General Interest— Quick Takes
CERI updates oil sands production, cost outlook
The realistic scenario in the latest Canadian Energy Research Institute outlook expects Alberta oil sand production to increase to 1.7 million b/d by 2015, 2.5 million b/d by 2020, 4.5 million b/d by 2030 before reaching a peak of 5.3 million b/d in 2041. Oil sand production was 1.3 million b/d in 2008.
The scenario assumes crude oil demand starting to increase in 2010 as the world recession ends and crude prices reaching $200/bbl for West Texas Intermediate in 2043.
CERI's outlook notes that during the past year oil sands projects have seen construction costs decline by 15% and operating costs decline by 13%.
It estimates that oil sands projects will have a rate of return of 23% for steam-assisted gravity drainage, 11% for mining and upgrading, and 18% for mining without upgrading. Total capital required during its 35-year realistic scenario period is $309 billion.
CERI points out, assuming no technology changes, that by 2043 oil sands natural gas requirements will be three to four times more than current levels, leading to US gas exports into Canada.
In addition, greenhouse gas compliance may cost the industry $130 billion during the next 35 years, CERI says.
API issues new hydraulic fracturing guidelines
The American Petroleum Institute published a new guidance document outlining industry best-practices for properly drilling and cementing wells that are being hydraulically fractured.
The well construction and integrity guideline is designed to ensure that shallow groundwater aquifers and the environment are protected through a well's drilling, completion, and production phases, API said on Nov. 2. It was the second of four documents that API's standards and practices department has been developing to address hydraulic fracing's increasing role in US energy options.
API published a guidance document on hydraulic fracing environmental and reclamation practices in August, it noted. The final two documents that are being developed will address cradle-to-grave water-handling practices and surface environmental considerations.
The newest guidance document is intended to provide producers and state regulators a framework for well construction that will supplement state regulations already in place or being developed, API said. The trade association has published industry standards since the 1920s and continually updates them to provide guidance and highlight industry-recommended best practices on a number of topics, it pointed out.
More than 1 million wells have been drilled in the US using hydraulic fracing over the past 60 years, according to API. As geographical formations being drilled become more complicated, hydraulic fracing will be used even more, especially for natural gas, it said, citing a 2006 government-industry report that found 60-80% of gas wells drilled in the next decade will require the technology.
"Natural gas has the potential to serve as an important bridge to our nation's energy future, but we need hydraulic fracturing to develop this gas," said Doug Morris, API upstream director. "Hydraulic fracturing is a safe and proven technology that is critical to developing the natural gas needed to heat homes, generate electricity, and create basic materials for fertilizers and plastics. This guidance document helps supplement and support existing state regulations to ensure that development of our nation's abundant natural gas resources is safe and effective."
Chesapeake decides not to drill in NYC watershed
Chesapeake Energy Corp. does not plan to drill natural gas wells within the New York City watershed.
Aubrey K. McClendon, Chesapeake's chief executive officer, said, "…it has become increasingly clear to us over the past few months that the concern for drilling in the watershed has become a needless distraction from the larger issues of how we can safely and effectively develop the natural gas reserves that underlie various counties in the Southern Tier of New York."
Chesapeake is the only leaseholder in the New York City watershed, holding fewer than 5,000 acres there. "This leasehold is immaterial to Chesapeake and also does not appear prospective for the Marcellus shale," McClendon said.
Chesapeake notes that it is the largest leaseholder in the Marcellus shale play, with 1.5 million net acres under lease. The leases lie in northern West Virginia, across much of Pennsylvania, and across portions of the Southern Tier of New York.
McClendon also said, "Chesapeake supports the [New York] Department of Environmental Conservation's decision to have all hydraulic fracturing vendors register their products and reveal the chemicals used in them."
Chesapeake discloses the frac chemicals it uses on its web site www.chk.com and also on www.hydraulicfracturing.com.
