OGJ Newsletter

Exploration & Development — Quick Takes

Gohta discovery expanded with Lundin's second well

Lundin Petroleum AB reported its Gohta appraisal well 7120/1-4s drilled in PL492 in the Barents Sea offshore Norway encountered 10 m of Upper Permian limestone conglomerate with good reservoir properties overlying fractured limestones of limited reservoir quality.

The well was spud earlier this year with the intention of testing the reservoir properties and hydrocarbon potential of the Permian carbonates in the Gohta karst Roye formation and the overlying Kobbe formation sandstones (OGJ Online, May 23, 2014).

The well is in the western part of the Gohta discovery in PL492, 5.3 km northwest of the original Gohta discovery (OGJ Online, Oct. 2, 2013).

The company has carried out data acquisition and sampling in the reservoir, which included conventional coring and fluid sampling. Both pressure and fluid properties indicate communication between the reservoirs in the 7120/1-4s and 7120/1-3 wells on the Gohta structure.

A production test of the 10-m thick gas condensate zone produced 26.4 MMcfd of gas and 880 b/d of condensate. Pressure build-up analysis showed the test draining an area within a 1,000-m radius.

An attempt to test a 50-m interval starting 23 m below the estimated gas-oil contact produced a rate 6.4 MMcfd of gas.

The well was drilled to a total depth of 2,490 m below sea level in 331.5 m of water. The company said the well will now be permanently plugged and abandoned before the Island Innovator rig is moved to PL609 where Lundin Norway will spud exploration well 7220/11-1.

Lundin Norway holds a 40% working interest in PL492 and serves as operator. Its partners are DNO ASA and Noreco Norway AS, which hold respective interests of 40% and 20%.

Statoil enters Colombia by securing offshore license

Statoil ASA has been awarded 33.33% interest in the COL4 license offshore Colombia in the Caribbean Sea during the 2014 Colombia Licensing Round, marking the Norwegian company's entry into the South American country.

ExxonMobil Exploration Colombia will also hold 33.33% interest in the license, while Spain's Repsol SA will serve as operator with 33.34%. The award is subject to the final approval of the National Hydrocarbons Agency of Colombia (ANH).

"Deepwater offshore Colombia is virtually untested," said Nick Maden, Statoil senior vice-president for exploration activities in the Western Hemisphere, adding, "The award of new acreage in this frontier area is in line with our exploration strategy of early access at scale."

Statoil says entry comprises an early exploration phase, and initial working commitments include 2D and 3D seismic acquisition. There are no well commitments during the first exploration phase.

The US Energy Information Administration notes that Colombia has seen a dramatic increase in oil and natural gas production in recent years due to a series of regulatory reforms. Total oil production in the country surpassed 1 million b/d in 2013, while natural gas production surpassed 400 bcf in 2012.

Central starts work toward Dingo field development

Central Petroleum Ltd., Brisbane, has begun clearing works for the Dingo gas field development in central Australia's Amadeus basin 65 km south of Alice Springs.

This week Central Petroleum has received a pipeline licence (PL30) from the Northern Territory government. This follows the granting of a petroleum production licence (PPL 7) earlier this year and the more recent approval from the Territory's Department of Mines and Energy for the preliminary field development plan and the preliminary reservoir management plan.

The development comprises a field gathering system that will connect two production wells to a central processing plant and a wholly owned 45-km pipeline to the Northern Territory government-owned Owens Spring power station.

Start of gas production is slated for first-quarter 2015.

Central acquired the Dingo field, along with the producing Palm Valley gas field to the west, from Magellan Petroleum Australia in March in a deal worth $35 million (Aus.).

Dingo field was discovered in 1981. In September 2013 Magellan signed a contract with Northern Territory Power & Water Corp. for the long-term sale of as much as 31 petajoules of gas from Dingo on a take-or-pay basis for 20 years.

In the meantime, further north, Central Petroleum has spudded its Whiteley-1 unconventional gas wildcat in Georgina basin permit ATP 912 near Bedourie in western Queensland.

