GENERAL INTEREST — Quick Takes
EIA: China to become world's largest net oil importer
China will become the world's largest net oil importer by October on a monthly basis and by 2014 on an annual basis, the US Energy Information Administration forecast in its August Short-Term Energy Outlook (STEO).
"The imminent emergence of China as the world's largest net oil importer has been driven by steady growth in Chinese demand, increased oil production in the United States, and a flat level of demand for oil in the US market," EIA said.
China's liquid fuels demand is forecast to be more than 11 million b/d in 2014, up 13% from 2011. In the meantime, US demand wavers around 18.7 million b/d, falling well off the peak consumption level of 20.8 million b/d in 2005.
On the supply side, Chinese oil production is expected to rise at 6% from 2011 to 2014, well below the US production growth rate of 28% over this period. In 2014, Chinese production is forecast to be only a third of US production.
EIA expected that the gap between net oil imports in China and the US beyond 2014 will continue to widen, given the sustaining effects of higher US oil production and stagnant or declining US oil consumption, coupled with China's projected strong oil demand growth and slow oil production growth.
GSCI energy, non-energy components diverge in returns
According to the US Energy Information Administration's Market Price Uncertainty Report, the energy component of the Goldman Sachs Commodity Index (GSCI)—a benchmark for changes in commodity markets over time—rose 8.1% since July 1. In contrast, the non-energy component of the index declined by 1.5%, suggesting that the recent increase in energy commodity returns are not likely because of improved global economic growth expectations but energy market-specific factors such as a drop in oil production from Libya due to ongoing protests.
The upward movement in the energy index also has been attributed substantially to the rise of the West Texas Intermediate over the last month, accompanied by higher trading volumes for WTI futures contracts on the New York Mercantile Exchange.
The NYMEX futures price for WTI crude accounts for more than one third of the weighting in the energy component of the GSCI and about 25% of the entire GSCI. The total monthly trading volume for WTI has outpaced Brent trading volumes over the past 3 months, averaging 1.5 million more total contracts traded.
Non-energy commodity prices have declined this year. Copper, gold, and corn, with a combined share of 11% of the S&P GSCI, are down 11%, 22%, and 33%, respectively, since the start of 2013. "The declines can be attributed to factors such as slower-than-expected growth in emerging market countries as well as market-specific explanations such as improved weather that led to higher corn crop yields," EIA said.
The GSCI represents the price of a broad spectrum of commodities and is used as a benchmark for changes in commodity markets over time. Commodity product classes represented within the index include energy, industrial metals, precious metals, agriculture, and livestock. Energy accounts for nearly 70% of the index, with oil alone comprising 47%. GSCI price levels were first published in 1991, and a related futures contract is currently traded on the Chicago Mercantile Exchange.
Jewell appoints Salerno as BSEE's third director
US Sec. of the Interior Sally Jewell has named Brian Salerno, a former US Coast Guard vice-admiral who retired last year as its deputy commandant for operations, as the US Bureau of Safety and Environmental Enforcement's third director.
He will assume his position at BSEE's helm on Aug. 26. BSEE's current director, James A. Watson, agreed to stay through the end of August when he announced his resignation to become president of Houston-based ABS Inc. in early September (OGJ Online, July 10, 2013).
While at USCG, Salerno worked primarily in maritime safety, security, environmental protection, and emergency response. Like Watson, he played a vital role in the agency's response to the 2010 Macondo deepwater well blowout, rig explosion, and subsequent oil spill in the Gulf of Mexico.
He also was a member of the National Academy of Sciences' Ocean Studies Board, which explored industry and government readiness to respond to oil spills in the Arctic Ocean. Salerno also was on a team that examined interagency relationships among BSEE, USCG, other government agencies, and federally regulated offshore industries.
He also is a board member of the North American Marine Environmental Protection Association, a group of maritime companies and organizations committed to environmentally sound practices, DOI said. Salerno's appointment does not require US Senate confirmation, it noted.
EV Energy Partners selling assets in Ohio
EV Energy Partners LP, along with certain institutional partnerships managed by EnerVest Ltd., agreed to divest acreage in the Utica shale in Ohio for $284 million to an undisclosed buyer.
The sale includes 22,535 acres in Guernsey, Harrison, and Noble counties, said Houston-based EVEP. A map showing the acreage is available on EVEP's web site.
Of the total acreage, EVEP is selling 4,345 acres for $56 million, net to its ownership interest. EVEP will retain royalty interests in these acres. The transaction is expected to close by the end of the third quarter.
"This is a good first step in our revised Utica acreage sale process," said John B. Walker, EVEP chairman. "The value of this sale averages $12,900/acre. We look forward to announcing additional deals" as EVEP continues to market its Utica acreage.
