GENERAL INTEREST — Quick Takes
IEA revises global 2014 oil demand forecast
The International Energy Agency reported it has revised downward its global oil demand forecast for 2014 since its last report by 200,000 b/d to 92.4 million b/d. IEA said this revision was made "on reduced expectations of economic growth and the weak recent trend."
IEA now projects annual demand growth at 700,000 b/d in 2014, rising to 1.1 million b/d in 2015 "as the macroeconomic backdrop improves."
Global supply, meanwhile, increased by nearly 910,000 b/d in September to 93.8 million b/d, IEA said, on higher output from both members of the Organization of Petroleum Exporting Countries and non-OPEC member countries. Compared with a year earlier, total supply stood 2.8 million b/d higher, as OPEC supply swung back to growth and amplified robust non-OPEC supply gains of 2.1 million b/d. Non-OPEC supply growth is expected to average 1.3 million b/d 2015.
Crude oil output from OPEC surged to a 13-month high in September, IEA said, led by Libya's continued recovery and higher Iraqi flows. "Production rose 415,000 b/d from August to 30.66 million b/d. A weaker demand outlook cut the 'call on OPEC crude and stock change' by 200,000 b/d for 2015 to 29.3 million b/d. The 'call' declines seasonally by 1.5 million b/d from fourth-quarter 2014 to first-quarter 2015," the agency said.
Offshore 'over-bonding' must end, IPAA says
The federal government's system for assuring that oil and gas companies operating offshore have enough capital to remove structures is badly broken, the Independent Petroleum Association of America said in comments submitted to the US Bureau of Ocean Energy Management.
"The federal government (and therefore the American taxpayer) has never yet had to spend a penny to plug old offshore wells or remove production facilities," IPAA said. "But BOEM and its sister agency, the Bureau of Safety and Environmental Enforcement, have acted in the last 4 years to tie up more and more company capital in bonds the government does not need or use."
Current bonding requirements are not just duplicative, but multiplicative, requiring for example that operators provide $80 million in assurance to cover the same $20 million removal operation, IPAA said. "The effect of this action has fallen disproportionately on independent producers," IPAA said.
"Independent oil and gas producers play a unique and critical function in the Outer Continental Shelf, developing 95% of America's oil and gas wells and reinvesting billions of dollars back into the American economy," IPAA Pres. Barry Russell said as the association filed its comments on Nov. 17.
"We encourage BOEM to work with independent producers to rationalize its approach to security, avoid disincentives to offshore investment, and protect the role of independent producers in the OCS," Russell said.
To bring this issue of what IPAA called "over-bonding" to an end, the trade association recommended eight steps to assure that offshore bonds cover actual and imminent structural removal costs, instead of those that are speculative and multiplicative.
ANGA: Focus needed on gas transportation issues
America's Natural Gas Alliance Pres. Martin J. Durbin called for a stronger focus on transportation as he outlined issues that the US gas industry faces following the 2014 midterm elections and heading into 2015.
"We're incredibly prepared for a cold winter after record injections this summer," he told reporters during a Nov. 17 teleconference. "With increased production, high injection rates, and pipeline infrastructure that's being built, natural gas looks as if it's ready for just about anything."
Durbin cited $19 billion in pipelines projects that are slated to come online during 2014, with 57% of these targeted for the US Northeast. "These are critical projects. The issue is not whether we have enough gas, but if we can get it to areas where it's needed," he said.
ANGA broadly would like to see all of these projects move forward, he said, and the alliance will provide education about benefits that would be provided in the Northeast if pipelines are built there.
"It's ironic that New England is close to one of the most prolific gas production regions in the country, but can't seem to get much of its gas," Durbin said, referring to the Marcellus shale in Pennsylvania. "Pipelines seem to be the only way to get it to consumers there aren't extensive storage options around."
ANGA Chief Economist Erica Bowman, who also participated in the teleconference, said, "Several projects have added around 4 bcfd of capacity in the Marcellus region, which would help alleviate price spikes in the New York region this winter."
Regarding LNG exports, Durbin said he was more optimistic than he was previously. "We've seen the [US Department of Energy's national interest review] process move forward," he said. "When it made the change, we thought it was positive but decided to wait and see. So far, it looks as if DOE has moved fairly quickly once applicants complete their [National Environmental Policy Act] reviews and obtain [Federal Energy Regulatory Commission] approvals."
Durbin said it also was positive when US Sen. John Hoeven (R-ND) withdrew his LNG export bill from markup by the Energy and Natural Resources Committee on Nov. 13 after talking with US Sec. of Energy Ernest G. Moniz.
