OGJ Newsletter

May 6, 2013
International news for oil and gas professionals

GENERAL INTERESTQuick Takes

Southwestern Energy to buy assets from Chesapeake

Southwestern Energy Co. plans to buy natural gas assets in Pennsylvania's Marcellus shale from Chesapeake Energy Corp. and its partners for $93 million.

The transaction involves 162,000 net acres in Susquehanna, Wyoming, Tioga, and Sullivan counties. Current net production from the properties is about 2 MMcfd from 17 gross wells. Closing is expected by May 15. After closing, Southwestern will have 337,000 net acres in the Marcellus.

Sanctions reduced Iran's oil exports in 2012

Iran's crude oil and lease condensate exports last year fell to their lowest level since 1986 as the US and the European Union tightened sanctions targeting Iran's oil sector, the US Energy Information Administration said.

Iran's 2012 crude oil and lease condensate exports declined to 1.5 million b/d in 2012 and its net estimated oil export revenue was $69 billion, compared with $95 billion in 2011. Besides, Iran's crude oil and condensate production dropped by 17% and liquid fuels consumption, including gasoline, diesel, jet fuel, and other products, dropped by 1%.

The US and EU measures prohibited large-scale investment in Iran's oil and gas sector and cut its access to European and US sources of financial transactions. Sanctions resulted in less investment in Iran's oil sector. New projects by several foreign companies have been cancelled and existing projects are negatively affected.

Alberta Energy Regulator leaders picked

Alberta Energy has selected leaders of the Alberta Energy Regulator, a new independent agency consolidating activities of the Energy Resources and Conservation Board with the ministerial department Environment and Sustainable Resource Development.

The Responsible Energy Development Act established the agency last year to regulate Alberta's upstream oil, oil sands, natural gas, and coal development (OGJ Online, Nov. 26, 2012). It will begin phasing in operations in June and eventually cover the full lifecycle of an energy project, from application and construction to production, abandonment, and reclamation.

Gerry Protti has been named board chair, responsible for setting the direction of the regulator's business and affairs. He has served as chair of several boards and committees, including the Canadian Association of Petroleum Producers.

Jim Ellis was named chief executive officer, responsible for day-to-day operations. He has served as deputy minister of the provincial energy and environmental departments and most recently was the lead Alberta official working on a Canadian energy strategy.

Hess looking to sell E&P assets in Indonesia

Hess Corp. wants to divest its exploration and production assets in Indonesia and Thailand where it also is trying to sell its remaining downstream businesses, including terminals, retail, marketing, and trading divisions.

In Thailand, Hess operates onshore Sinphuhorm gas field with a 35% interest. Offshore Indonesia, Hess is a partner with Kuwait Foreign Petroleum Exploration in Pangkah gas field. Hess also has 100% interest in deepwater block Semai V offshore Indonesia.

In other news, Hess closed its sale of Russian subsidiary Samara-Nafta to OAO Lukoil for a $2.05 billion. The aftertax proceeds to Hess, based on its 90% interest in Samara-Nafta, were $1.9 billion.

So far this year, Hess has announced asset sales amounting to $3.5 billion. As previously announced, the company is repaying debt and strengthening its balance sheet.

Exploration & DevelopmentQuick Takes

Cretaceous flows 57 MMscfd in Tanzania deepwater

BG Group has drillstem tested gas from better than expected properties in the deeper Cretaceous reservoir at its Mzia-2 well on Block 1 offshore Tanzania.

The first test of a Cretaceous discovery in deep water off Tanzania flowed at a maximum rate of 57 MMscfd of gas limited by test equipment capacity.

Mzia-2 is 4 km from the Mzia-1 discovery in 1,620 m of water and 45 km off southern Tanzania. It is 22 km north of the Jodari-1 discovery well, also on Block 1, where a successful drillstem test was completed in March on the shallower Tertiary reservoir.

BG Group Chief Executive Chris Finlayson said, "The successful Mzia-2 drill stem test follows completion of a multiwell appraisal program earlier this year on the nearby Jodari field. Results from the current campaign demonstrate the excellent quality of our interests offshore Tanzania, where our resources, and those of other participants in the region, are helping support plans for a multitrain LNG export project.

"While we continue exploration and appraisal offshore, BG Group and others are jointly studying suitable sites for a potential onshore LNG terminal and anticipate providing proposed locations to the Tanzania government in the next few months," Finlayson said.

The drillship Deepsea Metro-1 has moved to drill the Ngisi-1 exploratory well adjacent to the Pweza and Chewa discoveries on Block 4.

BG Group will use data from the current exploration and appraisal campaign and a recently completed 3D seismic survey to help identify new offshore targets for a third exploration program to start in late 2013.

