OGJ Newsletter

Aug. 20, 2012
International news for oil and gas professionals

GENERAL INTERESTQuick Takes

BSEE issues final offshore drilling safety regulations

The US Bureau of Safety and Environmental Enforcement issued its final offshore drilling safety rule. It strengthens requirements for safety equipment, well-control systems, and blowout prevention practices developed following the 2010 Macondo deepwater well blowout and oil spill, BSEE said on Aug. 15.

It said an interim safety rule was issued soon after the Deepwater Horizon semisubmersible drilling rig fire and explosion killed 11 people on Apr. 20, 2010, setting off a massive oil spill when it sank the following day.

“This rule makes final important standards that were put in place shortly after that spill and is based on input from stakeholders and recommendations from the numerous investigations related to that tragedy,” BSEE Director James A. Watson noted.

The oil and gas industry has operated under enhanced offshore safety requirements for the past 2 years, he added. More than 750 Gulf of Mexico deepwater and shallow-water drilling permits were approved during that period, according to BSEE.

It said the interim safety rule was issued under an emergency rule-making process that established new standards for casing and cementing, including integrity testing requirements; third-party certification and verification requirements; blowout preventer (BOP) capability, testing, and documentation obligations; and standards for specific well control training, to include deepwater operations.

The final rule improves upon an interim final rule by addressing requirements for compliance with documents incorporated by reference; enhancing the description and classification of well-control barriers; defining testing requirements for cement; clarifying requirements for the installation of dual mechanical barriers; and extending requirements for BOPs and well-control fluids to well-completions, workovers, and decommissioning operations, BSEE said.

The American Petroleum Institute is reviewing the final rule and hopes that BSEE carefully considered the language used in it, a spokesman said soon after the US Department of the Interior agency’s announcement.

USGS releases US reserves growth estimates

Potential undiscovered US reserves additions total 32 billion bbl of crude oil, 291 tcf of natural gas, and 10 billion bbl of natural gas liquids, the US Geological Survey said in a new estimate of technically recoverable domestic oil and gas. The amounts represent about 10% of the overall US oil and gas endowment, and do not include reserve growth estimates for federal offshore areas, it said.

“No attempt was made to estimate economically recoverable resources,” it noted. “Continuous, or unconventional, oil and gas accumulations such as shale gas, tight gas, tight oil, and tar sands were not included in this study.”

Unlike past reserve growth estimates which relied entirely on statistical extrapolations of growth trends, this one is partly based on detailed analysis of geology and engineering practices used in the assessed producing accumulations, the report said. The assessment used published and commercial, proprietary geologic information and field production data, it added.

“By providing geologically based, domestically consistent estimates of the potential additions of oil and gas from the growth in reserves in known fields, and placing that information in the public domain, we are furnishing a valuable projection on how much and where fossil fuels may be produced in the future,” said USGS Director Marcia K. McNutt.

“When combined with our estimates of undiscovered resources, policymakers can obtain a more complete picture of domestic, technically recoverable oil and gas,” she maintained.

API to intensify Vote 4 Energy effort

The American Petroleum Institute will increase its Vote 4 Energy program in Colorado, Florida, North Carolina, Ohio, and Virginia with print and online advertisements as it tries to make the issue more prominent in the 2012 election campaigns, API Pres. Jack N. Gerard said.

“It’s all about the voters,” Gerard told reporters during an Aug. 14 teleconference. “That’s why we talk with the American people about this regardless of their political persuasion. The public gets it.”

Gerard’s announcement came as API released results of a Harris Interactive telephone survey of 1,076 registered voters showing strong support from 47% for increased access to US oil and gas resources; 65% feeling strongly that this could lead to more American jobs; 62% feeling strongly that it could lower energy prices; 49% supporting strongly policies that allow more offshore development; and 57% backing strongly the Keystone XL pipeline project, the survey found.

