GENERAL INTEREST — Quick Takes
Texas governor signs bill to halt fracturing bans
Texas Gov. Greg Abbott signed a bill to prevent municipalities from banning hydraulic fracturing in a move that was expected after the city of Denton last year approved a referendum to prohibit fracturing in its city limits.
The law does allow cities to regulate above-ground activity, such as drilling setbacks, but it leaves jurisdiction of underground activity up to state regulators.
In 2014, the Texas General Land Office and the Texas Oil & Gas Association sued the city of Denton over its ordinance banning hydraulic fracturing in the city limits. Those lawsuits remain pending.
Denton, which sits atop the Barnett shale, became the first Texas city to ban hydraulic fracturing.
NWT shales survey points to multibillion-barrel OIP
An estimated 145 billion bbl of oil in place are in the Canol shale in Canada's Northwest Territories, while the thinner Bluefish shale could contain 45 billion bbl in place, Canada's National Energy Board and Northwest Territories jointly said on May 22 in the first government assessment of the formations' resource potential.
They emphasized that the amount of recoverable oil was not estimated because well test results are not publicly available yet, and it's still not certain whether the shales are capable of production. However, if only 1% of the Canol shale's in-place resource was recovered, it would represent a 1.45 billion bbl marketable resource, they added.
The shales extend along the McKenzie Plain between the McKenzie and Franklin Mountains. The plain is part of the Mackenzie Arc exploration region, which is within the Northern Canadian Mainland Sedimentary Basin, NEB said.
It said the oil and gas industry has recently been targeting the Canol shale: 14 exploration licenses have been granted there since 2010-11 for a total of $627.5 million (Can.) in work-bid commitments. Seven exploration wells have been drilled since 2012, it added.
Oil in place volumes were calculated using a probability model that recently was used to assess volumes in British Columbia's Montney formation and Saskatchewan's Bakken formation, NEB said.
The closest available comparison in the Canol shale's recoverability is the Permian basin of Texas, where operators report expected recovery factors around 3%, it indicated.
Large areas of the Canol shale are at much shallower depths than these other shale oil prospects, and the lower pressures might make oil recovery more difficult, it cautioned. If it is possible to recover 3% of what's believed to be there, however, the Canol could produce 4.35 billion bbl, NEB said.
Alfa, Harbour to acquire Pacific Rubiales for $1.7 billion
Mexican multinational conglomerate Alfa SAB de CV and British energy firm Harbour Energy Ltd. have collaborated to acquire the stock of Pacific Rubiales Energy Corp., Toronto, not already owned by Alfa in a deal valued at about $1.7 billion, excluding debt. Pacific Rubiales is the largest independent oil and gas producer in Latin America; its shares are also listed in Colombia.
The deal, which is expected to close in this year's third quarter, has been approved by Pacific Rubiales' board.
Alfa, which already holds 18.95% stake in Pacific Rubiales, has businesses in oil and gas, branded foods, aluminum auto components, petrochemicals, information technology, and telecommunications services.
Harbour Energy is an energy investment company held jointly by US private equity firm EIG Global Energy Partners and Asian commodity trader Noble Group Ltd.
Magnum Hunter selling noncore Utica acreage
Magnum Hunter Resources Corp., Dallas said its wholly owned subsidiary Triad Hunter LLC has signed a definitive agreement to sell certain noncore undeveloped Utica leasehold acreage in West Virginia for $40.8 million to an undisclosed independent producer.
The assets involve 5,210 net acres in Tyler County, W.Va. The transaction was scheduled to close May 28, subject to customary closing conditions.
Gary C. Evans, Magnum Hunter chairman and chief executive officer, said May 26 that the properties were not in Magnum Hunter's long-term drilling plan. The sale represented less than 3% of Magnum Hunter's total 210,000 net acres in leases in the Marcellus and Utica.
"Additionally, with lease expirations on the horizon on a large portion of this acreage position, it made sense to sell these properties now to an industry competitor that already owns adjacent leases," Evans said.
API-Ohio runs ads against proposed state severance tax
The American Petroleum Institute launched a series of radio ads in Ohio urging people to call their state senators in opposition of any additional taxes on the oil and gas industry, said Chris Zeigler, API-Ohio executive director.
An increased severance tax on horizontal drilling and hydraulic fracturing was expected to be included in a Senate version of a budget bill for Ohio.
Ohio Gov. John Kasich proposed a 6.5% tax on oil and gas sold at the wellhead and a 4.5% rate on natural gas liquids. The Ohio House of Representatives pulled the severance tax proposal out of the budget.
A budget measure is in a Senate committee now, and if authorized, could progress to a conference committee around June 15, Zeigler said.
"Right now, the industry is going through a downturn," Zeigler said. "Why would we want to add costs through more taxation on an industry that is just trying to weather the storm at this point?"