Exploration & Development— Quick Takes
Talisman hikes Marcellus, Montney positions
Talisman Energy Inc., Calgary, said it has more than doubled its acreage position to a combined 350,000 acres in the Pennsylvania Marcellus and British Columbia Montney shales and is restructuring its North American operations into shale and conventional business units.
Talisman said it is positioned for a major increase in Marcellus drilling in 2010 and plans to move parts of its Montney shale play to commercial development at the beginning of the year.
The company defines Tier 1 as top quality acreage with an expected full cycle breakeven of $4/Mcf. It has added 170,000 acres in the last few months through a combination of acquisitions and swaps for $570 million (Can.).
In the Marcellus, Talisman expects to end 2009 at 70 MMcfd. Production exceeds 50 MMcfd, compared with 5 MMcfd at the start of 2009 after commercial development began in late 2008.
The company's last five Marcellus wells have estimated ultimate recoveries of 6 bcf/well, and it has hiked its average assumption for EUR over all Tier 1 acreage 17% to 3.5 bcf/well. The 2009 wells have average 30-day initial production rates of 4.5 MMcfd, and the last six wells flowed 5 MMcfd or more.
Marcellus drilling and completion costs are down to (US) $4.3 million/well.
The company's 214,000 highly contiguous net acres in the Pennsylvania Marcellus are centered on Bradford and Tioga counties. Its 180,000 Tier 1 acres have 1,800 net well locations and a full-cycle breakeven of (US) $4/MMBtu. Land acquisition costs averaged (US) $3,250/acre.
Meanwhile, the company has 270,000 net acres in the Montney shale, of which 166,000 acres are considered Tier 1 with 3,000 net well locations. Land acquisition costs averaged $3,500/acre (Can.).
The 2009 focus has been in the Greater Groundbirch, Greater Farrell, and Greater Cyprus areas. Talisman expects to complete 20 pilot wells this year, including 11 horizontal wells. The company expects a full-cycle breakeven of $4/Mcf (Can.) but is not providing guidance yet on drilling and completion costs, initial potential rates, or EURs.
Barrett may give one Uinta shale another try
Bill Barrett Corp., Denver, expensed as a dry hole in the quarter ended Sept. 30 its first horizontal well on the deep Hook shale gas prospect in eastern Utah.
The State 16H-32 well flowed natural gas at a subcommercial rate from Upper Mississippian Manning Canyon shale at about 8,000 ft.
Although the well wasn't commercial, the company will conduct further analysis of a longer horizontal section and improved completion techniques, building on the knowledge gained from this initial well, and will consider a second horizontal well in the area.
The prospect lies in northern Emery County southeast of Price, Utah, along the San Rafael swell on the Uinta basin southwestern flank (OGJ Online, May 6, 2009).
The Manning Canyon shale in the Uinta basin is 2,000 ft thick, 7,000-11,000 ft deep, with attractive 1-4% total organic carbon and a 1.2-1.5% Ro. A hard limestone that may provide a frac barrier underlies it. Shell Exploration & Production Co. has also tested the play (OGJ, Oct. 19, 2009, p. 41).
Bill Barrett also expensed the costs associated with a second shallower well into the fractured Juana Lopez member of the Upper Cretaceous Mancos formation and the Woodside well previously drilled.
The company has a 50% working interest in Hook with ConocoPhillips holding the other 50%. Barrett has 100% working interest in the shallower formation. The prospect covers 74,500 net undeveloped acres.
South Africa shales, sandstones evaluation set
Falcon Oil & Gas Ltd., Denver, plans to evaluate the natural gas content of fractured shales and sandstones of Permian age in the Karoo basin 120 miles northeast of Cape Town, South Africa.
Under a technical cooperation permit, Falcon has up to 1 year to perform a technical appraisal of 7.5 million acres in the basin. The appraisal will include a review of the South African Petroleum Data Base.
The permit does not require Falcon to drill any wells and establishes the company in a priority position for exercising future exploration rights on lands covered by the permit, Falcon said.
Nine wells drilled in the area in the late 1960s and early 1970s encountered gas shows. One well, drilled in 1968, flowed at the rate of 1.84 MMcfd of gas from fractures without stimulation, according to a Soekor Inc. geological well completion report.