Energy issues loom large for 92% of the responding voters in this election, according to the survey. About 66% consider them “very important” and 26% regard them as “somewhat important,” it said. About 63% feel Washington is on the wrong energy policy (47% strongly and 17% somewhat), the survey found. Respondents were 33% Republican, 32% Democrat, and 24% Independent, with another 6% unspecified, it said.

Midstates Petroleum to acquire lime assets

Midstates Petroleum Co. Inc., Houston, plans to buy Mississippi lime assets in Oklahoma and Kansas from Eagle Energy Production LLC in a cash-stock deal worth $650 million. The acquisition will add 103,000 net acres of which 84,000 are in the Mississippi lime play with 78,000 in Oklahoma and 6,000 in Kansas.

The remaining 19,000 acres are in the Hunton play in Oklahoma. Closing is expected by Oct. 1 with an effective date of June 1, Midstates said. Eagle Energy is a private exploration and production company having financial backing from Riverstone Holdings LLC.

John Crum, Midstates chief executive officer and president, “The properties we are acquiring in the Mississippian lime play are particularly appealing because they are in a market-recognized, emerging horizontal oil play with good predictability and solid economics.”

The transaction is expected to add 37 million boe of proved reserves of which 35% are oil and 23% natural gas liquids, with 35% of the total assets being producing properties.

Midstates is acquiring 114 gross producing wells that are 85% operated with an average 67% working interest. Net current daily production from the properties is 7,000 boe/d.

Including the new assets, Midstates will have an oil-weighted proved reserve base of 63.2 million boe of which 45% will be oil, 20% NGLs, and the rest will be gas. About 41% of total reserves will be proved developed.

Citation to buy Noble Energy oil properties in Kansas

Citation Oil & Gas Corp., private Houston operator, will buy oil and gas properties in Kansas from Noble Energy Inc. for $140 million.

Closing is set for September 2012, effective Apr. 1, 2012. The properties include Noble Energy’s interest in about 250 producing wells on 14,000 net acres. As of the effective date, net production was 1,000 b/d of oil equivalent and net proved reserves were 7 million boe, nearly all crude oil.

Noble Energy said the next phase of its noncore divestment program, continuing into 2013, involves small asset packages in the Midcontinent, Gulf Coast, San Juan, and Ark-La-Tex areas and the company’s remaining assets in the North Sea.

Elango succeeds founding Cairn India CEO

P. Elango, director, strategy and business services, has been named interim chief executive officer of Cairn India Ltd., Gurgaon, succeeding Rahul Dhir.

Dhir, who has led the company since its inception in 2006, said he was leaving the position “to pursue my entrepreneurial interests.” Cairn India became a publicly traded company in 2007 and became part of the Vedanta Group of London last year (OGJ Online, Dec. 6, 2011).

Cairn has exploration and production interests in India and Sri Lanka, as well as pipeline and gas processing interests. It recently produced an average 206,963 boe/d of oil and natural gas.

Exploration & DevelopmentQuick Takes

Thick presalt oil pay found at Santos Carcara well

A group led by Petroleo Brasileiro SA (Petrobras) has encountered 400 m of continuous oil pay at the Carcara deepwater discovery well on the BM-S-8 block in the Santos basin offshore Brazil.

One participant in the well described the results as among the thickest pay yet encountered in the Santos basin presalt (see map, OGJ, June 16, 2008, p. 39).

In late May, when it had drilled to 5,926 m, Petrobras said the well had encountered 171 m of continuous oil column and was still in the oil zone (OGJ Online, June 1, 2012). The oil is reported to be 31° gravity. Present depth is 6,213 m.

Carcara is in 2,027 m of water 232 km offshore Sao Paulo state and 20 km from the Bem-te-Vi discovery well. Petrobras is block operator with 66% interest, Petrogal Brasil has 14%, and Queiroz Galvao Exploracao e Producao and Barra Energia have 10% each.