In addition to the acreage sale, EVEP announced the Utica East Ohio midstream facilities had started processing gas in July. The plant processes more than 85 MMcfd of wet gas, has a capacity of 200 MMcfd, and throughput is expected to increase steadily over the next few weeks.
Exploration & Development — Quick Takes
URTeC: Wolfcamp play dwarfs Bakken, Eagle Ford
"The Spraberry Wolfcamp could possibly become the largest oil and gas discovery in the world," said Pioneer Natural Resources Co. Chief Executive Officer Scott Sheffield while speaking Aug. 12 at the Unconventional Resources Technology Conference (URTeC) in Denver.
PNR is the largest acreage holder in the Spraberry field with 900,000 gross acres (730,000 net acres), the majority of which could be prospective for the horizontal Wolfcamp shale. Based on Pioneer's extensive geologic database, petrophysical analysis, and successful drilling results to date, there is significant horizontal Wolfcamp shale resource potential in this acreage.
According to Sheffield, the company will test 13 zones over the next 3 years. With 50 billion boe in recoverable reserves to date, Wolfcamp is bigger than the Bakken in North Dakota and South Texas's Eagle Ford shale. Sheffield noted that recoverable reserves are based solely on the Wolfcamp A, B, D, and the Jo Mill. "More reserves are yet to be discovered," he said.
Geographically, Wolfcamp is comparable to other plays. A unique feature that puts it ahead of other plays is its variety of geological zones. The play contains 3,500-4,000 ft of shales, which is more like 3-4 million acres when considered in 3D space as opposed to 2D space.
"Compare that to the Eagle Ford shale formation, which is about 300 ft deep and the Spraberry Wolfcamp shale, with its 50 billion boe, begins to dwarf the Eagle Ford and the Bakken with 27 billion boe and 13 billion boe, respectively," he said.
According to Sheffield, PNR's success in Eagle Ford has provided a smooth transfer into Wolfcamp. "When compared by phases of development, we see the Wolfcamp trending higher than the Eagle Ford based on activity and production," he said.
Based on recoverable reserves, the Wolfcamp is second only the Ghawar field in Saudi Arabia. "We believe this field will reach 100 billion boe recoverable reserves at some point in time," Sheffield said.
Llanos foothills Mirador well tests at 5,218 b/d rate
Petrominerales Corp., Calgary, said its Taya-1 well on Corcel Block 31 in the Llanos foothills of Colombia production-tested at the rate of 5,218 b/d of 23.2° gravity oil upon recompletion in the Mirador formation.
The majority of the production test was conducted using an electric submersible pump and an open choke with 14% drawdown. The well also produced a 30% water cut. For the last 6.5 hr that the well was producing on ESP, the rate stabilized at 5,169 b/d with a 37% water cut.
The average oil rate through a 192/64-in. choke over the entire production test period was 5,218 b/d with 23 psi wellhead pressure. Total recovery was 11,741 bbl of oil and 5,054 bbl of water, confirming the excellent quality of the Mirador reservoir.
As previously reported, well logs indicated 42 ft of potential net oil pay in Mirador and 31 ft in the Guadalupe formation. Prior to recompletion, the well was producing 315 b/d of oil from Guadalupe.
After producing the reserves in the Mirador, the company can isolate the Mirador and produce the remaining reserves in the Guadalupe.
For the rest of 2013, Petrominerales plans to drill at least two more wells in the area. They are Canaguay-2, an appraisal well on the recently acquired Canaguaro block, subject to the ANH approval, and one more exploratory well, Ceibo-1 on the Guatiquia block on trend with Candelilla and Yatay oil pools.
Brion wins Dover SAGD project approval
Brion Energy Corp., Calgary, has received Alberta Energy Regulator approval of the 50,000-b/d first phase of its large Dover oil sands project about 95 km northwest of Fort McMurray, Alta.
Brion, formerly called Dover Operating Corp., will use steam-assisted gravity drainage to develop bitumen in the Lower Cretaceous McMurray formation.
The company plans five phases of development and two SAGD plants, with production capacity reaching 250,000 b/d.
AER approved the first Dover phase with 10 conditions, most having to do with control of air emissions, subject to approval of the Lieutenant Governor Council.
Brion expects ultimate recovery of 4.1 billion bbl of bitumen over the 50-year life of the project.
Drilling & Production — Quick Takes
Chad group preparing to start oil production
Caracal Energy Inc., Calgary, said it will initially ship 468,000 bbl of line fill from its wells in southern Chad as it continues to make progress toward producing into the Chad-Cameroon oil pipeline.
Caracal will carry out the shipment on behalf of itself and its partners Glencore and the state company SHT. Initial production to come from the Badila-1 and 2 wells is expected to total as much as 14,000 b/d.
PetroChad Transportation Inc. is the company authorized to ship oil within Chad as defined under Caracal's production sharing contract.
