OGJ Newsletter

May 12, 2014
International news for oil and gas professionals

GENERAL INTERESTQuick Takes

Cedigaz: Global gas market growth slowed in 2013

Global natural gas consumption rose by just 1.3% in 2013, down from an average of 2.8%/year in the previous decade, according to a recent report from Cedigaz, the international natural gas association based near Paris. Production growth also slowed—to 0.8%—with the association ascribing the change to supply constraints in a tense geopolitical environment.

Increased pipeline trade led international natural gas trade 2.1% higher year-on-year, overcoming a stagnant, supply-restricted LNG market, Cedigaz said. Interregional pipeline gas exports were strongest from the CIS to Europe (+15%) and China (+36%). Global trade totaled 1,048 billion cu m (bcm).

Cedigaz's report, "2013 Natural Gas Year in Review," said the commodity still suffers from severe competition with coal in the power generation sector, with actual European Union consumption down 1.9% to 460 bcm, the lowest level in 15 years. In the US, rising year-on-year gas prices made coal more competitive and penalized gas consumption in power generation, causing it to fall 10.5%.

Gas production totaled 3,377 bcm, with Cedigaz citing declining mature and conventional fields combined with insufficient reserve replacement in describing the slow rate of growth. It said the lack of upstream investment was particularly acute in emerging markets due to their relatively unfavorable regulatory and fiscal climates.

Encana to buy Eagle Ford acreage for $3.1 billion

Encana Corp. unit Encana Oil & Gas Inc. reached an agreement with Freeport-McMoRan Oil & Gas LCC, a subsidiary of Freeport-McMoRan Copper & Gold Inc., to acquire 45,500 net acres in Karnes, Wilson, and Atascosa counties, part of the Eagle Ford shale in South Texas, for $3.1 billion, effective Apr. 1.

The acreage produced 53,000 boe/d in the first quarter and has an estimated drilling inventory of more than 400 locations. At yearend 2013, net proved reserves totaled 59 million boe while net proved and probable reserves totaled 69 million boe.

Production from the acreage in the first quarter included 46,000 b/d of total liquids production and 44 MMcfd of natural gas, generating operating cash flow of $327 million, with 75% of the total production volumes for the period being oil.

"With this transaction, combined with our announced divestments of Jonah and properties in East Texas, we're replacing natural gas production with high margin oil and liquids production," said Doug Suttles, Encana president and chief executive officer (OGJ Online, Mar. 31, 2014; Apr. 29, 2014).

The move advances the company's strategy by adding a sixth core growth asset in an established oil production basin. Encana said the deal will double the company's current oil production.

Encana expects the assets to be free cash flow positive in 2014, allowing Encana to execute its existing capital plan for the year without redirecting capital from its other five core growth plays. Through the second half of this year, Encana plans to start ramping up its activity in the play and exit 2014 with at least four drilling rigs running.

Sabine, Forest sign merger agreement

Sabine Oil & Gas LLC and Forest Oil Corp. have signed a definitive merger agreement under which the companies will combine their businesses in an all-stock transaction. The combined entity will be known as Sabine Oil & Gas Corp., headquartered in Houston, and led by Sabine's current executive management team.

The combined entity will have a 207,000 net acreage position in East Texas and a 65,000 net acreage position in the Eagle Ford.

The companies emphasized that the complementary nature of their assets present opportunities to generate savings through operating synergies, benefits of scale, and optimized capital allocation.

"Since Sabine began in 2007, we have focused on building a significant asset base in East Texas, and with this combination, we have created a leading industry position in this highly economic, multiplay basin," said David Sambrooks, Sabine president and chief executive officer. The companies also have assets in the Granite Wash, Permian, and Arkoma.

The combined company will have estimated proved reserves of 1.5 tcf of gas equivalent, of which 71% is gas, as of Dec. 31, 2013. This year's production totals 345 MMcfed, of which 65% is gas.

