OGJ Newsletter

May 26, 2014
International news for oil and gas professionals

GENERAL INTERESTQuick Takes

Gazprom, CNPC sign 30-year natural gas supply contract

OAO Gazprom and China National Petroleum Corp. signed a 30-year natural gas supply contract reportedly worth $400 billion that earlier this year the two firms announced they were preparing to sign (OGJ Online, Apr. 30, 2014).

The contract signing in Shanghai by Alexey Miller, Gazprom management committee chairman, and Zhou Jiping, CNPC chairman, was in the presence of Russian President Vladimir Putin and Chinese President Xi Jinping.

The contract stipulates that 38 billion cu m/year will be supplied from Russia to China. It includes provisions for a price formula linked to oil prices and a take-or-pay clause.

Gas will be delivered via the Power of Siberia trunk line encompassing the Yakutia and Irkutsk production centers designed for supplying gas to Russia's Far East and China.

Gazprom's Miller called it "the biggest contract in the entire history of the USSR and Gazprom" and that more than 1 trillion cu m will be supplied during the contract period.

Gazprom said $55 billion will be invested in the construction of production and transmission facilities in Russia.

Gazprom and CNPC in 2009 signed a framework agreement on major terms and conditions of gas supply from Russia to China, and in 2013 signed an agreement on major terms and conditions of pipeline gas supply from Russia to China via the eastern route.

Gazprom says Ukraine's gas debt at $3.508 billion

Gazprom says Ukraine's debt for Russian natural gas supplies amounts to $3.508 billion, including unpaid deliveries for March and April.

Gazprom will be delivering "strictly prepaid amounts of gas to Ukraine, starting from June."

Alexey Miller, chairman of Gazprom's management committee, met on May 16 in Amsterdam with Andrey Kobolev, chief executive officer of Naftogaz of Ukraine, to discuss the issue.

EIA: Norway supplied 21% of Europe's gas in 2013

Norway, the world's third-largest natural gas exporter after Russia and Qatar, supplied 21% of total European gas needs in 2013, according to data from the US Energy Information Administration.

EIA estimates that Norway produced 3.97 tcf of dry gas in 2013, a decline of 0.18 tcf from 2012. As a result of its modest domestic demand, Norway's net exports for 2013 were 3.8 tcf of gas, representing 96% of its production.

"Norway's natural gas reaches the Continent mainly via its extensive export pipeline infrastructure, while a small fraction is exported as LNG by tanker. The largest recipients of Norway's natural gas exports in 2013 were the UK, Germany, France, the Netherlands, and Belgium," EIA said.

Norway's single largest gas field, Troll, produced 1 tcf in 2013, according to estimates from the Norwegian Petroleum Directorate, which accounted for 27% of Norway's total gas production that year. Three other major producing fields in 2013 were Ormen Lange (0.76 tcf), Asgard (0.34 tcf), and Kvitebjorn (0.24 tcf). These four fields produced more than 60% of Norway's total dry gas in 2013.

Exploration & DevelopmentQuick Takes

Petrobras confirms Santos basin presalt discovery

Initially reported as a discovery in February 2013, Brazil's Petroleo Brasileiro SA (Petrobras) has confirmed that its 1-SPS-98 (1-BRSA-1063-SPS) well, the first to be drilled on Block BM-S-50 offshore Brazil, has tested carbonate reservoirs with good permeability.

The block, informally known as Sagitario, is in Brazil's ultradeepwater Santos basin presalt region 194 km offshore Sao Paulo in 1,871 m of water. It has reached total depth of 7,110 m, the company said. From a starting point of 6,144 m, the company detected 159 m of presalt reservoirs bearing 32º API gravity oil.

Petrobras holds 60% interest in the well with partners BG E&P Brasil and Repsol Sinopec Brasil, each with 20% interest.

More exploration permits awarded off Western Australia

Two more exploration permit awards have been made offshore Western Australia in the continuing acreage release program.