An inland transportation authorization has been granted, and PCT will ship and measure oil shipments into the export transportation system through custody transfer metering. PCT is constructing blending and shipping facilities required to bring Mangara field onstream. The facilities are to be completed and commissioned in the fourth quarter.
Meanwhile, Caracal spudded the Krim exploratory well on Aug. 4 just southwest of Mangara field and spudded the Badila-4 well on Aug. 8 to appraise the southeast extension of the primary Badila field. A rig will then move to spud the Bitanda exploratory prospect.
The Krim well targets the Cretaceous C and D sands now under development in Mangara field and the Cretaceous E sands that in Mangara-5 have a potential range of 150-230 m of net pay based on petrophysical analysis. The Krim drillsite is less than 10 km from Mangara field facilities.
Badila-4 is on a new structural high mapped on 3D seismic shot over Badila field in the quarter ended June 30. Badila field has possible reserves of 40 million bbl over and above the proved plus probable reserves of 45 million bbl. Much of the possible reserves are associated with the area in and around the Badila-4 well location.
Mya North gas flowing offshore Myanmar
Daewoo International Corp. reported the start of production at Mya North natural gas field, part of the Shwe gas project offshore Myanmar (OGJ Online, Jan. 22, 2007).
The company said Mya North, where four production were drilled a year ago, is producing 120 MMscfd.
By yearend 2014, drilling of production wells will be complete in the Shwe complex, Daewoo said. Production then will be an estimated 500 MMscfd.
China National Petroleum Corp. buys the gas for use in Myanmar and carries it through subsea and onshore pipelines.
The company estimates reserves in Shwe, Shwe Phyu, and Mya fields at 4.3 tcf of gas.
Daewoo holds a 51% interest in the project. Other interests are India's Oil & Natural Gas Corp., 17%; Myanmar Oil & Gas Enterprise, 15%; and GAIL (India) Ltd. and Korea Gas Corp., 8.5% each.
Woodside lets contract for outer Canning basin
Woodside Petroleum Ltd. let a 2-year, $442 million contract to Transocean Inc. to lock in a rig for a drilling campaign in the outer Canning basin offshore Western Australia.
Transocean will supply the drillship Deepwater Millennium for an eight-well program in 1,500-1,000 m of water beginning in February 2014.
The program will fulfil exploration commitments in permits WA-462-P, WA-464-P and WA-466-P in what geologists call the Rowley sub-basin. Woodside has already farmed out 45% in each to Shell. Even so the program expenditure represents about a quarter of Woodside's annual exploration budget.
The two companies have committed to an 11,000 sq km 3D seismic program across all three permits plus drilling. There will be four wells in 464-P, three in 466-P, and one in 462-P.
It will be a huge program over an area that has just three previous wildcats—East Mermaid-1 (Shell 1973), Whitetail-1 (Woodside 2003), and Huntsman-1 (Woodside 2006)—none of which found hydrocarbons.
Nevertheless both Woodside and Shell remain bullish about the gas potential of the region which lies about 300 km northwest of Broome.
Targets are believed to be both Triassic-age and deeper Paleozoic-age reservoirs.
The first three wells will be Anhalt in 462-P, Detmold in 464-P, and Hannover in 466-P—all named after historic German towns or cities. Other locations will be defined when data from the 2012 3D seismic survey have been interpreted.
PROCESSING — Quick Takes
Pembina Pipeline to build gas plant in Alberta
Pembina Pipeline Corp., Calgary, will build and operate a 100-MMcfd shallow-cut gas plant called the Musreau II and associated NGL and gas gathering pipelines near its current Musreau plant in its western central Alberta Cutbank complex.
The $110 million (Can.) Musreau II is backstopped by long-term contracts with area producers for 100% of its capacity, Pembina reported. Subject to regulatory and environmental approval, Pembina expects Musreau II to be in service in first-quarter 2015.
It will extract C3+ and yield about 4,200 b/d of NGL that will move in Pembina's "conventional" pipelines, which the company identifies as 7,850 km of pipelines that transport about half of Alberta's conventional crude oil production, about 30% of the NGL produced in Western Canada, and "virtually all of the conventional oil and condensate produced in British Columbia."
Pembina said its gas services business has 368 MMcfd net shallow-cut processing capacity, as well as 205 MMcfd of deep-cut capacity in operation. Additional capacities will be available from the following projects:
• 200 MMcfd to come on stream in this year's third quarter at its Saturn I plant in the Berland area of west-central Alberta.
• 200 MMcfd to come on stream in third-quarter 2014 at the Resthaven plant, also in west-central Alberta. The $230 million Resthaven, including plant, pipelines, and storage, in addition to gas processing, will have 13,000 b/d of liquids extraction capability and ultimately be able to process 300 MMcfd.
• 200 MMcfd on stream in late 2015 as part of the Saturn II project.