Exploration & Development — Quick Takes
BLM seeks comments on Atchee area project
The US Bureau of Land Management is seeking public comments on Rosewood Resources Inc.'s proposal to develop an oil and natural gas field in the Atchee area 40 miles south of Vernal, Utah.
The privately held Dallas independent plans to develop gas on 11,109 acres, 10,240 of which are BLM-administered, 640 of which are state-managed, and 49 of which are privately owned, BLM's Vernal field office said in a May 11 notice. Written comments will be accepted until June 10.
BLM said Rosewood plans to directionally drill 151 wells from 38 existing and 30 new well pads. Proposed activity also includes 7.5 miles of new road, up to 15 miles of new or replacement surface gas and water lines, and construction of three to nine new compressor stations and expansion of three existing compressor stations.
Rosewood proposes to drill 8-20 wells/year over the next 8-20 years until the resource base is fully developed, BLM said.
Australia releases 29 areas for offshore exploration
The Australian government has released a total of 29 areas for bidding in the 2015 offshore acreage release across eight basins in the Northern Territory, Ashmore Cartier Islands region, Western Australia, South Australia, Victoria, and Tasmania.
Twenty-three areas are available for work program bidding and six are available for cash bidding. Another three areas in the offshore Western Australia and Ashmore Cartier areas are re-released from the 2014 program as they garnered no bids last year.
Bidding will close for the first 12 blocks by Oct. 29. The cash bid blocks will close on Feb. 4, 2016. The second round of 10 blocks will close in April 2016.
Most notable of the cash bid areas are W15-1 and NT15-2 in the Bonaparte basin that contain the small Turtle oil and gas field and the small Barnett oil field. These were previously held by Tangier Petroleum, which defined a number of large targets, but was unable to meet work commitments. Tangiers was stripped of these areas in 2013.
First round work program areas include an area also in the Bonaparte basin in the vicinity of the Petrel, Tern, Frigate, Penguin, and Blacktip gas fields.
Other areas are near the Bayu-Undan gas field and the Cash-Maple gas fields in the Timor Sea.
Of equal interest is a block in the frontier Rowley Sub-basin of the Roebuck basin northwest of the recent Phoenix South-1 oil find.
Other frontier blocks are in the Ceduna sub-basin of the Bight basin in South Australia, the Nelson Sub-basin of the Otway basin of Victoria and Tasmania, and the Sorrel basin off western Tasmania.
CNOOC makes oil find in eastern South China Sea
CNOOC Ltd. has made a midsized oil discovery in the Liuhua 20-2 structure in the Northern Slope Belt of the Baiyun Sag, which lies in the Pearl River Mouth basin of the South China Sea.
Discovery well LH20-2-1 was drilled and completed at a depth of 2,970 m in 390 m of water, encountering oil pay zones with a total thickness of 35.2 m. The well tested at 8,000 b/d with a crude density of 0.75.
CNOOC says exploration of Liuhua 20-2 has further proved the "huge exploration potential" of Baiyun Sag, which is expected to become the new reserves growth area for deepwater crude exploration in the South China Sea.
Eni makes another Area D strike offshore Libya
Eni SPA estimates a natural gas and condensate discovery well in the Bouri North prospect offshore Libya can flow more than 3,000 boe/d when configured for production.
The well, A1-1/1, flowed during a production test at an equipment-constrained rate of 1,340 boe/d through a 64/64-in. choke from the Eocene Metlaoui Group.
The well is in 125 m of water in Area D, 140 km from the coast and 20 km north of giant Bouri oil field.
Earlier this year, Eni tested gas and condensate in another Area D exploratory well, B1-16/4 (OGJ Online, Mar. 16, 2015).
Eni North Africa BV operates Area D with 100% working interest through the exploration phase.
Drilling & Production — Quick Takes
Total reports 2 billion bbl output from Block 17
Total SA has reached cumulative production of 2 billion bbl from its deepwater Block 17, 150 km offshore Angola.
The recent startup of the CLOV fields-Cravo, Lirio, Orquidea, and Violeta-makes Block 17 the company's most prolific site, with production of more than 700,000 b/d (OGJ Online, June 12, 2014). Total operates four floating production, storage, and offloading units on major production zones Girassol, Dalia, Pazflor, and CLOV.
"Block 17 is a global benchmark in the deep offshore and represents a unique industrial adventure, with 15 discoveries and a very high level of production," commented Arnaud Breuillac, Total exploration and production president. He added that the company is transferring its expertise to areas such as Libra field offshore Brazil and the Laggan-Tormore project offshore the UK.
Total operates Block 17 with 40% interest alongside Statoil ASA 23.33%, Esso Exploration Angola Block 17 Ltd. 20%, and BP Exploration Angola Ltd. 16.67%. Angola's state-owned Sonangol is the concessionaire of the license.