Prior to Mzia-2, BG Group's acreage offshore Tanzania had produced seven consecutive natural gas discoveries, two successful appraisal wells and a successful test at Jodari field.

BG Group as operator has a 60% interest in Blocks 1, 3, and 4 offshore Tanzania, and Ophir Energy has 40%.

Lukoil to develop West Siberia license

Lukoil plans to begin drilling production wells in September 2014 an early-oil project on its Imilorsko-Istochnoye license in West Siberia (OGJ Online, Feb. 25, 2013).

It hopes to begin oil production in March 2015.

The company will shoot new seismic surveys during 2013-16, retest 15 existing exploratory wells, and drill four new exploration wells. It will use results to recalculate reserves.

Lukoil said early estimates put reserves in the area at 193.7 million tonnes of crude oil.

Eni boosts outlook for gas off Mozambique

Eni has increased its estimate of natural gas in place in its license offshore Mozambique to 80 tcf from 75 tcf after completing appraisal drilling.

Eni Mamba South 3, the ninth well drilled on Area 4, encountered 214 m of gas pay in high quality Oligocene and Eocene strata, proving communication with the same reservoirs in Mamba South 1 and 2 and Mamba North East 1 and 2.

Mamba South 3, drilled in 1,571 m of water, reached 4,948 m TD. It's 6 km north of Mamba South 1, 12 km northwest of Mamba South 2, and 50 km off the Cabo Delgado coast.

Eni said it is completing development plans.

It plans to drill an exploration prospect called Agulha 1 in the southern part of Area 4 to test deeper potential.

Eni, operator, has a 70% participating interests. Galp Energia, KOGAS, and ENH hold 10% interests each. ENH's interest is carried through exploration.

Petrochina Co. Ltd. has agreed to acquire 28.57% of Eni East Africa in a deal, subject to approvals, that will give China National Petroleum Corp. a 20% stake in Area 4 (OGJ Online, Mar. 14, 2013).

Total well cuts oil pay offshore Ivory Coast

The Total Ivoire-1X exploratory well has cut 28 m of net oil pay in a 100-m Cetaceous section offshore Ivory Coast. The oil is 35º gravity.

Total E&P Cote d'Ivoire and partners drilled the well to 5,044 m TD in 2,280 m of water in the western part of Block CI-100. It's the first well on the block.

Total said the results confirm extension into the block of active petroleum systems proven in the Tano basin, which includes fields such as Jubilee offshore Ghana.

The Total subsidiary is analyzing data to develop an appraisal program and explore prospects farther east.

Interests are Total 60%, Yam's Petroleum LLC 25, and Petroci Holding 15%.

Drilling & ProductionQuick Takes

Imperial starts up Kearl oil sands mine

Production of mined diluted bitumen has begun from the first of three trains at Imperial Oil Ltd.'s Kearl oil sands project 75 km northeast of Fort McMurray, Alta. (OGJ Online, Feb. 4, 2013).

Production will reach 110,000 b/d when all three trains are online later this year.

The project is the first oil sands mine in Alberta that has no upgrader. Kearl uses a proprietary froth treatment technology that enables salable bitumen to be produced with one processing step.

An expansion project will double Kearl production by late 2015 (OGJ Online, Jan. 19, 2012). Imperial expects future debottlenecking to raise output to about 345,000 b/d by about 2020. It estimates ultimate recovery of 4.6 billion bbl of bitumen over more than 40 years.

Because the project requires no upgrader, Kearl's lifecycle emissions of greenhouse gases will be comparable to those of many other crude oils processed in the US, according to project partner ExxonMobil Corp.

Kearl has water storage to eliminate withdrawal from rivers during periods of low flow, "progressive land reclamation, earlier tailings reclamation than other oil sands mining operations, and a state-of-the-art waterfowl deterrent system," ExxonMobil said.

Imperial holds a 70.96% interest in the Kearl project and is the operator. ExxonMobil, which owns 69.6% of Imperial, holds the remaining 29.04% Kearl interest through ExxonMobil Canada Properties, a wholly owned subsidiary.

ADNOC picks Shell for Bab sour gas work

Abu Dhabi National Oil Co. selected Shell as its partner to develop sour gas reservoirs in giant Bab gas-condensate field 150 km southwest of the city of Abu Dhabi to supply local markets.

ADNOC said the Bab megaproject will include the installation of a gas-processing and treatment plant, including a gathering system and sulfur-recovery facilities, able to process 1 billion scfd of sour gas.

The complex will yield 520 Mmscfd of sales gas for delivery to the domestic distribution network by 2020. ADNOC will hold a 60% interest in the joint venture, Shell 40%.