With the addition of Musreau II, Pembina's gas processing capacity will reach about 1.2 bcfd by yearend 2015, the company said.
Chennai Petroleum adding coker at Manali
Chennai Petroleum Corp. Ltd. has let a turnkey contract to Engineers India Ltd. covering the addition of a delayed coker at its 10.5 million tonne/year Manali refinery in Tamil Nadu, India.
According to press reports, the coker will have capacity of 2.2 million tpy.
It's part of a project enabling the refinery to upgrade resid and increase distillate yield by about 7%. The project includes revamp of an existing hydrocracker.
Chennai Petroleum is a partly owned subsidiary of Indian Oil Corp. Ltd.
Chevron Phillips Chemical gets air permits
Chevron Phillips Chemical Co. LP has received air permits from the Texas Commission on Environmental Quality for the ethylene and polyethylene projects it plans in Texas (OGJ Online, May 2, 2012).
Subject to board approval to be sought later this year, the company plans a 1.5 million tonne/year ethane cracker at its Cedar Bayou complex in Baytown and two polyethylene plants, each with 500,000 tpy of capacity, near its Sweeny complex in Old Ocean.
TRANSPORTATION — Quick Takes
TransCanada approves Energy East crude pipeline
TransCanada Corp is moving forward with its 1.1 million b/d Energy East Pipeline project based on binding, long-term contracts received from producers and refiners. A recent open season on the pipeline concluded with the company having signed 900,000 b/d of firm, long-term contracts to transport oil from Western Canada to Eastern Canadian refineries and export terminals (OGJ Online, Apr. 2, 2013). Eastern Canada currently imports 700,000 b/d of crude oil, according to TransCanada.
TransCanada expects the Energy East Pipeline to enter service by late-2017 for deliveries in Quebec and 2018 for deliveries to New Brunswick. The project involves converting about 3,000 km of gas pipeline on TransCanada's existing Canadian Mainline to crude service and building 1,400 km of new pipeline. Energy East will transport oil from receipt points in Alberta and Saskatchewan to delivery points in Montreal, the Quebec City region and Saint John, NB, enhancing Western Canadian producer access to Eastern Canadian and international markets.
The pipeline will terminate at Canaport in Saint John, where TransCanada and Irving Oil have formed a joint venture to build, own, and operate a new deep water marine terminal.
TransCanada intends early next year to proceed with the necessary regulatory applications for the pipeline project and terminal. The company expects Energy East to cost about $12 billion, excluding the transfer value of Canadian Mainline natural gas assets.
The decision to move forward on Energy East has not diminished the need for Keystone XL, according to TransCanada Pres. and CEO Russ Girling. "Energy East is one solution for transporting crude oil but the industry also requires additional pipelines such as Keystone XL to transport growing supplies of Canadian and US crude oil to existing North American markets," he said, adding, "Both pipelines are required to meet the need for safe and reliable pipeline infrastructure and are underpinned with binding, long-term agreements."
France's first Q-Max arrives at Fos Cavaou
France's Fos Cavaou LNG terminal, at the entrance of the port of Fos-sur-Mer on the Mediterranean, received the Al Mafyar Q-Max tanker, the first of the massive 266,000-cu m vessels to arrive in France. The report neither specified if the vessel was fully loaded nor where its cargo had been lifted.
Access to the Fos Cavaou terminal to receive Q-Max ships involved, the report said, "close cooperation between the company Fosmax LNG, the services of the port of Marseille Fos,…and the port services." The pilots had conducted simulations for vessel approach and berthing in order to be able to receive the Al Mafyar.
Since it began operating in 2010, Fos Cavaou has received more than 180 vessels, one fourth of which consisted of the 210,000-cu m Q-Flex vessels. It has regasification capacity of 8.25 billion cu m/year and LNG storage capacity of 330,000 cu m.
Fosmax LNG, which owns the terminal, is a subsidiary of Elengy, 72.5%, and Total SA, 27.5%. Elengy, a GDF Suez company, operates three French LNG terminals: Montoir-de-Bretagne on the Atlantic coast and Fos Tonkin and Fos Cavaou on the Mediterranean.
China's first FRSU receives approval
China National Offshore Oil Corp. (CNOOC) last month received approval from the National Development and Reform Commission for the country's first LNG floating regasification and storage unit (FRSU), CNOOC reported on its web site.
The vessel will be moored in the Nanjiang area of the Tianjiin port on Bohai Bay. The 2.2-million tonne/year Phase 1 will cost nearly $5.9 billion and, besides the FRSU, include storage and pipelines. An 11-mile, 40-in. gas pipeline will extend between Tianjin Nanjiang port and Lingang Economic Zone.
Phase 2 will consist of a 6-million tpy land terminal (OGJ, Apr. 1, 2013, p. 90).