Shales due look in New Zealand's East Coast basin
Trans-Orient Petroleum Ltd., Vancouver, BC, plans to deepen to 5,250 ft the Boar Hill-1 wildcat it has drilled to 1,600 ft in New Zealand's nonproducing East Coast basin.
The well's shallow section provided some encouragement as drill cuttings "head gas" readings were progressively more oil-rich as the well cut Oligocene strata, reaching full depth in Oligocene Weber. The drillsite is at the crest of the Boar Hill structure in the 100% controlled, 1.6 million-acre PEP 38349.
Deepening will take the well into the Paleocene and Upper Cretaceous Waipawa black shale and Whangai fractured oil shale source rocks.
Trans-Orient also plans to drill and core three shallow stratigraphic wells in its 100% owned, 530,000-acre PEP 38348 around the Waitangi Hill discovery, where a 1912 well recovered 50° gravity oil at 650 ft. Recent field work indicates that the Whangai formation generated the oil.
Trans-Orient will become a fully owned subsidiary of Tag Oil Ltd. in mid-December.
Drilling & Production— Quick Takes
Longhorn gas field starts in Gulf of Mexico
Eni SPA has started production from Longhorn gas field in 2,500 ft of water on Mississippi Canyon Blocks 502/546 in the Gulf of Mexico off Louisiana.
The field is producing 200 MMscfd through four subsea wells connected to the Corral platform, previously called Crystal, on Mississippi Canyon Block 365, 20 miles to the northwest.
Corral is a conventional jacket structure in 620 ft of water. Eni operates the new field and the platform.
On the Corral platform, Eni has added production and compression equipment able to process 250 MMscfd of gas and 6,000 b/d of oil.
Longhorn was discovered in July 2006.
Eni holds a 75% working interest, and Nexen Inc. holds 25%.
BPTT starts production from Savonette off Trinidad
BP Trinidad & Tobago (BPTT) has started its first natural gas production from Savonette field off Trinidad and Tobago.
Savonette lies in 290 ft of water about 50 miles southeast of Trinidad and Tobago in the prolific Columbus basin. BPTT holds a 100% interest in the field.
Production from the platform is tied into BPTT's Mahogany B platform via a 26-in., 5.3-mile subsea pipeline, where the gas is processed and then exported into BPTT's existing system. Gas from Savonette will supply Atlantic LNG's liquefaction plant for export as LNG to international markets, as well as the domestic market.
With Savonette, BPTT now has production from 12 offshore platforms.
Production from Savonette is expected to average 600 MMscfd of gas, plus associated condensate, from four wells. Savonette production will contribute to maintaining BPTT's total production level at more than 450,000 boe/d.
The Savonette platform was installed in February and is the fourth in a series of normally unmanned installations designed and constructed in Trinidad using a standardized 'clone' concept. The 1,898-tonne jacket and the 871-tonne topsides were built at the Trinidad Offshore Fabricators yard in La Brea, South Trinidad.
BPTT Chairman and Chief Executive Robert Riley said, "Since completing the Cannonball platform in 2005, in just four years, BPTT has designed and constructed three further platforms right here in Trinidad and commenced production from each—Mango, Cashima, and now Savonette."
The Savonette platform project was sanctioned on Apr. 4, 2008, and is a clone of the Cannonball, Mango, and Cashima platforms.
It has a designed capacity to accommodate as much as 1 bcfd of gas, but will produce 600 MMscfd.
BHP Billiton shuts in Griffin oil field
BHP Billiton has shut in the Griffin oil field off Western Australia in licence WA-10-L since it has come to the end of its economic life after 15 years of production.
Production reached a peak flow of 80,000 boe/d in the early stages of the development, but the field is now down to an average of only 4,000 boe/d due to natural depletion. The field was originally estimated to have a life of just 7 years. Total production from the field has been 178 million boe.