Total, whose presence in Angola dates back more than 60 years, reported equity production of 200,000 boe/d in 2014, essentially from Blocks 17, 0, and 14.
The company also operates with 30% interest the ultradeepwater offshore Kaombo development on Block 32. A final investment decision was made in 2014 to develop Kaombo's estimated reserves of 650 million bbl via two converted FPSOs with a total production capacity of 230,000 b/d (OGJ Online, Apr. 14, 2014).
Moody's Investors Service last year predicted that Angola will produce 2.1-2.2 million b/d of crude oil by 2016 (OGJ Online, Aug. 20, 2014).
Husky begins steam operations at Rush Lake
Husky Energy Inc. has started commercial steam operations at the 10,000-b/d Rush Lake heavy oil thermal project in Saskatchewan (OGJ Online, Dec. 12, 2014).
"Rush Lake is the latest in a series of long-life, low-sustaining capital thermal projects we are advancing in our heavy oil business," said Asim Ghosh, chief executive officer. "Five years ago, we had two heavy oil thermal projects in production and by the end of 2016, we will have 10 projects onstream."
Current production from Husky's thermal projects is about 44,000 b/d. Husky expects to add another 34,500 b/d over the next 18 months.
Rush Lake, which began steam operations about 8 weeks ahead of schedule, is expected to ramp up to full production "in a short time period," the company said. The 10,000-b/d Edam East project is scheduled to come on stream in third-quarter 2016, followed by the 4,500-b/d Edam West and the 10,000-b/d Vawn projects, both in the fourth quarter.
Husky said the projects use proven thermal technologies and modular, repeatable construction templates to access heavy oil deposits in the Lloydminster region, offering good returns even in a low-price environment (OGJ Online, May 6, 2015).
Petronas starts production from Bukit Tua field
Petronas reported startup of production from Bukit Tua field, and expects peak production to reach 20,000 b/d and 50 MMscfd (OGJ Online, Dec. 17, 2013).
In its initial production phase, rates are expected to be 3,700 b/d and 2 MMscfd.
The field lies on Ketapang block about 110 km offshore East Java. Petronas said gas will be transported through a subsea pipeline to an onshore receiving facility in Gresik, East Java, while oil will be offloaded to carriers for export from the Ratu Nusantara floating production, storage, and offloading facility.
Ketapang block is operated and 80% owned by PC Ketapang II Ltd., the Indonesian subsidiary of Malaysia's Petronas. The remaining 20% is held by state-owned Perusahaan Gas Negara through subsidiary PT Saka Ketapang Perdana.
Fire causes Cenovus to shutter Foster Creek facilities
Cenovus Energy Inc. halted production on May 23 from its Foster Creek oil sands and Athabasca natural gas operations as a precaution due to a forest fire about 25 km south on the Cold Lake Air Weapons Range (CLAWR) in northeastern Alberta.
The company says its decision to evacuate 1,800 people off the site and shutter production was primarily made because of the fire's proximity to the only access road to the facilities. No damage to Foster Creek system has been reported.
The restart of the facility will entirely depend on the status of the forest fire, Cenovus says. Once the fire is under control and it is deemed safe to return to the site, operations will resume as soon as possible.
Foster Creek, which is jointly owned with ConocoPhillips, has gross production of 135,000 b/d, of which 67,500 b/d is net to Cenovus. Total net oil production across all of Cenovus' assets averaged about 218,000 b/d in the first quarter. The Athabasca natural gas operation currently produces about 20 MMcfd of gas, most of which is used as fuel for Foster Creek.
The company previously reported plans to invest $700-750 million for expansions at Foster Creek (OGJ Online, Dec. 18, 2014). Phase G expansion as of January was about two-thirds complete (OGJ Online, Sept. 19, 2014).
PROCESSING — Quick Takes
Victoria unit buys gas plant in Cameroon
Victoria Oil & Gas PLC, London, said a wholly owned subsidiary has completed the $2.578-million purchase of a natural gas processing plant at Logbaba gas field in Douala, Cameroon, from Expro Worldwide BV (OGJ Online, Oct. 30, 2013).
The plant handles production by the subsidiary, Gaz du Cameroun SA (GDC), which owns 60% of the Logbaba Project. RSM Production Corp., an affiliate of Grynberg Petroleum Co., Denver, holds a 40% participating interest.
The project supplies condensate to a refinery and dry natural gas through a 33-km pipeline network to an electric utility and industrial customers in Douala.
In a financial report last November, Victoria said it expected Logbaba production to average about 10.4 MMscfd in 2015. According to the company, Logbaba field, which has two wells, can produce 20 MMscfd.