Upon completion of the transaction, Sambrooks will serve as the company's chairman as well as president and chief executive officer. Shane Bayless will serve as executive-vice president and chief financial officer, and Todd Levesque will serve as executive vice-president and chief operating officer.

Devon, Cimarex to acquire Cana-Woodford assets

Devon Energy Corp., Oklahoma City, and Cimarex Energy Co., Denver, reported entering into an acquisition scheme for assets primarily in the Cana-Woodford shale play in western Oklahoma.

Cimarex signed a purchase and sale agreement to acquire the assets for $497.4 million in cash. Simultaneously, Cimarex entered into an agreement with Devon to sell at closing a 50% interest in these assets for $248.7 million.

Cimarex's share of the assets includes its estimate of proved developed reserves of about 140 bcf of gas equivalent (64% gas) at Jan. 1, current production of about 35 MMcfed (63% gas) and 50,000 net acres, including 30,000 net acres in the Cana-Woodford area and oil-rich East Cana area. About 65% of the proved developed reserves are associated with properties in which Cimarex already owns a working interest, it said.

Devon's portion of the agreed acquisition, meanwhile, includes current production of 5,800 boe/d (37% liquids) and proved reserves of about 23 million boe as of Jan. 1.

"Consistent with our philosophy to add scale and scope to our operations, this acquisition significantly bolsters our position in one of our liquids-rich core development areas," said Devon COO Dave Hager, adding, "These assets directly overlap our existing core Cana position and expand our exposure to other western Oklahoma oil and gas plays."

Cimarex has its principal operations in the US Midcontinent and Permian basin.

Exploration & DevelopmentQuick Takes

BP plans to exit Utica shale

BP America reported that it will not proceed with development of its nearly 100,000 acres of leasehold in the emerging Utica shale in Ohio. Regulatory filings show the company recorded a $521 million write-off relating to its Utica acreage in this year's first quarter.

The announcement follows the company's decision to create a separate business around its onshore oil and gas activities in the US Lower 48, and was made in conjunction with the release of first-quarter financial results.

Brian Gilvary, BP chief financial officer, declined to say if the company had any plans for the acreage.

"In terms of Utica, we've taken the write-off of the assets where we've made the appraisal wells. It's premature to say what we'll do with the remaining parts of that asset base," Gilvary told analysts on Apr. 29.

The company acquired its foothold in the Utica in March 2012, agreeing to lease about 84,000 acres in Trumball County, in far northeast Ohio, from the Associated Landowners of the Ohio Valley.

Data from the Ohio Department of Natural Resources shows the bulk of Utica permitting activity is occurring to the south in Carroll, Harrison, Columbiana, Noble, and Guernsey counties. The agency had issued 1,230 permits to drill in the formation as of Apr. 26.

Statoil: Johan Castberg fails to hit volume expectations

Statoil ASA and its PL532 partners concluded the 2013-14 Johan Castberg field exploration program by making an oil and gas discovery in the Drivis prospect in the Barents Sea. However, it represented just the second oil discovery in the field, falling beneath Statoil's volume expectations.

Statoil estimates total volumes in Drivis to be 44-63 million boe recoverable, of which 42-54 million bbl are oil. The discovery will be considered for tie-in to 7220/8-1 Johan Castberg.

Well 7220/7-3 S, 15 km southwest of the 7220/8-1 Johan Castberg discovery and 230 km northwest of Hammerfest, proved a 68-m gross gas column in the Sto formation and an 86-m gross oil column in the Sto and Nordmela formations.

The well was drilled to 2,029 m vertical depth below the sea surface and was terminated in the Fruholmen formation from the Late Triassic. Water depth at the site is 345 m. The well will now be permanently plugged and abandoned.

The West Hercules rig conducted the drilling. It will now move to projects outside the Norwegian continental shelf (NCS).

This is the seventh exploration well in PL532—the previous one was drilled in February (OGJ Online, Feb. 20, 2014). The license was awarded in the 20th licensing round in 2009 (OGJ Online, May 5, 2009).