Production has been processed on the Griffin Venture floating production, storage, and offloading vessel—one of the first such vessels off Australia. Gas was piped ashore near Onslow for addition to the domestic gas grid. There is no word on the future of Griffin Venture at this stage.
Griffin and nearby associated Scindian and Chinook fields, in the Carnarvon basin about 62 km off Onslow, were found during an exploration program in 1989-90. The fields came on stream in 1994 through subsea wells connected to flowlines leading to the FPSO.
Joint venture partners are BHP, operator, with 45%, ExxonMobil Corp., 35%, and Inpex of Japan, 20%.
Processing — Quick Takes
PDVSA closes purchase of Dominican refiner stake
After several months of delays, Venezuela's state-owned Petroleos de Venezuela SA (PDVSA) has completed its purchase of a 49% stake in the Dominican Republic's state refiner Refineria Dominicana de Petroleo SA (Refidomsa), which owns a 34,000-b/d facility in Haina.
The Dominican Republic's Treasury Minister Vicente Bengoa said the sale, worth $131.5 million according to Venezuelan media, would allow his country to become an oil distribution center for the Caribbean and possibly Central America.
As part of the agreement, the Dominican Republic will buy 30,000 b/d of oil from Venezuela in addition to the 50,000 b/d it already receives under the Caracas-sponsored PetroCaribe accord, which provides Venezuelan oil and gas at preferential prices.
Analyst BMI said, "The deal will further integrate the Caribbean island into Venezuela's PetroCaribe petroleum trading scheme, touted by President Hugo Chavez as an alternative to the region's dependence on the US for its energy needs."
Chavez showed interest in the agreement in June, but PDVSA did not obtain a purchase memorandum of understanding from the Dominican government due to a regional crisis involving the ouster of Honduran President Manuel Zelaya, a close political ally of Chavez.
A further delay arose in August after California legislator Loretta Sanchez suggested the agreement would violate the terms of the free trade agreement between the US and the Dominican Republic. Under the FTA's terms, oil refined by Refidomsa could be exported to any market while under the new agreement with PDVSA refined oil could be sold only to Venezuela.
Purchase of the refiner was reported in July, when PDVSA said it agreed to acquire a 49% interest in Refimdosa as partial payment of oil debts. The Dominican Republic owed $1 billion to Venezuela for oil supplied under the PetroCaribe program (OGJ, July 20, 2009, Newsletter).
In December 2008, Royal Dutch Shell PLC sold its 50% stake in Refidomsa to the Dominican government for $110 million, making the government sole owner of the Haina refinery.
Shell said its decision to sell the shareholding was part of its active portfolio management to realize value for shareholders and to refocus the downstream portfolio.
Venezuela, Brazil sign accord on refinery
Brazil's state-run Petroleo Brazileiro SA (Petrobras) and Venezuela's Petroleos de Venezuela SA (PDVSA) completed negotiations for joint construction and operation of the Abreu e Lima refinery, in Brazil's Pernambuco state.
The two firms said the Abreu e Lima refinery will be able to process 230,000 b/d of heavy oil, supplied equally by Petrobras and PDVSA. The refinery's main product will be low-sulfur diesel.
Petrobras and PDVSA will incorporate the company in Brazil. They did not say when the procedures would be completed or when the refinery would begin operating.
The refinery was conceived to process crude from a PDVSA-Petrobras joint venture in the Carabobo region of Venezuela's Orinoco belt, but it has taken years for the two sides to agree on the terms of their partnership.
Last month, Petrobras said it had resolved all outstanding issues with PDVSA over development of the Abreu e Lima refinery, but that the Venezuelan firm would have to pay Petrobras at least $400 million when it signs the final agreement (OGJ Online, Oct. 8, 2009)
Petrobras will hold a 60% stake in the joint-venture firm, while PDVSA will hold the remaining 40%.
Construction on Aramco's Karan project under way
Saudi Aramco's Karan gas project swung into full speed last month as all four contract packages began construction, according to a company announcement.
Following the awarding of program contracts in March, the offshore platforms and subsea pipeline package began fabrication in September. The units involved 30,000 tonnes of steel for 38 structures, said an announcement from the company in mid October.
