OGJ Newsletter

April 29, 2013
International news for oil and gas professionals

GENERAL INTERESTQuick Takes

Stopping project won't keep oil sands in the ground

Defeating the proposed Keystone XL pipeline project would not keep Canada from producing crude oil from its oil sands, Natural Resources Minister Joe Oliver said during a visit to Washington.

"Several of the project's opponents believe it would be a decisive body blow which would keep the oil sands in the ground. That's simply wrong," he said in remarks at the Center for Strategic and International Studies on Apr. 24.

Oliver called on the Obama administration to approve the project and allow construction to begin on the pipeline's final 875 miles.

"This project is completely in step with the long and productive US-Canadian energy relationship," Oliver said. "Rejecting it would be a serious reversal of that relationship."

He disputed environmental organizations' charges that the crude would be exported once it reached the US Gulf Coast, saying it simply would replace heavy oil US processors now import from Venezuela, which has become a much less reliable supplier.

"For the US, it comes down to a clear choice: import more heavy oil from its closest neighbor which respects contracts and has similar environmental goals, or continue to get it from a country which has threatened to cut off supplies 5 times in the last 5 years," he said.

Oliver said he considers rail a possible transportation supplement—but not a replacement—for pipelines. Canada is interested in building pipelines to begin exporting crude from its east and west coasts to countries in the Organization for Economic Cooperation and Development, he said.

"Right now, we have one main customer," he said. "The United States will need to continue importing oil as it develops its considerable resources, but imports won't be as big a part of its total supply. Canada would like to start selling its oil to other consuming countries."

Oliver spoke while US construction trades unions rallied in support of Keystone XL and the jobs it would produce in front of the AFL-CIO's national headquarters.

API wants EPA to go further in RIN reform effort

The American Petroleum Institute and American Fuel & Petrochemical Manufacturers welcome the US Environmental Protection Agency's proposals to address renewable fuel credit fraud, but would like to see the agency go further, the trade associations jointly said.

"EPA's proposal is a welcome attempt to address the significant fraud in the biofuel markets, but will not solve the systemic problems caused by the [federal Renewable Fuel Standard] biofuel mandates," AFPM Pres. Charles T. Drevna said Apr. 19.

"These mandates will harm consumers as EPA forces the consumption of increasing amounts of biofuels that are incompatible with today's cars and refueling facilities," Drevna noted.

AFPM supports the agency's decision to provide refiners with an affirmative defense to the liability created by fraudulent biofuel producers, Drevna said, but the scope of the EPA proposal is much broader than the problem it purports to solve.

The rule follows EPA's discovery of more than 140 million fraudulently created biodiesel credits—known as renewable identification numbers—and its decision to assess fines against refiners who purchased such RINs from EPA-registered biodiesel producers.

API Senior Policy Advisor Patrick Kelly said the trade association considers EPA's proposal a positive first step. "The voluntary program allows companies that purchase credits to be assured they were validly generated and represent true production of renewable fuels," he indicated.

"We remain concerned, however, that EPA's proposal shifts some of [its] enforcement responsibility onto third party auditors," Kelly continued. "EPA's plan does not change the fact that the [RFS] is unworkable and must be repealed."

EPA schedules hearings on gasoline proposal

The US Environmental Protection Agency scheduled public hearings Apr. 24 in Philadelphia and Apr. 29 in Chicago about its proposed Tier 3 gasoline sulfur content and vehicle emissions limits.

The proposal would set new vehicle emissions standards and lower the sulfur content of gasoline, considering the vehicle and its fuel as an integrated system staring in 2017, according to EPA.

The American Petroleum Institute and American Fuel & Petrochemical Manufacturers each have called the plan unnecessary and costly.

Exploration & DevelopmentQuick Takes

Three North Slope exploratory tests find oil

Repsol SA said its winter exploratory campaign on Alaska's North Slope resulted in three "good quality hydrocarbon discoveries" whose results are encouraging for future development, but the company did not use the word commercial in its announcement.

The Qugruk-1 and Qugruk-6 wells, about 3 miles apart along the Beaufort Sea shore, produced two hydrocarbons shows, with encouraging results during production tests.

The Qugruk-3 well, 7 miles inland from the other two wells, identified hydrocarbons at multiple levels, Repsol said. The company said the Q-1, Q-3, and Q-6 wells reached depths of 2,493 m, 3,214 m, and 2,637 m, respectively, but didn't provide names of the oil formations.

