salah license.
In Salah Gas Ltd. has signed a $1.15 billion EPC contract with Petrofac International (UAE) for work on the In Salah southern fields development project in Algeria.
The three gas fields (Krechba, Teg, and Reg) in the northern part of the license were initially developed in Phase 1, with the objective of delivering 9 billion cu m/year of gas. Phase 1 started in late 2001 and first commercial gas was delivered in July 2004.
Based on the expected decline of gas production from these three fields, Phase 2 will maintain the production plateau and sustain long-term gas sales commitments, according to the partnership.
Phase 2 includes four gas fields in the southern part of the license: Garet El Bifna, Gour Mahmoud, In Salah, and Hassi Moumene.
Under the EPC contract Petrofac will build several facilities including well pads, manifolds, flowlines, and a new central processing facility with a gas processing capacity of 17 million cu m/day. The central processing facility will be north of the town of In Salah and tied back to the existing producing facilities in Reg for further transport of the gas to the Krechba central processing facility for carbon dioxide removal and gas export.
The partnership expects first gas from the southern fields in the first half of 2014. The investment shares of the three partners are Sonatrach 35%, BP 33.15%, and Statoil 31.85%.
Husky resumes operations at Lloydminster upgrader
Husky Energy Inc. reports that its Lloydminster, Sask., heavy oil upgrader has resumed normal operations. The upgrader is currently operating at 75-85% of its capacity and is ramping up towards full production.
A minor fire on Feb. 2 damaged a hydrocracker fractionation unit that supplies product to the coker. Husky said while damage was not extensive, repairs took place in a congested space under extremely cold weather.
The company has determined that the fire started because a pipeline froze and burst, releasing fuel onto equipment.
Husky's 2009 fact sheets says that the upgrader has a 82,000 b/d capacity and the feedstock for the upgrader is heavy oil from northeastern Alberta and western Saskatchewan, and bitumen from Husky's Tucker oil sands project 30 km northwest of Cold Lake, Alta. This heavy oil and bitumen is mixed with lighter hydrocarbons (condensate or naphtha) to reduce the viscosity, allowing it to flow through Husky and third party pipelines to the upgrader.
Husky estimates that the overall pretax costs including repairs was $80-$90 million (Can.) which represents the facility running at reduced rates and considers the market price environment during the affected period and through ramp up.
It mitigated financial impacts by maintaining daily production at about 40-50% of normal rates during the repair process.
Statoil submits Vigdis North-East plan
Statoil submitted a 4.2 billion kroner plan to the Norwegian Ministry of Petroleum and Energy for the development and operation for Vigdis North-East in the Tampen area of the North Sea.
The company expects to start production from the field in December 2012.
This is the second fast-track development plan that Statoil has submitted to the Norwegian Ministry of Petroleum and Energy this year. Earlier in the year, Statoil submitted a plan for the development of Visund South (Pan-Pandora).
Vigdis North-East is planned as a subsea development, 1.6 km from the existing subsea installation on the Vigdis field.
The development will have a standard template with three producing wells and one water-injection well. A new pipeline will transport produced oil and gas to the existing Vigdis B template and then existing infrastructure will carry the production 7 km to the Snorre A tension-leg platform.
Statoil expects to recover about 33 million boe from a fluvial sandstone reservoir in the Early Jurassic Statfjord formation. The company drilled the discovery well 34/7-34 to 2,670-m TVD subsea in March 2009 (OGJ Online, Mar. 28, 2009).
Production starts at Statoil's Peregrino field
Statoil started producing heavy oil from Peregrino field off Brazil. The company plans to gradually ramp up production to a plateau of 100,000 boe/d.
Peregrino lies in 100 m off water 85 km off Brazil in the Campos basin on licenses BMC-7 and BMC-47.
The first development phase includes two drilling and wellhead platforms and a floating production, storage, and offloading vessel.
The company plans to drill 30 horizontal production wells and 7 wells for injecting produced water back into the reservoir for recovering an estimated 300-600 million boe. The oil reservoir lies at a 2,300 m depth below sea level.
The field was discovered in 1994. Statoil (Hydro ASA) acquired a 50% stake in the discovery in 2005, and the remaining 50% and its operatorship from Anadarko Petroleum Corp. in 2008 (OGJ Online, May 4, 2008). Peregrino's development plan was approved by the Brazilian authorities in 2007.
In May 2010, Statoil sold a 40% stake in Peregrino to the Sinochem Group. The closing of the transaction is pending governmental approvals.
Statoil is currently drilling an exploration well at Peregrino South to explore for additional potential in the area. Following completion of this well, it plans to drill one additional well in the area.
PROCESSING — Quick TakesKazakhstan Petrochemical awards contract
Kazakhstan Petrochemical Industries Inc. LLP, Almaty, has awarded Lummus Technology, a CB&I company, a contract for the license and basic engineering of a propane dehydrogenation unit and a polypropylene plant, both to be part of KPI's gas processing complex planned for the western Atyrau region.
Each unit will have a design capacity of 500,000 tonnes/year.
The propane dehydrogenation unit will use the CATOFIN technology to convert propane to propylene. The polypropylene plant will use the Novolen advanced gas-phase polypropylene technology, which will enable KPI to produce polypropylene products for local and export markets, said the CB&I announcement.
KPI is registered under the laws of the Republic of Kazakhstan with the aim to develop and operate a worldscale gas-to-polymers complex in western Kazakhstan.