It is the first in a program of unconventional gas wells operated by Central in partnership with French international major Total. It will be followed by Gaudi-1, scheduled to begin during mid-September this year in ATP909 a little to the south.

Each well will be extensively cored and sampled for gas desorption and reservoir properties as well as logged to evaluate hydrocarbon resource potential.

HNR moves ahead with Dussafu block development

Harvest Natural Resources Inc., Houston, reported that it has signed a declaration of commerciality with the Gabonese government pertaining to Dussafu block offshore Gabon. Also, Gabon awarded an exclusive exploitation authorization (EEA) for the development and exploitation of oil discoveries on Dussafu block.

HNR spudded the Dussafu Tortue Marin-1 exploratory well on the Dussafu Marin PSC offshore Gabon in late 2012 (OGJ Online, Nov. 11, 2012).

The EEA provides for exploitation of the presalt oil discoveries on the Ruche (2011), Tortue (2013), Moubenga (1981), and Walt Whitman (1996) prospects, HNR said. These discoveries will be named, respectively, Ruche A, Ruche B, Ruche C, and Ruche D, and collectively will be called Ruche field. The area awarded by the EEA covers 850.5 sq km.

The proposed field development plan includes a single floating production, storage, and offloading vessel and subsea wells that will be tied back to the FPSO. HNR will submit the proposed FDP within the next 90 days for sanction by Gabon.

"The award of the EEA is a major milestone toward bringing the Dussafu block into production," said HNR Pres. and Chief Executive Officer James A. Edmiston.

Harvest holds 66.667% interest in Dussafu block through its wholly owned Harvest Dussafu BV subsidiary, while Panoro Energy ASA holds 33.333% interest.

Drilling & Production — Quick Takes

AER responds to cause of Primrose bitumen leaks

The Alberta Energy Regulator (AER) said on July 22 that it agrees with the assessment that the steaming strategy and wellbore issues were the main contributing factors to last year's bitumen flow-to-surface (FTS) incidents at the east and south sections the Primrose project operated by Canadian Natural Resources Ltd. (CNRL).

The response comes after AER completed a preliminary review of both the CNRL causation report, received on June 27, and the independent technical review of CNRL's report.

The technical review indicated that CNRL's strategy to inject large volumes of steam at fracture pressure in closely spaced wells was a fundamental cause of the FTS incidents.

Four FTS incidents have been reported to AER since May 2013, resulting in the recovery of 1180 cu m of bitumen emulsion from the sites in an affected area covering 20.7 hectares (OGJ Online, July 18, 2013).

"Our assessment of the reports leads us to believe that these [FTS] events can be prevented if proper mitigation measures are put in place," said Jim Ellis, AER president and chief executive officer.

Restrictions on steaming activity at Primrose East and within 1 km of Primrose South have been in place since June 2013. AER says the bitumen release has been contained, with cleanup efforts ongoing.

Ellis said AER, however, is "not prepared to approve a return to full operations at these sites until all potential risks are addressed and proper requirements are in place to avoid a similar incident," adding, "This will require a gradual, step-by-step approach that allows us to manage those risks."

AER's investigation is ongoing, and it continues to examine what measures can be put in place to prevent similar incidents. CNRL and the panel that conducted the independent technical review continue to collect and analyze data and will submit final reports to the AER in September once all the data have been analyzed.

Statoil resumes oil, gas production from Njord A platform

Statoil ASA reported the restart of oil and gas production July 19 from the Njord A platform in the Norwegian Sea. Production had been shut for maintenance for nearly a year.

Extensive analyses in 2013 revealed a need to reinforce the platform structure. Maintenance work included bracing the primary beams and struts, and increasing the length of the secondary beams under the platform.

Even with the recent reinforcements, Statoil said the platform "will not be robust enough to resume drilling activity" this summer.

Statoil said long-range plans include further bolstering the platform to prepare it for future drilling operations and an extended lifetime on the Njord field.