Lukoil commissions new plant at Bulgarian refinery
Lukoil Neftochim Burgas AD, a subsidiary of Russia's OAO Lukoil, has commissioned a heavy-residue hydrocracking complex at its 9.8 million-tonne/year refinery in Burgas, Bulgaria, along the Black Sea.
The new complex, which consists of a 2.5 million-tpy residual asphalt hydrocracking unit and a number of auxiliary units, began operations on May 20, Lukoil said.
In addition to reducing emissions of greenhouse gases, the new processing complex will contribute to an increase in the refinery's production of light fuels as well as an improvement in overall energy efficiency at the site, the company said.
With start-up of the new complex, which will produce Euro 5-compliant fuel gas, gasoline, diesel, and vacuum gas oil, the Burgas refinery is anticipated to reach a refining depth of 90%, Lukoil said.
The $1.5 billion complex includes a sulfur recovery unit that was completed during 2014, according to a March report to investors.
Lukoil, which in 2012 let a turkey project-implementation contract for the hydrocracking plant to Technip, initially planned to commission the complex in January 2015, the company said in a release on Jan. 25, 2012.
TRANSPORTATION — Quick Takes
QCLNG begins commercial operations
BG Group subsidiary QGC has taken operational control of Train 1 at its Queensland Curtis LNG (QCLNG) plant from Bechtel Australia, which built it. BG Group's Train 1 equity partner, China National Offshore Oil Co. (CNOOC), also approved sale of the QCLNG natural gas pipeline to APA Group, satisfying the last of the transaction's preconditions. The sale should be finalized this quarter.
The transfer of operational control of Train 1 marks the start of commercial operations at QCLNG. First production from Train 1 occurred in December, with 16 cargoes shipped to date. QCLNG's Train 2 is under construction and is expected to start operations next quarter (OGJ Online, Dec. 31, 2014).
BG holds roughly 74% equity interest in the upstream resource and related infrastructure supplying QCLNG and 100% of the project's Curtis Island plant (including LNG storage tanks and jetty).
BG agreed last year to sell its 100% equity interest in the 540-km pipeline to APA for $4.5-5 billion (OGJ Online, Dec. 10, 2014).
Cheniere reaches FID for Corpus Christi project
Cheniere Energy Inc. has made a final investment decision (FID) for its liquefaction project near Corpus Christi, Tex., and has issued a notice to proceed to Bechtel Oil, Gas & Chemicals Inc. for construction of the first two liquefaction trains (OGJ Online, Jan. 2, 2015).
The news comes on the heels of the US Department of Energy issuing final authorization for the project to export domestically produced LNG to countries without a Free Trade Agreement with the US. The project is authorized to export LNG up to the equivalent of 2.1 bcfd of natural gas for a period of 20 years.
The liquefaction project is designed for as many as three trains with expected aggregate nominal production capacity of 13.5 million tonnes/year, three LNG storage tanks with capacity of 10.1 bcf of gas equivalent, two LNG carrier docks, and a 22-mile, 48-in. gas supply pipeline. The first train is expected to start operations as early as 2018, with the second train expected to start up 6-9 months later.
Total project costs of $11.5 billion for the first two trains, two LNG storage tanks, one dock, and the gas supply pipeline will be funded with $3.1 billion of project equity and $8.4 billion of debt. Corpus Christi Holdings LLC, a wholly owned subsidiary of Cheniere, has closed on its previously reported credit facility for the first two trains totaling $8.4 billion.
"Including our LNG export facility at Sabine Pass, we now have six trains under construction, with first LNG expected at Sabine Pass from Train 1 by yearend," said Charif Souki, Cheniere chairman and chief executive officer.
Rio Grande LNG project advances with FEED agreement
NextDecade LLC, The Woodlands, Tex., has signed an agreement with CB&I for the front-end engineering design (FEED) and engineering, procurement, and construction (EPC) terms related to the Rio Grande LNG export project in Brownsville, Tex. This agreement follows NextDecade's applying for and acceptance into the FERC pre-filing process in late March (OGJ Online, Mar. 25, 2015).
The scope of the FEED-EPC agreement covers all design and engineering activities required for the full FERC permitting process, as well as for the parties to prepare the procurement of equipment until the point of the final investment decision (FID). This will be possible once the FERC and related permitting agencies have given full authorization to construct, expected in 2017, NextDecade said.
Rio Grande LNG, a wholly owned subsidiary of NextDecade, is a land-based LNG export project on a 1,000-acre site along the Brownsville Shipping Channel in Brownsville, Tex. The project includes plans for as many as 6 liquefaction trains, each with a 4.5 million tonne/year nominal output capacity.
The 140-mile proposed Rio Bravo Pipeline will supply the plant connecting it to the Agua Dulce natural gas market hub.
The company expects to make an FID on the Rio Grande's $8-billion Phase 1 in 2017, pending regulatory approvals.
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