Statoil launched a targeted exploration campaign around Johan Castberg in May 2013 to clarify additional oil potential in the area and make the development project more robust.

"Over the past year we have made a significant exploration effort in the Johan Castberg area," said Irene Rummelhoff, Statoil senior vice-president, exploration, on the NCS. "Five wells have been drilled back-to-back, giving us important subsurface information and a good understanding of the total resource base in the area.

"We are certainly glad to have an oil discovery in Drivis," said Rummelhoff. "However, the exploration program as a whole has not delivered on volume expectations. Out of the five wells drilled only two have resulted in oil discoveries." Statoil added that the results constitute an important input to the Johan Castberg field development project.

Statoil is PL532 operator with 50% interest. Partners are Eni Norge AS 30% and Petoro AS 20%.

Lundin Norway drills Johan Sverdrup appraisal wells

Lundin Norway AS, a wholly owned subsidiary of Lundin Petroleum AB, has drilled two appraisal wells in the Johan Sverdrup area in the North Sea's Norwegian continental shelf.

Appraisal well 16/2-19 found 6 m of good quality oil filled sandstone of lower Jurassic-upper Triassic age in the Geitungen area in the northeastern part of the Johan Sverdrup discovery. The well is 2.1 km north of appraisal well 16/2-12 and 3.2 km southeast of appraisal well 16/2-9S, both in PL265.

Statoil said the purpose of the well was to investigate the Jurassic presence, reservoir thickness, quality and distribution on the north-eastern edge of Johan Sverdrup discovery.

The well found 12 m of upper Jurassic spiculitic silty sandstone with no reservoir quality and 6 m of good quality sandstone of most likely lower Jurassic-upper Triassic age. Fluid sampling indicated an oil water-contact at 1,927-29 m below sea level. Those sediments are resting on a 37-m sequence of low-nonquality sediments of most likely Triassic Permian age before entering granitic basement.

Well 16/2-19A was drilled as a sidetrack 1,000 m toward the southwest, encountering 13 m gross of low-to-excellent quality upper Jurassic sandstone in a more central position within the Geitungen area.

The well found 10 m of oil-filled, low-to-medium quality upper Jurassic spiculitic silty sandstone above an oil-filled, 3-m sandstone of excellent quality, most likely Draupne sandstone facies of upper Jurassic age. Those sediments are resting on a 20-m sequence of nonreservoir quality carbonate and sandstone, most likely Permian age, before entering granitic basement. No oil water contact was established.

Wells 16/2-19 and 16/2-19A were drilled using the semisubmersible drilling rig Ocean Vanguard, which will continue to drill a shallow gas pilot hole within PL265.

Johan Sverdrup field is on PL501, PL265 and PL502. Lundin Norway holds 10% interest in PL265 with Statoil Petroleum AS as operator with 40% interest. Other partners are Petoro AS 30% and DNO ASA 20%.

Petrovietnam protests location of CNOOC drilling rig

Petrovietnam said it sent a protest letter on May 4 to the president of China National Offshore Oil Corp. regarding the position of a drilling rig, indicating it violated Vietnam's "sovereign and jurisdiction rights."

Citing the 1982 United Nations Convention on the Law of the Sea, Petrovietnam demanded CNOOC "cease the illegal actions immediately and move the HD-981 drilling rig out of Vietnam's waters."

Petrovietnam said the rig location, 15° 29' N and 111° 12' E, was within the exclusive economic zone and continental shelf of Vietnam. It said CNOOC positioned the rig there on May 2.

CNOOC's action "was against the cooperative spirit" between the two national oil and gas groups, Petrovietnam said.

Drilling & ProductionQuick Takes

States to probe whether wells induce seismic events

State oil and gas regulators and geologic surveys are forming a working group with the Interstate Oil & Gas Conservation Commission and Groundwater Protection Council to examine whether a relationship exists between injection wells and seismic events in several states, IOGCC said on Apr. 29.