"The outlook is certainly better," he said. "I think it's a sign of the strong bipartisan support in Congress to move this forward."
PAA to buy BridgeTex interest from Oxy for $1.075 billion
Plains All American Pipeline LP (PAA) and Plains GP Holdings LP have signed an agreement with Occidental Petroleum Corp. to purchase Oxy's 50% interest in BridgeTex Pipeline Co. LLC for $1.075 billion.
BridgeTex, a company jointly owned by Oxy and Magellan Midstream Partners LP, owns the BridgeTex Pipeline, a 300,000-b/d crude oil pipeline extending from the Permian basin to the Houston Gulf Coast. The BridgeTex Pipeline began service in September (OGJ Online, Sept. 23, 2014).
The sale of Oxy's interest in BridgeTex includes two transactions: PAA will purchase for $1.075 billion Oxy's interest in the 400-mile northern leg of the BridgeTex pipeline that extends from the Permian basin to East Houston; and Magellan will acquire Oxy's interest in the 40-mile, 24-in. southern leg of the BridgeTex pipeline from Houston to Texas City for $75 million.
Exploration & Development — Quick Takes
Cairn-led JV makes another oil find off Senegal
A well drilled offshore Senegal by a group led by Cairn Energy PLC will be plugged and abandoned following completion of logging operations, and will be appraised next year.
Cairn and its joint-venture partners completed operations on the SNE-1 well, which was drilled to a total depth of 3,000 m in 1,100 m of water 100 km offshore on the Sangomar Offshore block. The well discovered oil in the Upper Clastic target but did not find hydrocarbons in the deeper target of Karstified and fractured Lower Cretaceous shelf carbonates.
Cairn has 40% working interest in three blocks offshore Senegal-Sangomar Deep, Sangomar Offshore, and Rufisque-which cover 7,490 sq km.
Last month Cairn reported making an oil discovery with the FAN-1 exploration well on the Sangomar Deep block (OGJ Online, Oct. 7, 2014).
Cairn's partners in the three blocks are ConocoPhillips 35%, FAR Ltd. 15%, and Senegal state oil concern Petrosen 10%.
Eni signs addendum to extend E&P work in Turkmenistan
Eni SPA has signed an addendum to the production-sharing agreement (PSA) it has with Turkmenistan with respect to the onshore Nebit Dag block in western Turkmenistan.
The addendum extends to February 2032 the duration of the PSA for the block and transfers a 10% stake of Eni's contractor share to Turkmenneft. Eni, which serves as block operator, will keep the remaining 90% interest stake in the PSA.
The agreement, says Eni, will enable further exploration and production investments in Burun and other satellite fields of the Nebit Dag block.
In a separate agreement, Eni and the Turkmen State Agency for Management and Use of Hydrocarbon Resources signed a memorandum to explore the possibility of extending Eni's activities to Turkmenistan's offshore sector of the Caspian Sea.
The addendum was signed by Turkmen State Agency Director Yagshygeldy Kakayev, Turkmenneft Chairman Tachdurdy Begdjanov, and Eni Chief Executive Officer Claudio Descalzi. Also present were Turkmenistan President Gurbanguly Berdimuhamedov and Italian Prime Minister Matteo Renzi.
Eni began operating in Turkmenistan in 2008. These agreements consolidate the company's cooperation with the national authorities and with state company Turkmenneft.
CNOOC makes oil find with Lufeng well
China National Offshore Oil Corp. Ltd. reported what it is calling a midsized oil discovery in the eastern part of the South China Sea.
The Lufeng 14-4-1 discovery well tested a 1,320 b/d of oil. It was drilled and completed at a depth of 4,098 m and encountered oil pay zones with a total thickness of 150 m.
The Lufeng 14-4 structure is in Lufeng Sag in the Pearl River Mouth basin in 145 m of water. CNOOC noted the "huge exploration potential of the Paleogene system" in the basin.
Kitabu-1 well offshore Malaysia is dry
A well designed to test Miocene turbidite sands similar to pay in South Furious 30 oil field 4 km to the south offshore Sabah, Malaysia, is dry.
The local affiliate of operator Lundin Petroleum AB will plug the Kitabu-1 wildcat, which it drilled to planned total depth of 2,270 m on Blocks SB307-308. The company said the targeted reservoir proved to be poor-quality siltstone. There were no hydrocarbon shows (OGJ Online, Oct. 27, 2014).
Lundin reported no plans for subsequent drilling.
Drilling & Production — Quick Takes
Operators report start of Tubular Bells production
Operator Hess Corp. and partner Chevron Corp. reported the start of oil and gas production from their Tubular Bells development in the deepwater Gulf of Mexico. The project is expected to produce 50,000 boe/d from three wells.