Separately, Abu Dhabi Co. for Onshore Operations, an ADNOC operating company and operator of Bab gas wells for the parent company, has inaugurated a three-train gas compression complex able to process 1.8 bscfd of Bab field gas and condensate. Production from the complex goes to facilities operated by Abu Dhabi Gas Industries (Gasco) for final processing.

A second phase of the Bab compression project, now in the tendering phase, will raise sustainable gas production to 2.1 bscfd and raise ADCO's gas compression capacity to 2.4 bscfd. It will include construction of a compression station with 600 MMscfd of capacity, a new direct gathering manifold station, extension of two remote manifold stations, and tie-in of 32 new gas wells. Completion is scheduled by the third quarter of 2015.

A third phase is planned, with completion due in 2018. When that phase is complete, the compression project will have raised Bab gas production by 25%.

BSEE, Helix test spill containment equipment

The US Bureau of Safety and Environmental Enforcement (BSEE) has started a drill to test the deployment of Helix Well Containment Group's capping stack system for Noble Energy Inc. in the deepwater Gulf of Mexico.

BSEE Director Jim Watson said the drill started Apr. 30. The drill is a test of the Helix equipment and also a test of Noble's ability to obtain and deploy a containment system.

The capping stack system is designed to stop the release of oil and natural gas in case a blowout preventer were to be ineffective. BSEE regulations require an operator be able to demonstrate that it has immediate access to surface and subsea containment equipment to promptly respond to a blowout or other loss of well control.

"We fully expect operators to have the plans, equipment, and capabilities in place to respond to a subsea blowout in deepwater at a moment's notice," Watson said. "These types of exercises give us an opportunity to see how the equipment is deployed in real-world conditions and to learn lessons that can be shared across the industry."

Helix's capping stack is to be deployed in 5,047 ft of water, latched to a test wellhead, and pressurized, BSSE said of the drill, which is expected to take several days.

Helix is one of two consortia that provide contract access to well containment equipment to oil and gas operators. This equipment is required by BSEE for drilling with subsea blowout preventers in deepwater. The Marine Well Containment Co. successfully completed a similar deployment in July 2012.

Apache starts Tonto oil flow offshore the UK

Apache Corp. has started production from Tonto oil field in the North Sea offshore the UK at 10,346 b/d of oil from one well.

The Tonto-1 production well was drilled directionally from the Forties Bravo production platform. An appraisal wellbore found 62 ft of net oil pay in an Eocene sandstone at 6,325 ft. A horizontal completion lateral logged 243 ft MD of net oil pay.

Apache identified production potential of the reservoir, which is above the main Forties Paleocene reservoir, with seismic inversion. It started production before a 3D seismic survey to be shot over Forties in July to allow imaging of production patterns in the Eocene reservoir, which will help target future production wells.

The company, with a 100% working interest, plans to drill another development well by the end of 2013 after analysis of time-lapse seismic data.

Like Maule and Bacchus, other oil fields brought on stream in the Forties area in the last 3 years, Tonto qualifies for a small-field tax allowance (OGJ Online, Aug. 2, 2012).

PROCESSINGQuick Takes

Enbridge to build East Texas cryo plant

Enbridge Energy Partners LP, Houston, will build a 150-MMcfd cryogenic natural gas processing plant near Beckville in Panola County, Tex., the company has announced, estimating the cost of the project at $140 million.

Construction will begin in late 2013 with start-up by early 2015.

Adding the Beckville plant will expand the company's processing capacity in the Cotton Valley and Haynesville shales to about 820 MMcfd, it said. The plant will connect with existing NGL infrastructure in the area.

Enbridge's East Texas system includes about 3,900 miles of gas gathering and transportation pipelines, about 200,000 hp of compression, eight gas-treating plants and, with the addition of the new Beckville plant, six gas processing plants.

Other gas plants in Enbridge's East Texas system are the Avenger plant in Marion County, Grapeland in Houston County, Henderson in Rusk County, Longview in Gregg County, and Carthage (idled), in Panola County.

Rosneft, Mitsui sign petrochemical MOU

Rosneft and Mitsui & Co. have signed a memorandum of understanding to jointly build a large petrochemical complex in far eastern Russia.

The plant is to have capacity to process 3.4 million tonnes/year (tpy) of feedstock, mainly naphtha, to produce 2 million tpy of ethylene and propylene. Plans include production of polymers and other petrochemical products.

The site is in the Primorsk region near the village of Pervostroyiteley in Nakhodka City District.

Rosneft subsidiary Far East Petrochemical Co., incorporated in 2011, is the developer.

Feedstock will come from Rosneft's 7 million tpy Achinsk refinery, 8 million tpy Komsomolsk refinery, and petrochemical plant at its 11 million tpy Angarsk refinery.