Latest recipients are a joint venture of Inpex and Santos in the Browse basin and sole titleholder Neon Energy in the Dampier sub-basin. These follow an award to AWE last month in the Exmouth sub-basin.

Inpex and Santos have been awarded WA-502-P, about 60 km northwest of Inpex's Ichthys gas-condensate field. The block lies in 400-500 m of water about 475 km from Broome and covers an area of 580 sq km.

The award to Inpex is in line with the company's strategy of gathering permits close to Ichthys to maximize the potential and longevity of the development project. Even so, Inpex has elected to take 40% interest in the WA-502-P JV, leaving Santos with 60% and operatorship.

Neon Energy was awarded WA-503-P, taking on the task of operator and 100% ownership at this initial stage. Neon will acquire 80 sq km of 3D seismic by early 2015.

The primary exploration focus will be the Lower Cretaceous-Upper Jurassic basin margin fan deposits within the oil-rich Legendre trend. The company has already identified four leads based on existing 3D data.

The permit lies midway between and on trend with the Legendre oil field 30 km to the northeast and the Caribou gas field 30 km southwest.

AWE in April was awarded exploration permit WA-497-P immediately adjacent to the producing Pyrenees, Vincent, and Coniston oil fields and north of the Macedon gas field.

The permit covers an area of 560 sq km in 150-500 m of water.

AWE has 100% and is operator. The company will begin with a permit-wide 3D seismic survey to evaluate a number of what it sees as interesting prospects and leads.

Partners enter next phase for North Reggane gas project

Partners in the $3 billion North Reggane natural gas project in west-central Algeria have let a $976 million contract with Petrofac International (UAE) LLC (OGJ Online, Feb. 15, 2012).

The contract covers gas processing facilities, a gathering network, and export pipeline, and stipulates completion within 36 months. Plant capacity will be 283 MMcfd of gas. Production startup is slated for summer 2017.

The project's partners include Sonatrach 40%, Repsol YPF 29.25%, RWE Dea AG 19.5%, and Edison 11.25%.

Twenty-six development wells are planned. A 3D seismic campaign covering 1,450 sq km was completed in April. The acquired data is being processed and interpreted.

Exploration activities began in the North Reggane concession area in 2002, according to RWE Dea.

Drilling & ProductionQuick Takes

Leak shuts production at Statoil's Snorre B platform

Statoil ASA has shut down production from the Snorre B platform after it experienced a hydrocarbon leak into a recently identified crater measuring 100 cu m affiliated with a well at one of four seabed production frames, a company spokesman told OGJ on May 19. The crater was spotted May 17 after a routine inspection by a remotely operated underwater vehicle.

The company said heavy brine is now being pumped into the well to stabilize it. Production will remain shut down until the cause of the leak is found.

Thirty-three out of 136 workers on the platform were evacuated to a floating accommodation facility near Snorre A on May 17—the field's other production platform—and eventually onshore May 19. Statoil described these evacuated workers as "noncritical personnel related to handling this type of issue."

Statoil said it has kept the Norwegian Petroleum Safety Organization informed of its activities.

Snorre field reserves are estimated at 1.55 billion bbl of oil. Statoil in October 2013 recommended the construction of a drilling and processing platform for extracting the field's remaining reserves (OGJ Online, Oct. 28, 2013).

Production from the Snorre A platform was shut down in late 2004 after human error caused a natural gas leak, halting production of about 130,000 b/d of oil from the platform and 75,000 b/d from its Vigdis satellite, which used the Snorre A facilities for processing (OGJ Online, Jan. 18, 2005). Production resumed in early 2005 (OGJ Online, Feb. 9, 2005).

Partners in the Snorre license are Statoil 33.27556%, Petoro 30%, ExxonMobil E&P Norway 17.44596%, Idemitsu Petroleum Norge 9.6%, RWE Dea Norge 8.57108%, and Core Energy 1.1074%.