Tubular Bells lies 135 miles southeast of New Orleans in 4,300 ft of water in the Mississippi Canyon area. The discovery well was drilled in 2003, and project construction began in October 2011.
The floating production facility, a classic spar hull with traditional three-level topsides, is producing from the Miocene trend. The field has an estimated production life of 25 years.
Interest in the Tubular Bells development is Hess 57.14% and Chevron 42.86%.
"Achieving first oil at Tubular Bells is an important step towards Chevron achieving its production goal of 3.1 million b/d by 2017," said George Kirkland, Chevron vice-chairman and executive vice-president, upstream.
The Chevron-operated Jack-St. Malo project, a large Lower Tertiary development, is scheduled to come online later this year (OGJ Online, Mar. 13, 2014). The company also recently found oil on its Guadalupe prospect in the gulf (OGJ Online, Oct. 23, 2014).
Cenovus gets approvals for Telephone Lake project
Cenovus Energy Inc., Calgary, has received approval from the Alberta Energy Regulator (AER) and the province of Alberta for its wholly owned Telephone Lake thermal oil sands project, 90 km northeast of Fort McMurray in the company's Borealis Region of northern Alberta.
The company filed a regulatory application and environmental impact assessment for Telephone Lake in fourth-quarter 2011.
The steam-assisted gravity drainage (SAGD) project will have an initial production capacity of 90,000 b/d anticipated to be developed in two 45,000 b/d phases. Telephone Lake is expected to eventually have total production capacity of more than 300,000 b/d, with a project life of more than 40 years.
The company has drilled more than 300 stratigraphic test wells on the property over the past 10 years, confirming that the Telephone Lake reservoir has high permeability and a thickness similar to that of Cenovus's existing Christina Lake thermal oil sands project (OGJ Online, Aug. 29, 2013).
Cenovus says it also conducted a dewatering pilot project that was successfully concluded during fourth-quarter 2013, demonstrating the company's ability to remove an underground layer of nonpotable water sitting on top of the oil sands deposit at Telephone Lake.
While dewatering is not essential to development of Telephone Lake, the company believes it will enhance project economics and reduce the impact on the environment.
About 70% of the top water was removed during the dewatering pilot and replaced with compressed air, which Cenovus expects will improve the steam to oil ratio (SOR) of the project.
As of Dec. 31, 2013, the independent qualified reserves evaluator (IQRE) indicated Cenovus's best estimate bitumen economic contingent resources for Telephone Lake at 2.6 billion bbl. Cenovus expects to reclassify a significant portion of these contingent resources to proved plus probable reserves once a development plan is approved by the company. The company expects to make a decision on the timing of development in 2015.
Cenovus is operating two oil sands projects. Christina Lake has a current gross production capacity of 138,000 b/d while Foster Creek's is 150,000 b/d. Expansions continue at both projects.
Construction of Phase A at the company's Narrows Lake project is progressing (OGJ Online, June 1, 2012). Cenovus holds 50% of the three projects with partner ConocoPhillips.
Cenovus is also moving ahead with Phase A of its wholly owned Grand Rapids oil sands project (OGJ Online, Mar. 21, 2014).
PROCESSING — Quick Takes
Westlake lets EP contract for ethylene plant expansion
Westlake Chemical Corp., Houston, has let a contract to Technip for work related to the expansion of ethylene capacity at its Sulphur, La., plant near Lake Charles.
Technip will provide detailed engineering and procurement services to expand the recovery section of Westlake's Petro 1 (P1) ethylene plant at the Sulphur complex, Technip said.
Technip's operating center in Houston will execute the project with support from the company's office in Mumbai, India, the service provider said.
This latest contract follows a series of feasibility studies executed by Technip to help Westlake evaluate expansion options and development of the process design package and front-end engineering design for the project, said Stan Knez, Technip's senior vice-president of process technology.
A value of the contract was not disclosed.
Last month, Westlake Chemical released details on the Lake Charles ethylene capacity expansion plan, at which time it said the expansion, as well as other capital improvements to be included in the project, would require an investment of about $330 million (OGJ Online, Oct. 23, 2014).
The expansion, which is scheduled to be completed late next year or early in 2016, will increase the plant's ethane-based ethylene capacity by about 250 million lb/year, Westlake Chemical said.
The company previously completed an expansion of the Petro 2 (P2) ethylene unit at its Lake Charles complex during first-quarter 2013 (OGJ Online, Sept. 25, 2012).
Westlake Chemical initially announced plans to expand P1 and P2 in April 2011 as part of its strategy to capitalize on low-cost ethane and other light NGLs becoming available as a result of North America's increased shale gas production.