It said the US Environmental Protection Agency estimates there are nearly 150,000 Class II Underground Injection Control (UIC) wells across the country the oil and gas industry uses to dispose of produced water or enhance resource recovery.

State agencies participating in the Induced Seismicity by Injection Work Group will collaborate and share science, research, and practical experience to equip the states with the best decision making tools to evaluate the possible connections between seismic events and injection wells, minimize risk, and enhance appropriate readiness when seismic events occur, according to IOGCC.

RWE Dea Egypt ramps up gas production at Disouq

RWE Dea Egypt has ramped up natural gas production through its North West Khilala-1-4 (NWK-1-4) development well, which is part of the Disouq gas project in the Egyptian Nile Delta.

The well, the company's fourth on stream at Disouq, was flowed at a rate of 17 MMcfd during clean-up testing. The well was successfully drilled in March to delimit the northwestern part of the North West Khilala (NWK) field (OGJ Online, Mar. 14, 2014).

The company said output will be boosted by additional wells and the start-up of the central treatment plant later this year.

RWE Dea said NWK field has now reached its production target of 60 MMcfd of gas.

The RWE Dea-operated Disouq project encompasses the development of seven gas fields in the Nile Delta and NWK was the first field brought into production in September 2013 (OGJ Online, Sept. 10, 2013). RWE Dea, along with Egyptian Natural Gas Holding Co. and Suez Oil Co., plans to produce a total of 430 bcf of gas from the seven gas fields in the first phase of the project.

PROCESSINGQuick Takes

More processing, pipelines on tap for US shale plays

Shale development in the US continues to spawn support infrastructure.

MarkWest Energy Partners LP, Denver, will expand Marcellus shale processing at two sites in West Virginia. Regency Energy Partners LP, Dallas, plans a new processing plant and NGL pipeline in North Louisiana.

At its Sherwood complex in Doddridge County, W.Va., MarkWest will build an additional 200-MMcfd processing plant to accommodate production from Antero Resources Corp., based on a long-term, fee-based contract (OGJ Online, Nov. 8, 2013).

The new plant will expand total capacity at Sherwood to 1.2 bcfd by second-quarter 2015. The announcement said Antero continues to develop rich-gas acreage in northern West Virginia and is the anchor producer for Sherwood.

At its Mobley complex in Wetzel County, W.Va., MarkWest will increase total processing capacity to 920 MMcfd with construction of an additional 200-MMcfd plant—Mobley V—to handle production from EQT Corp. Plans target in service by second-quarter 2015.

Mobley currently consists of three plants with total 520 MMcfd of processing capacity. Later this year, MarkWest will start up Mobley IV, increasing capacity to 720 MMcfd (OGJ Online, Aug. 19, 2013). The complex processes production from Marcellus rich-gas production from EQT, Magnum Hunter Resources Corp., Stone Energy Corp., Consol Energy Inc., and Noble Energy Inc.

MarkWest said in 2014, it will complete 11 projects, bringing its total US Northeast processing and fractionation capacity to 4 bcfd and 250,000 b/d, respectively.

In North Louisiana, Regency Energy Partners will build a processing plant and NGL pipeline at its Dubberly site.

The project will include addition of a new 200-MMcfd cryogenic processing plant, filled by gas from Regency's recently completed Dubberly gathering trunkline. Residue gas from this plant will flow into the Regency Intrastate Gas System.

In addition, Regency will build a 160-mile, 8- and 10-in. NGL pipeline from Dubberly for delivery to fractionation. The pipeline will have initial capacity of 25,000 b/d, expandable with additional pump stations.

Combined project costs are to be about $260 million, said the Regency announcement, and both the new plant and the NGL pipeline are to be completed in mid-2015.

LyondellBasell ethylene expansion projects advance

LyondellBasell has secured a key permit required to proceed with its $1.3 billion ethylene expansion program at its plants in Channelview, La Porte, and Corpus Christi, Tex., all of which are benefitting from rising North American shale gas production (OGJ Online, July 1, 2013).