Eldfisk 2/7 S topside en route to southern North Sea

The Kvaerner ASA-constructed Eldfisk 2/7 S topside, completed in April, has departed the company's yard in Stord and is en route to the Greater Ekofisk area of the southern North Sea.

Operator ConocoPhillips, which let a 5.5 billion kroner contract for the topside to Kvaerner in 2011, will receive one combined living quarter and utility module, and a combined process and wellhead module for its integrated production platform (OGJ Online, Mar. 18, 2011).

The contract also included the fabrication of two bridges and one bridge support module and a flare, all of which were delivered in 2013 directly to the field from Kvaerner's subcontractors in Poland.

The topside will be towed to the field and lifted onto the steel jacket substructure in two separate lifts. Kvaerner will then perform the offshore hook-up work to prepare the platform for the start of production. The company said this work has already commenced and will continue through the summer and into the fall.

ConocoPhillips in 2011 also let a 1.3 billion kroner contract for modifying the existing Eldfisk 2/7 A, Eldfisk 2/7 FTP, Eldfisk 2/7 B, and Embla platforms as a consequence of the installation of the Eldfisk 2/7 S platform (OGJ Online, Mar. 23, 2014). Both contracts are part of ConocoPhillips's Eldfisk II 35-40 billion kroner redevelopment plan.

Eldfisk was discovered in 1970 and has been in production since 1979.

EnQuest eyes second-half Alma-Galia start

EnQuest PLC, London, expects production to start in this year's second half from its redevelopment of Alma and Galia oil fields in the UK North Sea (OGJ Online, June 25, 2012).

The company originally planned to restart production in fourth-quarter 2013 but early last year expanded the project in a move that boosted the reserves estimate.

Alma, originally known as Argyll, was the first field to produce oil commercially off the UK and the first in the world developed with a floating production system. Argyll was on production during 1975-92. Renamed Ardmore, it produced oil again during 2003-05.

EnQuest expects initial gross peak production from the Alma-Galia project of about 20,000 boe/d.

Production start awaits arrival on the field of the EnQuest floating production, storage, and offloading vessel, which is undergoing finishing and commissioning at OGN Group's Tyneside yard. The 248-m-long vessel, previously Bluewater's Uisge Gorm FPSO, has capacities to produce 57,000 boe/d and to store 625,000 bbl of crude oil.

Subsea equipment is in place in the fields, which are in about 80 m of water, 310 km southeast of Aberdeen. Risers and mooring systems have been installed.

EnQuest last year said expansion of the Alma-Galia project would extend FPSO vessel life by up to 15 years and increase the number of wells that would be drilled in a second development phase. It said drilling results to that point had met or exceeded expectations.

The expansion increased proved and probable reserves to 34 million boe from 29 million boe.

EnQuest holds 65% interest. Kuwait Foreign Petroleum Exploration Co. holds 35%.

PROCESSINGQuick Takes

Hess completes Tioga gas plant expansion

Hess Corp. has completed the expansion of its Tioga gas plant in northwestern North Dakota.

The expanded plant, which services natural gas produced from the Bakken tight-oil formation, is now fully operational and processing about 120 MMcfd. Output is soon expected to ramp-up to 250 MMcfd, and could rise to more than 300 MMcfd.

Prior to the expansion, the plant processed just 100 MMcfd.

Gov. Jack Dalrymple numbered among the state officials present at a ceremony May 19 to commemorate the opening of the expanded plant. Dalrymple called the expansion "an example of what we need to see, which is more capturing of natural gas and more added value to the product."

The expansion of the Tioga plant will reduce the amount of gas flared at Hess's Bakken operations to 15-20% from about 25% before the plant was shut down for construction work.

Gas production in North Dakota has risen sharply in recent years, in step with increasing oil production from the Bakken shale. However, the state lacks the midstream infrastructure needed to utilize all of the fuel.

Data from the North Dakota Industrial Commission show 33% of the state's nearly 1 bcfd of gas production was being flared in mid-May. State regulators earlier this year adopted a flaring-reduction plan that seeks to reduce flaring to 5% of gas production by 2020.