FCC CO2 pilot trial starts up in Brazil
An industry research group has started a pilot-scale trial of oxycombustion as a way to lower emissions of carbon dioxide from refinery fluid catalytic cracking units.
The CO2 Capture Project (CCP) is testing a full-burn FCCU at a Petrobras research complex in Parana, Brazil. It expects the project to confirm the technical and economic viability of retrofitting an FCCU to allow CO2 capture through oxycombustion.
It hopes the test will advance a technology able to capture as much as 95% of FCC CO2 emissions, which can be 20-30% of all emissions from a typical refinery.
A normal FCCU regenerates catalyst by burning off deposited coke in air. With oxycombustion, pure oxygen, diluted with recycled CO2 to maintain thermal balance and catalyst fluidization, replaces air.
The project will test start-up and shutdown procedures and different operational conditions and process configurations. Scheduled for completion at the end of May, it will provide data for scale-up of the technology.
The pilot FCCU can process 33 b/d of hydrocarbon feed, emitting 1 ton/day of CO2. It has an adiabatic riser, stripper, and regenerator.
CCP members are BP PLC, Chevron Corp., Eni SPA, Petroleo Brasileiro SA, Royal Dutch Shell PLC, Suncor Energy Inc., and ConocoPhillips. The Electric Power Research Institute is an associate member.
TRANSPORTATION — Quick TakesInterOil moves ahead to build floating LNG
InterOil Corp.'s InterOil and Pacific LNG Operations Ltd. have agreed with Samsung Heavy Industries and FLEX LNG Ltd. to move ahead with construction and operation of a 2 million tonne/year (tpy) floating LNG processing vessel (FLNG). The agreements are conditional upon Flex shareholder approval and final investment decision (FID).
The FLNG project is part of proposed infrastructure to liquefy natural gas from onshore Elk and Antelope gas fields in the Gulf Province, Papua New Guinea, in line with preliminary arrangements with Energy World Corp. and to link with InterOil's proposed condensate stripping plant. That plant is being pursued in joint venture with the Mitsui Group.
The FLNG vessel's operations are targeted for mid-2014.
FLEX LNG has informed InterOil that it completed the generic frontend engineering and design (FEED) in 2009. The project-specific FEED is to start in May of this year, working towards an FID before yearend.
The agreements represent a continuation of the more than 12-month collaboration among Samsung Heavy Industries, FLEX LNG, InterOil, Pacific LNG, and Liquid Niugini Gas Ltd. (LNGL), InterOil's joint-venture LNG project company with Pacific LNG, to develop the first floating LNG production.
FLEX LNG and Samsung Heavy Industries will be responsible for design, engineering, construction, and commissioning of the FLNG vessel. FLEX LNG will also be joint operator of the FLNG vessel together with LNGL. Construction of the FLNG unit will be fully financed by FLEX LNG and Samsung Heavy Industries.
The FLNG vessel is to be moored alongside the proposed jetty in the Gulf Province, which will be shared with InterOil's proposed land-based LNG facilities, and have production capacity of up to 2 million tpy of LNG and be able to process an estimated 2.25 tcf of gas over 25 years.
FLEX LNG will receive 14.5% of the revenue, less agreed deductions and premiums, from the sale of LNG from the FLNG vessel for an initial 15 years. For the next 5 years, FLEX LNG will receive 12.5% of the revenue and 10% of the revenue for the last 5 years. During the 25 years of the contract, LNGL will become a part owner of the FLNG vessel.
Harvest Pipeline expands Arrowhead system
Harvest Pipeline Co. will build a 12-in. OD pipeline to bring additional quantities of Eagle Ford shale crude and condensate to Corpus Christi, Tex. The project will expand the capacity and reach of Harvest's existing Arrowhead pipeline system, particularly for shippers in LaSalle County.
The pipeline will have an initial capacity of more than 50,000 b/d, expandable to 90,000 b/d and is underpinned by long-term arrangements with Anadarko Petroleum Corp. and Flint Hills Resources.
Flint Hills recently finalized acquisition of a small-craft pier and wharf next to its existing oil terminal in Ingleside, Tex., which is already receiving Eagle Ford production. Flint Hills expects to begin outbound waterborne shipments of Eagle Ford production from the retrofitted assets by mid-2012.
Harvest began construction on a separate expansion of its Arrowhead system in January, a 25-mile line running from Cotulla, Tex., in LaSalle County, to an interconnect near Fowlerton, Tex. (OGJ Online, Jan. 11, 2011).
Koch plans Eagle Ford oil pipeline
Koch Pipeline Company LP plans to build an intrastate crude oil pipeline in Texas extending from Pettus to Corpus Christi that will transport production from the Eagle Ford shale. Current plans include a 20-in. OD line, currently in the permitting and right-of-way acquisition phase and expected to be complete mid-2012. Koch says the pipeline will increase its system capacity in the region to about 250,000 b/d.
Completion of the line is timed with affiliate Flint Hills Resources' updates to an Ingleside terminal capable of shipping up to 200,000 b/d of production via barge to other Gulf Coast markets. Koch Pipeline is also constructing a station near Helena in Karnes County along with connections to tank batteries in Karnes and DeWitt counties and a 16-in. OD, 120,000 b/d pipeline from Helena to Pettus. This pipeline will connect to the 20-in. line at Pettus and be expandable to more than 200,000 b/d. Koch expects to complete this line by late 2012 (OGJ Online, Dec. 17, 2010).
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