"These results are encouraging for the future development of the resources discovered," Repsol said. "Recent tax reform passed in Alaska was a critical factor in ensuring the development of this project, where extreme climate conditions and geographical remoteness result in high operating costs."

Repsol operates the discovering group with a 70% stake, together with US companies 70 & 48 LLC, a subsidiary of Armstrong Oil & Gas, 22.5%, and GMT Exploration Co. 7.5%.

Medco group to test North Sumatra gas find

A group led by PT Medco Energi plans to test an indicated gas discovery on Block A Aceh in North Sumatra, Indonesia.

The Matang-1 exploratory well has been drilled to 7,893 ft true vertical depth. It penetrated a gross gas column of at least 90 ft in the Oligo-Miocene Upper Bampo limestone formation, the primary reservoir target. The base of the gas column has not been encountered.

While drilling the primary reservoir target, losses into the formation and gas influx into the well occurred. As a result, Medco chose to suspend the well and to test the reservoir interval drilled to date to obtain flow rate and gas quality information.

Interests in Block A Aceh are Medco and Premier Oil PLC 41.67% each and Japan Petroleum Exploration Co. Ltd. 16.66%.

Drilling & ProductionQuick Takes

Vladimir Filanovsky field blocks complete

Lukoil reports completion of two supporting blocks weighing a total of 5,000 tons to be towed out soon to Vladimir Filanovsky oil field in the northern Caspian Sea (OGJ Online, Oct. 8, 2012).

The blocks will be set in 7 m of water for the ice-resistant drilling and production platform.

The supporting blocks were built at the LOTOS shipyard in Astrakhan in Russia's Republic of Kalmykiya. Each block is 28.3 m long, 23.7 m wide, and 16.4 m high. Twenty 2-m-diameter piles driven to depths of 60 m will secure the blocks to the seabed.

Lukoil has commissioned two supporting blocks weighing a total of 5,000 tons. Astrakhan Shipbuilding Production Association is building the drilling and production platform's topsides, which will be attached to the supporting blocks in mid-2014. Photo from Lukoil.

Astrakhan Shipbuilding Production Association is building the drilling and production platform's topsides, which will be attached to the supporting blocks in mid-2014.

The platform will support drilling of 11 directional wells. It will be bridge-linked to a central processing platform and accommodation module.

Alberta eases royalty on five pilot projects

The Alberta government has awarded royalty allowances worth a total of $33 million to five pilot projects designed to improve recovery rates and lower environmental effects of oil sands and conventional oil and gas production.

Contributions from the four companies receiving assistance under the Innovative Energy Technologies Program will total $173 million. Since its start in 2004, the $200-million program has supported 46 projects.

Recipients of the latest round of royalty help are:

• Imperial Oil Ltd. for a pilot at its Cold Lake project involving a cyclic solvent process, which uses propane and propane-diluent solvent injection and production cycles to mobilize heavy oil instead of using steam. The royalty allowance is $10 million for a project expected to cost $100 million.

• Cenovus Energy Inc. for a 10 Mw chemical looping steam generator at its Christina Lake thermal project. The specialized steam generator keeps carbon dioxide separate from other gases emitted during combustion, avoiding the need to remove CO2 after combustion and making pure CO2 available for capture and storage. The royalty allowance is $10 million, the total project cost $62 million.

• Perpetual Energy for a low-pressure electro-thermally assisted drive pilot 75 km north of Red Earth. The project will use three parallel horizontal wells with electric cables to heat bitumen with water or solvent injected during electrical heating. Perpetual Energy expects the process to require less energy and water than conventional steam-assisted gravity drainage. The project cost is $18.2 million, the royalty allowance $5.46 million.

• Cenovus for a sand-alkali-surfactant associative polymer flood in conventional oil production at Canadian Forces Base Suffield near Medicine Hat. The pilot is expected to encourage conservation of fresh water in enhanced recovery. The royalty allowance is $5.37 million for a project costing $17.9 million.

• Canadian Natural Resources Ltd. for a pilot at its Horizon mine near Fort McMurray involving two processes to treat, recycle, and reuse high-saline and process-affected water. The project cost is $8.32 million, the royalty allowance $2.496 million.

MEG reports low SOR in SAGD pilot

MEG Energy, Calgary, has achieved a steam-oil ratio of 1:3, which it calls "industry-leading," in a pilot project at its Christina Lake thermal oil sands project in Alberta.

In its third-quarter financial report MEG said it is expanding application of the technology, called enhanced modified steam and gas push (eMSAGP).