Algeria’s Ain Tsila gas-condensate field commercial

Parties to the Isarene production-sharing contract have agreed a formal declaration of commerciality for Ain Tsila gas-condensate in the Illizi basin in eastern Algeria.

Upon approval by Algerian authorities, operator Petroceltic International PLC and partners expect to be granted a 30-year exploitation permit for the field.

The companies estimate Ain Tsila to contain a gross resource of 2.1 tcf of sales gas, 67 million bbl of condensate, and 108 million bbl of liquefied petroleum gas. Development would begin in 2014 and gas production start in the third quarter of 2017.

The initial 18 vertical wells will produce a combined 355 MMscfd of wet gas during a 14-year plateau to a new gas processing plant. A further 106 development wells are estimated to be needed to maintain the plateau.

Petroceltic has a 56.625% working interest in the development. Enel has 18.375% and Sonatrach 25%.

The field was formally declared commercial on completion of an agreement for Sonatrach to market the gas using a formula linked to Brent oil pricing.

AWE fracs Carynginia shale in Perth basin

AWE Ltd., Sydney, said it is recovering fluids and gas after successful fracs of two shale zones at the Woodada Deep-1 well in Australia’s onshore Perth basin.

AWE, with 100% interest, ran fracs on the Permian Middle Carynginia shale at 2,370-2,425 m and the Permian Upper Carynginia shale at 2,283-2,330 m. Nitrogen lift is in use.

Measurement of gas flow rates will not be possible until clean-up and flowback of the well has been completed, which is expected in the next week, the company said. The plan is to continue clean-up and flowback, collect gas samples for analysis, and measure production data.

The company noted that the results indicate that the Carynginia can be fracture stimulated and gas can be recovered from the shale but that it is too soon to assess commercial potential.

AWE has said it has a large leasehold in the basin underlain by the Carynginia, Triassic Cockatea, and Permian Irwin River prospective shale units below 2,500 m. The company noted an estimated 13-20 tcf of gas in place in the Middle Carynginia.

Georgina basin shale cores fluoresced, bled oil

Cores from the Middle Cambrian Lower Arthur Creek “hot shale” and Thortonia carbonate formations in the southern Georgina basin of Australia’s Northern Territory exhibited extensive fluorescence throughout and bled oil upon retrieval, said PetroFrontier Corp., Calgary.

PetroFrontier drilled the vertical section of the Owen-3 horizontal well to 1,180 m measured depth and is drilling the horizontal leg a further 1,000 m. The well is the company’s third horizontal penetration in the basin.

PetroFrontier retrieved a combined 32.5 m of core from the two formations. It also wireline logged the well with encouraging results that indicate more than 25 m TVD of hydrocarbon-bearing formation.

Completion is to begin later in August. PetroFrontier intends to conduct 10-stage frac stimulations at MacIntyre-2H, Baldwin-2Hst1, and Owen-3H. The wells will be flow-tested after all three have been stimulated. All three wells showed encouraging oil and gas indications in the hot shale.

Drilling & ProductionQuick Takes

Clipper South gas flow starts offshore the UK

RWE Dea UK has started production from Clipper South natural gas field in the UK North Sea.

Bayerngas UK, a 25% partner, said production has begun from a horizontal well drilled into a tight Lower Permian Rotliengendes sandstone encountered at 2,500 m below the seabed in 24 m of water. Fairfield Acer Ltd., another 25% partner, said initial gross production from well 48/19a-C1 was 43 MMscfd. Peak field production will be 100 MMscfd, Fairfield said.

RWE Dea UK, the operator with a 50% interest, in February said it plans to drill and hydraulically fracture as many as five horizontal Clipper South wells. The field, discovered in 1982, is on UKCS Blocks 48/19 and 48/20, 60 miles offshore Lincolnshire. It has an estimated 500 bcf of natural gas in place.