Hess is a leading operator in the Bakken, holding more than 640,000 net acres. The company is running a 17-rig drilling program this year, and expects net production for the full year will average from 80,000-90,000 boe/d.

Greg Hill, president and chief operating officer for Hess, said the Bakken will be the single biggest contributor to the company's production growth during the next 5 years. "We expect that by 2018, we'll be producing 150,000 boe/d from the Bakken," Hill said.

Hess plans to invest more than $1.5 billion in North Dakota infrastructure projects from 2012 to 2014.

More cryo capacity to handle Permian production

Lucid Energy Group LLC, Dallas, will install a 200-MMcfd cryogenic gas plant about 10 miles southeast of Big Lake in Reagan County, Tex., a site the company says is in the "heart of the Permian's Midland basin."

Manufactured by UOP Russell, Tulsa, the plant will bring Lucid's total processing capacity in the Midland basin to 320 MMcfd. It operates a combined 120 MMcfd of processing at its Silver and Munson plants, in Sterling and Irion counties, respectively.

The Big Lake plant will connect to Lucid's 450-mile pipeline system and process gas produced from the Wolfcamp shale in Irion, Reagan, and Crockett counties. Construction is under way with the plant expected to be in service in first-quarter 2015.

Big Lake will be the third gas processing plant Lucid has built since the company started operating in the Permian basin less than 2 years ago. Big Lake will connect to Lucid's existing high-pressure gas header system, which reaches across five counties in the Midland basin.

Lucid Energy formed in 2011 with equity support from EnCap Flatrock Midstream.

EPA okays ExxonMobil's Texas ethylene cracker project

The Environmental Appeals Board (EAB) for the US Environmental Protection Agency has approved a permit granted to ExxonMobil Chemical Co. to proceed with plans to build a natural gas-fired ethylene production unit at its existing olefins plant in Baytown, Tex., just east of Houston (OGJ Online, July 1, 2013; June 5, 2012).

The Washington, DC-based EAB rejected claims by Sierra Club that EPA Region 6 abused its discretion under the Clean Air Act when, in November 2013, it granted ExxonMobil's Baytown project a prevention of significant deterioration permit for the regulation of greenhouse gas emissions, according to a May 14 decision recently posted to EAB's web site.

In striking down all four allegations of discretionary abuse alleged by Sierra Club, EAB upheld Region 6's determination that the installation of carbon capture and sequestration as an add-on control technology would be too expensive, on a total cost basis, to be selected as the best available control technology for limiting GHG emissions from the proposed Baytown unit, according to the decision.

EPA finalized ExxonMobil's PDS permit for the Baytown plant on May 14 as a result of the decision, which will allow the company to begin construction on the project, the agency said in a May 16 release.

EBA's ruling on the GHG-related permit precedes by a day EPA's May 15 proposal of heightened air emissions requirements for US refineries (OGJ Online, May 15, 2014).

ExxonMobil previously said it expected the Baytown project, which calls for construction of a 1.5-million-tpy ethane cracker at the complex to convert ethylene to premium polyethylene products for world markets, to be commissioned in 2016 (OGJ Online, June 5, 2012).

TRANSPORTATIONQuick Takes

PSA cites Statoil for leak at Hammerfest LNG plant

An investigation into a Jan. 5 hydrocarbon leak at Statoil ASA's Hammerfest LNG facility in northern Norway found that the event "had a big accident potential and could have led to loss of life," according to a May 15 report from the Norwegian Petroleum Safety Authority (PSA).

The incident—which occurred during normal operation at the process plant on Melkoya Island outside Hammerfest and shut in production for 3 days—resulted in the release of 250-750 kg of gas from the stuffing box of pump 25-PA-103B, PSA reported. "Wear was observed on one of the gaskets in the stuffing box, but its underlying causes were not identified," it said.