Since full implementation of the pilot in January 2012, the technology by the fourth quarter had lowered steam rates by 30% without decreasing the production trend, the company reported.

In the pilot, MEG drilled two infill wells and injected noncondensable gas with steam between three steam-assisted gravity drainage well pairs in early stages of production. The technique is normally applied in late phases of SAGD production.

MEG said early results from new wells using eMSAGP have shown similar improvements, "driving expectations of further efficiencies and incremental production increases."

It said it will initiate eMSAGP in an additional six wells in the current quarter.

It plans to begin steaming the 35,000-b/d second stage of Christina Lake's second phase in the third quarter. The company projects total Christina Lake production this year at 32,000-35,000 b/d.

MEG reported a first-quarter loss of $71.3 million (Can.), compared to a $53.4 million profit in the same period of 2012, attributing the loss mainly to unrealized foreign exchange effects related to a weakening of the Canadian dollar against the US dollar and lower cash flows from operations due to lower price realizations.

Because of a widening of the discount of bitumen blend against West Texas Intermediate, its bitumen realization fell to $30.04/bbl in the first quarter this year from $50.15/bbl in the first quarter of 2012.

PROCESSINGQuick Takes

QP signs JV deal for condensate refinery

Qatar Petroleum has signed a joint venture agreement covering the expansion of its Laffan Refinery condensate spliter at Ras Laffan (OGJ Online, Aug. 19, 2011).

It plans a condensate refinery with capacity of 146,000 b/d similar to the Laffan Refinery 1 (LR1) facility, which started up in September 2009.

LR 2, to be operated by Qatargas Operating Co. Ltd., will process untreated condensate from supergiant North gas field, producing as much as 60,000 b/d of naphtha, 53,000 b/d of jet fuel, 24,000 b/d of gas oil, and 9,000 b/d of LPG. Construction of the $1.5 billion facility is expected to be complete in the second half of 2016.

A diesel hydrotreater now under construction and expected to be commissioned in the second quarter of 2014 will have capacity to process all light gas oil from the LR 1 and LR 2 facilities, yielding ultralow-sulfur diesel.

Ownership under the joint venture agreement is QP, 84%; Total, 10%; Idemitsu and Cosmo, 2% each; and Marubeni and Mitsui, 1% each.

Australian gas plant nears completion

Empire Oil and Gas NL, Claremont, WA, is nearing completion on its Red Gully natural gas and condensate separation plant in Western Australia.

The plant will treat condensate and gas from the Gingin West-1 and Red Gull-1 discovery wells. Initial capacities will be 10 MMcfd and 500 b/d, to be doubled by a likely second train. Cost of the plant and related construction is estimated at $35.8 million.

Gas will be treated to meet specifications for flow, under a 20-year agreement, through the Dampier-to-Bunbury gas pipeline (OGJ Online, Dec. 29, 2006), which will be reached via a new 2-mile, 4-in., 30-MMcfd pipeline that is part of the project. Condensate will be stored and trucked to BP's Kwinana, WA, refinery.

The company statement said that, in addition to treating gas from the Gingin West-1 and Red Gully-1 discovery wells, the plant could be used to treat other nearby conventional and unconventional discoveries.

Discoveries at Gingin West-1 and Red Gully-1 in permit EP 389 led to gas that flowed at 12 MMcfd and up to 832 b/d from the Jurassic Upper Cattamarra Coal Measures.

Crosstex awards contracts for La. expansions

Crosstex Processing Services LLC, a unit of Crosstex Energy LP, Dallas, has awarded a contract to UOP LLC, Des Plaines, Ill., for technology and equipment to extract petrochemical feedstocks from NGLs derived from shale gas.

UOP will install its Russell de-ethanizer and depropanizer fractionators capable of handling a 100,000 b/d of mixed NGLs at Crosstex Energy's 225-MMcfd gas plant in Plaquemine, La. Start-up will be in 2014.

The project is part of Crosstex Energy's Phase II of its Cajun-Sibon NGL pipeline extension and fractionator expansion due for start-up late next year (OGJ Online, Dec. 12, 2012).

Included with the new 100,000-b/d fractionator is expansion of the Cajun-Sibon pipeline by 50,000 b/d of raw-make NGL for total capacity of 120,000 b/d and construction of 57 miles of NGL pipelines from Crosstex's Eunice, La., fractionator, connecting to the new Plaquemine fractionator.