The complex is to have its own sea terminal in an ice-free port.

The memorandum calls for cooperation in engineering design, followed by a final investment decision.

Satorp executive says Jubail refinery 97% complete

Construction is 97% complete of the 400,000 b/d full-conversion Saudi Aramco Total Refinery & Petrochemicals Co. (Satorp) refinery at Jubail, Saudi Arabia (OGJ Online, Sept. 15, 2011).

During a visit by chief executives of Saudi Aramco and Total, Mohammed J. Al-Hammad, executive director of the project, said all units will be in operation by November. Exports of fuel oil could begin in August, he said.

The $14 billion refinery will process Arab heavy crude and yield petrochemicals as well as high-quality fuels. It will be Saudi Arabia's first producer of petroleum coke and paraxylene.

TRANSPORTATIONQuick Takes

Pipeline outlets seen crucial to Canadian oil producers

Although a price squeeze on Canadian producers of bitumen and heavy oil has eased recently, pipeline access to waterborne trade remains essential, according to an analyst at Scotiabank, Toronto.

The price of Western Canadian Select (WCS) heavy crude oil rose from $58.38/bbl (US) in February to $66.73/bbl in March and about $68/bbl in April, reported the analyst, Patricia Mohr, in a commodity price report. The WCS discount against West Texas Intermediate crude fell from a record high $36.94/bbl in February to $26.23/bbl in March, $23.07/bbl in April, and, based on futures values, $13.90/bbl in May. The WCS discount is growing again in June.

Mohr attributed the recent narrowing of the WCS-WTI discount to:

• A seasonal increase in demand for Western Canadian crude oil as refineries in the US Midwest increased runs after unusually high maintenance downtime early in 2013.

• Operational enhancements allowing increased throughput in the pipeline system.

• Increased use of rail transportation, allowing crude from Alberta to reach the Gulf Coast, where heavy crude has higher value than it does at the WTI pricing hub at Cushing, Okla.

Mohr noted that capacity of the Seaway Pipeline between Cushing and the Gulf Coast expanded to 400,000 b/d in February but said actual throughput has remained at 300,000 b/d, dominated by light crude.

The analyst said: "The overall pipeline system from Canada to the United States still constrains flows of Western Canada's oil to Texas, where heavy Mayan crude from Mexico (only marginally higher in quality than WCS Heavy) is currently priced at $96/bbl—above WTI oil at $91—and $25 above the $68 garnered by heavy oil producers in Western Canada, subtracting a $2-3/bbl quality discount but not adjusting for transportation costs."

Approval of the US-Canadian border crossing of the Keystone XL pipeline, she said, would boost flows of Canadian crude to the Gulf Coast refineries needing heavy feedstock, "significantly boosting prices for Alberta and Saskatchewan heavy crude."

Citing the delay in approval of the border crossing, TransCanada Corp. last week changed its in-service date for the project to late 2015 from late 2014 or early 2015 (OGJ Online, Apr. 26, 2012).

If Canadian oil producers are to be assured of world prices, Mohr said, pipeline access to the West and East Coasts must increase.

The average price of Saudi Arabian heavy crude delivered to China in the first quarter this year was $106/bbl, she pointed out.

"Given the low cost of tanker shipping and pipeline transportation, the netback for Alberta sales of heavy crude in China would have been quite high in the first quarter, probably more than $95/bbl, had transportation infrastructure been available," she said, adding that tanker shipping from British Columbia to China costs only $3-4/bbl.

Canada publishes onshore pipeline regulations

Canada's National Energy Board has published "Regulations Amending the Onshore Pipeline Regulations, 1999." The regulations clarify requirements for federally regulated pipelines regarding management systems, with the purpose of protecting the public, workers, and the environment, according to NEB.

NEB requires pipeline companies to anticipate, prevent, manage, and mitigate potentially dangerous conditions associated with their pipelines. When implemented, the new requirements can effectively manage risk and promote safe pipeline operation, NEB said.

The regulations make it clear that management systems must apply to key company programs for safety, pipeline integrity, security, environmental protection, and emergency management, according to NEB. They also require these systems be in place through each phase of the pipeline's lifecycle; from design, materials, construction, and operation all the way through to abandonment.

NEB described the regulations as including provisions focused on a company's senior leadership for accountability of its management systems, the company's safety culture, and the achievement of outcomes related to safety of the public and environmental protection.

Furthermore, it said, the companies must have an internal reporting policy encouraging employees to bring forward, without fear of reprisals, hazards and risks they may encounter during their work activities.

The regulations rename the "Onshore Pipeline Regulations, 1999" as the "National Energy Board Onshore Pipeline Regulations."