Arve Rennemo, head of Njord operations, said, "Njord A will produce oil and gas until the summer of 2016, after which it will be taken to shore for additional upgrades."

Production from Njord A platform began in September 1997. It was designed for an original lifetime of 16 years.

Before production ceased on July 27, 2013, the Norwegian Petroleum Directorate estimated 2013 production would average 10,000 b/d of oil, 980 million standard cu m of natural gas, and 230,000 tonnes of NGL (OGJ Online, Sept. 27, 2013).

Operators, FMC team to develop subsea equipment

Anadarko Petroleum Corp., BP PLC, ConocoPhillips, and Royal Dutch Shell PLC have signed an agreement with FMC Technologies Inc. to jointly develop next-generation standardized subsea production equipment and systems for producing oil and gas from deepwater high-pressure, high-temperature reservoirs.

The group plans to build the equipment and systems to withstand pressures reaching 20,000 psi and temperatures reaching 350° F. at the mudline, while improving overall deepwater development through the standardization of materials, processes, and interfaces, as well as the enhancement of reliability and operability.

BP previously reported its intention with Maersk Drilling to develop conceptual engineering designs for next-generation offshore drilling rigs as part of the company's Project 20K, an initiative to develop what BP calls "next-generation systems…to help unlock the next frontier of deepwater oil and gas resources (OGJ Online, Feb. 8, 2013)." At the time the company said current equipment has a technical limit of 15,000 psi and 250° F.

PROCESSING — Quick Takes

Sadara lets contract for Jubail petrochemical complex

Sadara Chemical Co., a joint venture of Saudi Aramco and Dow Chemical Co., has let a contract to Rolta India Ltd., Mumbai, to implement a comprehensive engineering information system (EIS) within Sadara's grassroots Jubail integrated chemical complex in Jubail Industrial City II, in Saudi Arabia's eastern province (OGJ Online, Oct. 18, 2012).

This latest multimillion dollar contract expands the scope of work under an earlier multimillion dollar contract awarded to Rolta in July 2013, Rolta said.

Rolta will manage the project with a global team working out of the US, India, and Saudi Arabia, the company said.

Currently under construction, the $20 billion complex will possess flexible cracking capabilities and will produce more than 3 million tonnes/year of high-quality chemical products and performance plastics, Rolta said.

"Successful implementation of the engineering system is vital to the support and efficient operation of the Sadara complex," said Taher Nemer, Sadara's project manager for manufacturing and engineering systems at the Jubail complex.

Comprised of 26 manufacturing units, the complex will be one of the world's largest integrated chemical facilities, and the largest ever built in one single phase (OGJ Online, July 26, 2011).

The manufacturing units will produce a wide range of performance products such as polyurethanes (isocyanates, polyether polyols), propylene oxide, propylene glycol, elastomers, linear low-density polyethylene, low-density polyethylene, glycol ethers, and amines.

Sadara is on track to deliver its first products in second-half 2015, with full operation of the complex scheduled in 2016, according to a Jan. 14 release from Finland's Metso Corp., who will supply valves to control process flows in several areas of the complex, including the mixed feed cracker.

Tesoro plans to boost xylene recovery at US West Coast

Tesoro Corp. is planning a petrochemical feedstock project that will utilize production from its US West Coast refining operations to enhance xylene recovery at its 120,000-b/d Anacortes, Wash., refinery about 70 miles north of Seattle.

The $400 million project, which will involve gathering intermediate feedstock, primarily reformate, from its West Coast refining system, is designed to enable the Anacortes plant to recover up to 15,000 b/d of mixed xylene, the US independent refiner said in a July 21 release.

The mixed xylene mostly will be exported to destinations in Asia-Pacific, where regional demand is a primary driver in the global xylene market's annual growth rate of about 5% to 7%, Tesoro said.

Pending permitting and approval, Tesoro said it expects the project to be commissioned in 2017.

A final investment decision on the project is due by yearend, the company said.