TRANSPORTATIONQuick Takes

Enbridge updates Eastern Access project progress

Enbridge Inc. expects to complete reversal of its Line 9A crude oil pipeline between Sarnia and North Westover, Ont., this year, said Tom Hodge, project director, expansion and replacement project, at the API Pipeline Conference in San Diego. The Line 9A reversal is part of the company's larger Eastern Access Projects designed to transport Western Canadian crude as far east as Montreal, Que. Hodge said reversal of Line 9B between North Westover and Montreal would be complete early-2014. Enbridge expects the reversed Line 9 to carry as much as 200,000 b/d.

A 50,000 b/d expansion of Enbridge's Line 5 between Superior, Minn., and Sarnia will be completed early this year, according to Hodge, with Line 79 between Stockbridge and Romulus, Mich., entering service this month. Hodge said replacement work on Line 6B between Griffith, Ind., and Stockbridge, Mich., would be done by yearend, with Stockbridge to the St. Clair River in Marysville, Mich., done by early 2014.

Line 79 work includes laying 35 miles of new 20-in. OD pipe and leasing 29 miles of idle Wolverine 16-in. OD pipe, as well building new metering and other facilities. The Line 6B Phase 2 replacement program follows work done last year by Enbridge to replace 75 miles of the line as part of the Line 6B 2012 Maintenance and Rehabilitation Project. The full pipeline will have replaced once Phase 2 is complete, increasing its capacity to 500,000 b/d from 240,000 b/d.

The Eastern Access projects also include expansion of the Spearhead North pipeline (Line 62) between Flanagan, Ill., and the terminal at Griffith, Ind., to 235,000 b/d from 130,000 b/d by adding horsepower. The company will also add a 330,000 bbl tank at Griffith to existing storage (OGJ Online, May 17, 2012).

Puerto Rican authority plans FSRU scheme

Excelerate Energy, Houston, and Puerto Rico's Electric Power Authority have filed a preliminary application with the US Federal Energy Regulatory Commission to install and operate floating offshore LNG regasification off the southern coast of Puerto Rico.

The Aguirre Offshore GasPort would be about 4 miles offshore Puerto Rico's southern coast, near the town of Salinas. It would provide fuel to the Aguirre Central Complex and would underpin the conversion of power generation from imported oil to natural gas.

The Central Aguirre Power Complex will convert 900 Mw of existing power generation to be dual-fueled, capable of using No. 2 diesel or natural gas or both as primary fuel.

Excelerate's proprietary dockside LNG receiving terminal technology—GasPort—is a shoreside application, says the company's web site, that takes about 12 months from "investment decision to operation" to install.

GasPort incorporates a jetty-mounted, articulated, high-pressure gas-offloading arm and uses Excelerate's Energy Bridge floating storage and regasification unit (FSRU) to vaporize LNG into natural gas for market. A specialized, purpose-built FSRU, moored at GasPort, can deliver regasified LNG at pipeline pressure at 50-800 MMcfd.

Excelerate and Puerto Rico's power authority said they anticipate FERC to issue a draft environmental impact statement in third-quarter 2013 and a final EIS in early 2014. Pending FERC approval, the facility will be in service in early-2015.

Contracts awarded for Zeebrugge terminal expansion

Fluxys LNG NV/SA has awarded a turnkey project for expanding the LNG terminal in the Zeebrugge Port to TS LNG, a joint venture between Sener and Techint E&C.

The project will add a second jetty, enabling the terminal to increase capacity and further develop its role as a hub for supplying LNG as fuel for ships and long-haul trucks, said the companies' announcement. When construction is completed by 2015, the terminal will be able to load and unload an additional 14,000 cu m/hr.

The last expansion of the 25-year-old terminal started up in 2008, expanding the terminal to 9 billion cu m/year from its original 4.5 billion cu m/year (OGJ Online, Aug. 2, 2004).

For the current project, TS LNG will carry out all activities and be in charge of project management, procurement, construction, and commissioning management.

Canada publishes onshore pipeline regulations

Canada's National Energy Board has published amendments to its existing regulations for onshore pipelines.

The amendments clarify requirements for federally regulated pipelines regarding management systems, with the purpose of protecting the public, workers, and the environment, according to NEB.

NEB requires pipeline companies to anticipate, prevent, manage, and mitigate potentially dangerous conditions associated with their pipelines. When implemented, the new requirements can effectively manage risk and promote safe pipeline operation, NEB said.

The regulations make it clear management systems must apply to key company programs for safety, pipeline integrity, security, environmental protection, and emergency management, according to NEB. They also require these systems be in place through each phase of the pipeline's lifecycle; from design, materials, construction, and operation all the way through to abandonment.