Production flows through a new, temporarily staffed wellhead platform linked to the Lincolnshire Offshore Gas Gathering System and Theddlethorpe terminal. Bayerngas estimated production life at 15 years.

GDF Suez sets Cygnus development offshore the UK

GDF Suez E&P UK plans develop Cygnus natural gas field in the southern gas basin of the UK North Sea with four platforms starting production by the end of 2015.

The operator has let a frame contract to Heerema Fabrication Group for fabrication and commissioning of four topsides for platforms to be set in 23 m of water 150 km northeast of Easington, England. Heerema will perform the work at its Hartlepool yard in Northeast England.

GDF Suez also let a contract for detailed design of the Cygnus project to AMEC, which handled front-end engineering and design (OGJ Online, Oct. 3, 2011). Cygnus development remains subject to approval by the UK government.

Three of the platforms will form a bridge-linked complex called Cygnus Alpha. The fourth, Cygnus Bravo, will not normally be manned.

GDF Suez estimates proved plus probable reserves at Cynus at 18 billion cu m. It hasn’t reported expected production rates.

The company plans to develop the field with 10 initial development wells and two drilling centers. It estimates investment at €1.7 billion. It expects gas to flow via the Esmond Transportation System (ETS) pipeline to the Bacton terminal in North Norfolk. Interests are GDF Suez 38.75%, Centrica Energy 48.75%, and Bayerngas 12.5%.

Diamond Offshore orders deepwater semi

Diamond Offshore Drilling Inc. has entered a contract with Jurong Shipyard, Singapore, for construction of a moored semisubmersible rig able to drill in as much as 6,000 ft of water.

The rig, Ocean Apex, will have a variable deck load of 7,000 tons, a maximum hook-load capacity of 2 million lb, and a 15,000 psi, five-ram blowout preventer. It will have quarters capacity for 140 workers. The Ocean Apex will use the hull from a Diamond Offshore cold-stacked unit. Its delivery is schedule for the second quarter of 2014.

Diamond Offshore estimates project cost, including commissioning, spares, and project management and excluding capitalized interest, at $370 million.

PROCESSINGQuick Takes

Calumet to buy Montana heavy-oil refinery

Calumet Specialty Products Partners LP, Indianapolis, has signed a definitive agreement to buy Montana Refining Co. Inc., which operates a small heavy-oil refinery in Great Falls, Mont., for $120 million plus an amount for working capital to be determined later.

The seller is Connacher Oil & Gas Ltd., Calgary, which said disposition of the refinery is part of a strategic review it began earlier this year (OGJ Online, Feb. 22, 2012). Connacher also has signed a letter of intent to sell its conventional oil and gas assets to an undisclosed buyer for $18.3 million cash.

The refinery to be acquired by Calumet has crude capacity of 9,500 b/d and handles mainly heavy feedstock from Canada.

Processing capacities include 2,800 b/d of fluid catalytic cracking, 1,000 b/d of catalytic reforming, and 1,100 b/d of hydrotreating.

Calumet Vice-Chairman and Chief Executive Officer Bill Grube said the acquisition “develops our long-term strategy of diversifying our crude slate and geographic presence.”

Connacher said it expects the working-capital adjustment to the Montana Refining purchase price to be $35-50 million.

The company’s conventional upstream properties, all in southern Alberta, produced 305 b/d of crude oil and 2.139 MMcfd of natural gas in the second quarter of 2012.

In a press statement, Connacher said the refinery and conventional-property sales would allow it to “pursue development opportunities to increase production at Great Divide,” its oil sands leasehold near Ft. McMurray, Alta.

In the second quarter, two of its Great Divide properties, Algar and Pad One, produced an average 11,651 b/d of bitumen via steam-assisted gravity drainage.

Methanex okays Chile-US methanol plant move

Methanex Corp., Vancouver, has let a contract to Jacobs Engineering Group Inc. to provide engineering, procurement, and construction services in its move of a methanol plant from Chile to Louisiana (OGJ Online, Feb. 7, 2012).