In addition to the Anacortes refinery, Tesoro's US West Coast refining system also includes the 166,000-b/d Golden Eagle refinery at Martinez, Calif., a 363,000-b/d refinery at Los Angeles, Calif., and a 72,000-b/d refinery at Kenai, Alas.

Delta inks crude supply agreement for Trainer refinery

Monroe Energy LLC, a subsidiary of Delta Air Lines Inc., has entered into a 5-year agreement with midstream logistics provider Bridger LLC, Addison, Tex., to supply 65,000 b/d of US crude oil to Delta's 185,000-b/d refinery in Trainer, Pa.

The supply agreement, which will cover about one third of crude oil processed daily at the refinery, comes as part of Delta's strategy to manage the cost of the airline's primary expense of jet fuel, according to a July 21 joint release from Delta and Bridger.

Bridger will supply the Trainer plant with lower-cost US crude from Bakken oil fields in North Dakota to replace more expensive crude feedstocks the refinery historically has sourced from overseas, the companies said.

"By combining this transaction with our other sources of domestic crude supply, we expect to meet our goal of a minimum of 70,000 b/d of domestic crude sourcing at the refinery," said Graeme J. Burnett, Delta's senior vice-president for fuel optimization and chairman of Monroe.

Bridger recently invested $200 million to expand its existing railcar fleet with acquisition of 1,300 railcars that exceed current safety specifications for crude oil tank cars which will be among the mix of assets used to transport crude supplies to the Trainer refinery, the company said.

Monroe Energy agreed to buy the Philadelphia refinery from Phillips 66 in 2012 for $180 million with the goal of converting the installation to primarily produce jet fuel in order to reduce Delta's fuel costs (OGJ Online, Sept. 17, 2012; May 1, 2012).

TRANSPORTATION — Quick Takes

Tallgrass secures right to acquire Pony Express interest

Tallgrass Energy Partners LP (TEP) has been offered the right to purchase 33.3% interest in Tallgrass Pony Express Pipeline LLC by Tallgrass Development LP for $600 million.

Pony Express owns and develops an oil pipeline project consisting of the conversion of a 430-mile natural gas pipeline and the construction of a 260-mile southward pipeline extension that, when complete, will result in an oil pipeline from Guernsey, Wyo., to Cushing, Okla.; and the construction of a 66-mile lateral in Northeast Colorado that will interconnect with the mainline.

The project is being completed in stages, with the mainline expected to be placed in service during the third quarter, while the Northeast Colorado lateral is expected to be in service during next year's first half.

TEP in 2012 acquired Kinder Morgan Interstate Gas Transmission, Trailblazer Pipeline Co., Casper-Douglas natural gas processing and West Frenchie Draw treating facilities in Wyoming, and 50% interest in the Rockies Express Pipeline from Kinder Morgan Energy Partners LP for $1.8 billion (OGJ Online, Aug. 20, 2012).

Cheniere, EDF sign Corpus Christi LNG supply deal

Corpus Christi Liquefaction LLC (CCL), a unit of Cheniere Energy Inc., Houston, has agreed to supply Electricite de France SA (EDF) with 380,000 tonnes/year of LNG on the start of operations of Train 2 of the LNG export facility under development near Corpus Christi, Tex.

Start-up of Train 3—which would raise the project's aggregate production capacity to 13.5 million tpy—would result in an increase in the deal to 770,000 tpy and extension of the agreement term to 20 years, with an extension option of up to 10 years. Under the agreement, EDF will purchase LNG on a FOB basis for a purchase price indexed to the monthly Henry Hub price plus a fixed component. LNG will be loaded onto EDF's vessels. Cheniere says deliveries from Train 3 are expected to occur as early as 2019.

CCL has recently struck supply deals with Endesa Generacion SA of Spain (OGJ Online, Apr. 2, 2014); Iberdrola SA of Spain (OGJ Online, May 30, 2014); and Woodside of Australia (OGJ Online, July 1, 2014). Cheniere says LNG exports from the CCL project could begin as early as 2018.