On Apr. 16, the US Environmental Protection Agency issued a final greenhouse gas permit for the company's proposed project to expand its Corpus Christi, Tex., cracker by about 363,000 tonnes/year, LyondellBasell said in a May 2 release.

The permit is the first to be drafted by the Texas Commission on Environmental Quality and issued by EPA under a new program designed to help improve permitting efficiency and productivity for applicants in the state of Texas.

LyondellBasell said it expects construction at the Corpus Christi plant to begin during second-half 2014, with start-up planned for late 2015.

LyondellBasell also said required plant modifications are under way at its La Porte plant and are scheduled to be completed this summer, while start-up at the Channelview plant is planned for early 2015.

When fully operational, LyondellBasell expects the multiplant expansion project to increase North American ethylene capacity by an estimated 1.85 billion lb/year for a total estimated capacity of 11.8 billion lb/year.

"Successfully securing our permit in Corpus Christi means our multiplant ethylene expansion program is on target to be fully operational by the end of 2015," said Jim Gallogly, chief executive officer of LyondellBasell.

"Rather than build a new plant from the ground up, which can take 5 years or more, our approach is to expand our existing facilities and seize the feedstock advantage more swiftly and cost-effectively," Gallogly added.

During the 2013 launch of the expansion projects, the company confirmed the La Porte expansion will add about 363,000 tpy of ethylene capacity at the plant, while the Channelview project will expand that site's capacity by 113,000 tpy (OGJ Online, July 1, 2013).

TRANSPORTATIONQuick Takes

Magnolia LNG files formal FERC application

Magnolia LNG LLC, a wholly owned subsidiary of Liquefied Natural Gas Ltd., Perth, has filed an application with the US Federal Energy Regulatory Commission seeking authorization for the siting, construction, ownership, and operation of the proposed Magnolia LNG project along the Calcasieu River, near Lake Charles, La.

The FERC filing follows extensive work performed by Magnolia LNG since early 2013 on front-end engineering design, pre-filing consultation, and preparation of 13 draft Resource Reports for FERC.

The work also has involved consultation with other federal, state and local agencies, such as the Louisiana Department of Environmental Quality, US Department of Transportation, and the US Coast Guard, Magnolia said.

Magnolia LNG said it anticipates receiving all approvals during 2015, which will be a key requirement for financial close. Construction will start shortly thereafter, with first LNG exports planned for second-half 2018.

LNG Ltd. and Magnolia LNG will now focus on securing an EPC contract and finalizing legally binding liquefaction tolling agreements with counterparties.

LNG Ltd. in January signed a binding pipeline capacity agreement with Kinder Morgan Louisiana Pipeline (KMLP), securing sufficient firm gas transportation for the plant's full 8-million tonne/year (tpy) capacity. Magnolia will use four 2-million tpy trains (OGJ, Apr. 7, 2014, p. 108).

NEB grants export licenses for two LNG projects

Canada's National Energy Board has approved applications for 25-year natural gas export licenses for two proposed LNG export projects.

Aurora Liquefied Natural Gas Ltd. received approval to export a maximum of 24 million tonnes/year of LNG from its proposed site near Prince Rupert, BC. Oregon LNG Marketing Co. LLC received approval to export a maximum of about 10.5 million tpy from its site near Kingsgate and Huntingdon, BC.

Aurora LNG is a joint venture of Nexen (a division of CNOOC), Inpex Corp., and JGC Corp. In November last year, it acquired exclusive rights to almost 1,900 acres of BC government land and deepwater access at Grassy Point, 18 miles north of Prince Rupert, for an LNG export plant (OGJ, Apr. 7, 2014, p. 108). CNOOC acquired Nexen in 2012 to improve its access to Western Canadian shale gas.

Nexen's web site claims that third-party evaluators have estimated that the gas assets Nexen and its joint venture partners share in the Horn River and Cordova basins hold as much as 15 tcf of recoverable resources, while the Liard lands may contain as much as 23 tcf of "prospective resource."