The firm decided to proceed with relocation of the idle 1-million-tonne/year plant to Geismar, La., and began dismantling it. Jacobs also has the contract for site-specific engineering and construction management at the 225-acre site in Geismar.

Methanex estimates cost of the project at $550 million. Operations are to start by the end of 2014.

TRANSPORTATIONQuick Takes

KMEP completes TGP, EPNG pipeline purchases

Kinder Morgan Energy Partners LP (KMEP) has completed its previously announced acquisition of 100% of Tennessee Gas Pipeline (TGP) and a 50% interest in El Paso Natural Gas (EPNG) pipeline from Kinder Morgan Inc. (KMI). The $6.22 billion transaction allows KMEP to more than replace cash flow from certain assets it is divesting pursuant to an agreement KMI reached with the US Federal Trade Commission as part of completing its El Paso Corp. acquisition.

FTC issued its final order approving the acquisition in June, requiring KMI to sell three Rocky Mountain gas pipelines and associated assets. KMI had said when the deal closed in May that it would offer assets to KMEP to replace the divested holdings (OGJ Online, June 20, 2012).

TGP is a 13,900-mile system with a design capacity of 7.5 bcfd, moving gas from Louisiana, the Gulf of Mexico, and South Texas to the US Northeast, including New York City and Boston. EPNG is a 10,200-mile system with a design capacity of 5.6 bcfd. It transports gas from the San Juan, Permian, and Anadarko basins to California, other western states, Texas, and northern Mexico. TGP and EPNG combined have more than 200 bcf of working gas storage capacity.

KMEP and BP North America last month signed deals to provide BP condensate processing and storage at KMEP’s terminal on the Houston Ship Channel (OGJ Online, July 19, 2012). In June, KMEP completed its purchase of a 50% interest in a joint venture owning the Altamont gathering, processing, and treating assets in the Uinta basin in Utah and the Camino Real gathering system in the Eagle Ford shale in Texas from Kohlberg Kravis Roberts & Co. LP (OGJ Online, June 5, 2012).

Shah Deniz partners commit to funding for TAP

Shareholders in the Trans Adriatic Pipeline (TAP) natural gas project reached an accord with members of the Shah Deniz consortium to secure funding for the project. The agreement also includes an option for the Shah Deniz shareholders to take as much as 50% equity in TAP.

TAP partners are Switzerland’s EGL 42.5%, Norway’s Statoil 42.5%, and Germany’s E.On Ruhrgas 15%. Shah Deniz partners are BP, State Oil Co. of Azerbaijan Republic, and Total.

“These funds will contribute towards continued work in several important areas during the period running up to the final routing decision, expected in 2013,” a TAP news release said.

TAP will transport gas from the giant Shah Deniz II development in Azerbaijan, shipping it via Greece and Albania, across the Adriatic Sea to southern Italy, and then to Western Europe.

Sunoco Logistics starts Mariner East open season

Sunoco Logistics Partners started a binding open season for Project Mariner East to deliver 65,000 b/d of propane and ethane from Marcellus shale areas in western Pennsylvania, including MarkWest Energy Partners’s processing and fractionation complex in Houston, Pa., to southeastern Pennsylvania.

Mariner East will be scalable to support higher volumes as needed, with propane shipments expected by second-half 2014 and full propane and ethane operations in first-half 2015. Subject to terms of the open season, Sunoco will give priority service to shippers making long-term volume commitments.

Mariner East would move ethane to the Philadelphia area from where it would be transported via ship to either the US Gulf Coast or Europe. It would use primarily existing Sunoco pipeline. The project would also include new storage at Philadelphia and near Nederland, Tex.

MarkWest, Sunoco’s partner in the project, says the capacity of Sunoco’s existing 8-in. OD pipeline between Delmont, Pa., and Philadelphia could be increased to meet any future increase in demand for space on the system.