Although the incident didn't cause personal injuries or material damage, PSA said, "Had the hydrocarbon leak ignited, an explosion would have resulted, which could have caused two fatalities." One person was reportedly in the immediate vicinity of the leak and another out in the plant "could have been affected," the authority said.

PSA noted that an explosion "would also have caused damage to equipment and structures, and a lengthy shutdown of the plant."

PSA ordered the company to explain how it would fix the issue in a letter to Statoil.

FERC issues FEIS for Maine's Downeast LNG project

The US Federal Energy Regulatory Commission has issued its final environmental impact statement (FEIS) for the Downeast LNG project in Washington County, Maine, proposed by Downeast LNG Inc. and Downeast Pipeline LLC.

FERC concluded that approval of the proposed project would ensure that most impacts in the project area would be avoided or reduced to less than significant levels provided that Downeast implements the mitigation measures recommended in the FEIS.

The commission explained that construction and operation of the project would primarily result in temporary and short-term environmental impacts, and that some long-term and permanent environmental impacts would occur.

FERC said it will take recommendations for the project into consideration when it makes a decision.

The project would provide 500 MMcfd of gas to New England. The proposed facilities notably include a marine terminal with a 3,862-ft pier for LNG vessels ranging 70,000-165,000 cu m in capacity and two 160,000-cu-m full-containment LNG storage tanks.

A supplemental EIS for the project was released in April 2013 (OGJ Online, Apr. 2, 2013). A draft EIS was issued 4 years prior, noting, as with the FEIS, that the US Coast Guard's letter of recommendation that the Passamaquoddy Bay waterway was suitable for the type and frequency of marine traffic that would be associated with the project if risk mitigation recommendations outlined in the Water Suitability Report are fully implemented (OGJ Online, May 18, 2009).

Koch to expand Eagle Ford crude line

Koch Pipeline Co. LP, an indirect, wholly owned subsidiary of Koch Industries Inc., plans to install a 24-mile, 200,000-b/d pipeline in San Patricio County, Tex., effectively expanding the company's South Texas crude oil pipeline system.

Koch operates 540 miles of crude oil transportation lines in Texas. The 16-in. line is expected to begin service in the second quarter.

"We are seeing additional opportunities with the Eagle Ford shale play and this new pipeline will help us move domestic crude to the US market more efficiently by using a combination of new and existing pipeline infrastructure," said Bob O'Hair, Koch Pipeline executive vice-president.

Keyera takes stake in Enbridge Athabasca diluent line

Keyera Corp. has agreed with Enbridge Pipelines (Athabasca) Inc. to participate in the Norlite Pipeline as 30% nonoperating owner. The Norlite Pipeline will move diluent for producers from the Edmonton-Fort Saskatchewan area into the Athabasca oil sands region. The pipeline will initially run from Enbridge's Stonefell Terminal near Fort Saskatchewan northward to Suncor's East Tank Farm, adjacent to Enbridge's Athabasca Terminal. Along the route, Norlite will pass by both Enbridge's Cheecham Terminal and the Keyera-Enbridge South Cheecham Rail and Truck Terminal.

Norlite will use 20-in. OD pipe to ship 280,000 b/d. Throughput commitments from Suncor Energy Inc. (SEI), Total E&P Canada Ltd., and Teck Resources Ltd. for the Fort Hills oil sands project and by Suncor Energy Oil Sands LP (SEOS) for its proprietary oil sands production will anchor the pipeline.

If Enbridge secures additional long-term commitments, Norlite could be increased to a 24-in. OD and could also include a lateral to Enbridge's Norealis Terminal. Enbridge expects to finalize project scope later this year, at which time estimated cost will be determined. It expects the project to enter service second-quarter 2017.

The throughput commitments SEI, Total, Teck and SEOS made on the Norlite Pipeline include transportation on Keyera's diluent system between Edmonton and Stonefell. Keyera's diluent transportation system will deliver into the Norlite Pipeline.

Enbridge ships diluent 1,588 miles from the Chicago area to Edmonton on its Southern Lights Pipeline (OGJ Online, June 5, 2013).