The three onshore packages—Karan gas facilities, pipeline utilities and cogeneration, and the Karan sulfur recovery and Manifa gas facilities—have all begun initial construction at Khursaniyah (OGJ, June 22, 2009, p. 50).
Project teams consist of members from Aramco and contractors J. Ray McDermott, Hyundai Engineering & Construction Co., Petrofac, and GS Engineering.
Karan is the first nonassociated offshore gas field Aramco has developed, the announcement reiterated. The onshore facility, about 160 km north of Dhahran, will be able to process 1.8 bscfd of Karan Khuff gas.
The gas will move in a 110-km subsea pipeline from field to onshore processing at the Khursaniyah gas plant. The offshore facilities at Karan consist of four production platforms connected to a main tie-in platform that will feed sour gas to the subsea pipeline.
The Khursaniyah plant will process gas through three trains, each with an inlet capacity of 600 MMscfd. The trains will include gas sweetening, acid-gas enrichment, gas dehydration, and supplementary propane refrigeration. The facilities also will include a cogeneration plant with boiler, a sulfur-recovery unit with storage tank, substations, and a transmission pipeline linked to the country's master gas system.
Transportation— Quick Takes
BP, Eni need more gas for Egyptian LNG train
Egypt's state-owned Egyptian Natural Gas Holding Co. (Egas), clarifying earlier comments, reported that BP PLC and Eni SPA have found just 2 tcf of gas, or half the amount needed to start up an LNG train at Damietta.
For the proposed second train to start up, said Abdallah Abdelhady, Egas assistant vice-chairman for production, the two firms have to find a total of 4 tcf of gas. Once they have done so, he said, the second train will start.
An Egas official said last week that the firm had shelved plans for the construction of a second LNG train at Damietta until enough reserves are found.
"If the Egyptian government is given proven gas reserve certificates then it will deal with the project in a more positive manner because we have a lot of commitments with domestic demand," said Hassan Sabry, an Egas projects and planning official.
Shamil Hamdy, undersecretary at the oil ministry, was earlier quoted as saying that Eni had delayed the project because it lacked the necessary financing due to the global economic downturn (OGJ Online, Oct. 30, 2009).
Construction begins on Chinese LNG terminal
Construction on another LNG terminal in China began earlier last month, according to press reports from the country.
The Ningbo LNG terminal is south of Shanghai, in Zhejiang Province, and will be the fifth Chinese terminal, the fourth owned by China National Offshore Oil Co. Ltd. China's National Development and Reform Commission approved the project earlier this year.
When completed in 2012, Phase 1 of construction at Ningbo will have installed 3 million tonnes/year of regasification capacity. Press reports put construction costs of Phase 1 at more than $1 billion. CNOOC envisions a matching second phase but has announced no completion date.
Ownership of CNOOC Zhejiang Ningbo Liquefied Natural Gas Co. Ltd. is among CNOOC Natural Gas & Power Co. Ltd. (51%), Zhejiang Provincial Energy Group Co. Ltd. (29%), and Ningbo City Power Developing Corp. (20%).
CNOOC's 3-million-tpy terminal at Shanghai received its first LNG cargo earlier this month (OGJ, Oct. 26, 2009, p. 11).
Floating Florida LNG terminal approved
A Gulf of Mexico offshore LNG terminal took a major step towards reality Nov. 2 when acting Maritime Administrator David T. Matsuda approved its construction off western Florida.
The approval was expected after Port Dolphin Energy LLC announced last week it had signed a "record of decision" in its application for a license to build the deepwater LNG port.
The signing, according to the announcement by the company, "paves the way to the awarding of a deepwater port license" to be issued by the US Maritime Administration. It marked the "successful completion of a comprehensive environmental impact statement" directed by the US Coast Guard and formal approval [in September] by Florida Gov. Charlie Crist.
More Oil & Gas Journal Current Issue Articles
More Oil & Gas Journal Archives Issue Articles