P1 currently has an ethylene production capacity of 567,000 lb/day, while P2 has a capacity of 630,000 lb/day (OGJ, July 7, 2014, p. 90).
TRANSPORTATION — Quick Takes
ETP, Regency plan Permian-to-Mont Belvieu NGL pipeline
Energy Transfer Partners LP and Regency Energy Partners LP, both of Dallas, reported that their joint venture, Lone Star NGL LLC, has received board approval to construct a 533-mile, 24- and 30-in. natural gas liquids pipeline from the Permian basin to Mont Belvieu, Tex.
Separately, the JV also plans to convert Lone Star's existing West Texas 12-in. NGL pipeline into crude oil-condensate service.
The pipeline construction and conversion projects-estimated to cost $1.5-1.8 billion-are expected to be operational by third-quarter 2016 and first-quarter 2017, respectively.
The new pipeline is being built to accommodate Lone Star's contracted NGL transportation volumes that will exceed Lone Star's existing 290,000 b/d of capacity from the Permian basin by 2016. The 24-in. line will initially be sized to transport 375,000 b/d from the Permian basin to Bosque County while the 30-in. line is currently sized to transport 495,000 b/d from Bosque County to Mont Belvieu. The pipelines can be easily expanded to transport additional volumes in the future, the partners said.
Lone Star's existing 12-in. West Texas NGL pipeline extends from the Midland area to the Gulf Coast and will be sized to ship 70,000 b/d to Corsicana, Tex., and 100,000 b/d to Sour Lake, Tex. Lone Star plans to hold an open season for the crude-condensate service at a future date.
Woodside releases draft EIS for Browse LNG project
Woodside Petroleum Ltd. has released its draft environmental impact statement (EIS) for the proposed Browse LNG project offshore Western Australia.
The document reaffirms that a floating LNG (FLNG) development is the most likely and commercially viable option, although it gives no indication of possible production figures. Instead the statement says the FLNG proposal is nearing completion of the "base of design" (BOD) phase.
Woodside says the front-end engineering and design phase will reach completion 12 months after the completion of the BOD phase. This is expected to lead to a final investment decision (FID) with offshore drilling likely to start 2 years after that.
Commissioning of the FLNG facilities would probably happen 5-8 years after a successful FID. The project's production phase would have a 40 to 50-year lifespan.
The Woodside joint venture has submitted applications for the renewal of the retention leases surrounding the three gas fields-Torosa, Brecknock, and Calliance-that make up the project.
As many as three FLNG facilities measuring 488 m long and 78 m wide are planned, each capable of producing 3.9 million tonnes/year of LNG and 17,000-22,000 b/d of condensate. However there also is the possibility of moving one of the FLNG vessels around to different locations on the three targeted fields.
This latter scenario could see two FLNG vessels at Brecknock and Calliance reservoirs for about half the reservoir life, and two facilities at the Torosa reservoir for half that reservoir's life.
Development includes setting up three drill centers at Brecknock and Calliance, with five at Torosa. There would also be construction of the usual other subsea infrastructure, including manifolds, flowlines, umbilicals, risers, and moorings.
A total of 64 production wells are likely.
The project will potential target as much as 11.7 million tpy of LNG and 66,000 b/d of condensate.
The fields have an estimated contingent reserve of 15 tcf of gas and 441 million bbl of condensate. They lie about 425 km north of Broome.
Public comment for the draft EIS will close on Dec. 19.
JV members are Woodside, BP PLC, Japan Australia LNG, and PetroChina.
Freeport LNG nears construction phase
Freeport LNG Expansion LP expects later this month to close on financing and begin construction on the first two trains of its natural gas liquefaction and LNG export facility on Quintana Island near Freeport, Tex.
Financing as well as the start of construction on the third train are expected in next year's second quarter.
The plans follow the denial of pending rehearing requests by the US Federal Energy Regulatory Commission and final authorization from the Department of Energy to export to countries without a free-trade agreement with the US (OGJ Online, Nov. 14, 2014).
Freeport LNG in 2012 let contracts to a joint venture of CB&I Inc. and Zachry Industrial Inc. to construct the initial two trains, which are respectively expected to start operations 45 and 50 months from the start of construction (OGJ Online, Feb. 17, 2012). The third train is expected to be in operation 6 months following the second train.
Each liquefaction train has a nameplate design capacity of 4.64 million tonnes/year. About 13.2 million tpy of the production capacity of the three liquefaction trains has been contracted under use-or-pay liquefaction tolling agreements with Osaka Gas, Chubu Electric, BP Energy Co., Toshiba Corp., and SK E&S LNG LLC.