GENERAL INTEREST — Quick Takes
BLM expands BMP for oil, gas activity
The US Bureau of Land Management announced expanded best management practices (BMP) for oil and gas producers operating on onshore federal lands. The additional BMP aim to increase wildlife protection during exploration and production of onshore federal leases, the US Department of the Interior agency said late last month. The policies also cover geothermal resources, it added.
It said industry leaders and the agency have actively cooperated in recent years to significantly decrease the number of wildlife deaths associated with fluid mineral operations. The new BMP build on this cooperation by establishing a consistent policy approach and set of practices, BLM said.
The BMP focus on open pits and tanks containing freestanding liquid; chemical tank secondary containment; pit, tank, and trench entrapment hazards; open exhaust stacks; and wire exclosure fencing.
BLM said specific mitigation strategies include using closed loop systems or nets for managing fluids, constructing wildlife escape ramps in open excavation operations, and installing screens on all open exhaust stacks to prevent bird and bat entry or nesting.
Also included are strategies that reduce threats to important bird species like the Greater-Sage Grouse and Lesser Prairie-Chicken. For these species, demonstrably effective mitigation measures will utilize fence markings around production facility exclosures to prevent wire collisions near mating areas, according to BLM.
US petroleum demand hits 17-year November low
US petroleum demand remained weak in November, averaging 18.5 million b/d and reaching the lowest level for the month in 17 years, the American Petroleum Institute reported.
Deliveries, which API uses to measure demand, were down 3.3% from November 2011 and 0.2% lower than in October, it said in its latest monthly statistical review.
Gasoline demand, which averaged 8.5 million b/d, modestly fell 0.3% year-to-year, according to API. Distillate fuel oil demand dropped by a bigger percentage—6.3%—to 3.8 million b/d, it said.
"The economy has shown modest improvement—in employment, for example – but the fundamentals of fuel demand fail to indicate a strengthening recovery is imminent," API Chief Economist John C. Felmy said.
"Look at the weakness in distillate deliveries, including ultra-low sulfur diesel fuel, which is critical to shipping just about everything in our economy," he continued. "It was down 4.5% from November last year."
Crude oil and condensate production, meanwhile, climbed 13.3% year-to-year to nearly 6.8 million b/d, API said. Production of natural gas liquids, an increasingly important element of US oil and gas production because of their role as a manufacturing feedstock, rose 1.5% from November 2012 to 2.4 million b/d, it indicated.
Forest Oil selling noncore South Texas assets
Forest Oil Corp., Denver, agreed to sell its South Texas properties, excluding its Eagle Ford shale oil properties, for aftertax cash proceeds of $325 million.
The buyer is a privately owned exploration and production company, Forest said.
Subject to customary closing conditions, the transaction is expected to close by Feb. 15 with an effective date of Jan. 1.
The properties, which produced 66 MMcfed (86% natural gas) during third-quarter 2012, had estimated proved reserves of 272 bcfe (85% natural gas) as of Dec. 31, 2011.
Forest intends to use the proceeds from this divestiture to pay down debt and retains all of its natural gas hedges.
Patrick R. McDonald, president and chief executive officer, said the company is allocating its capital and resources towards core oil and liquids assets in the Texas Panhandle and Eagle Ford.
After the South Texas divestiture closes, liquids will account for 40% of the Forest Oil production. McDonald expects the liquids share of the production mix will increase.
Exploration & Development — Quick Takes
Illinois source rock information to be released
The Illinois State Geological Survey in Champaign, Ill., is preparing to release data related to source rocks and potential source rocks in Illinois that could be of value in developing exploration and development strategies.
The information includes analysis of Devonian New Albany shale and Ordovician strata. The data may include Rock-Eval, x-ray diffraction data, geochemical and geomechanical data, and photographs. The data and reports will be made available on Jan. 10, 2013, and thereafter upon request.
Most of the analyses were conducted by outside laboratories, and the ISGS and University of Illinois cannot attest to the validity or accuracy of the reports. The information is presented "as-is," said Joan Crockett, geologist and petroleum technology transfer coordinator.
Information on hydrocarbon source rock potential can be useful to many individuals and companies, large and small, as they evaluate acreage, consider mineral leasing opportunities, or conduct regional resource assessments.
The recent successes of Ordovician Utica-Point Pleasant liquid hydrocarbon exploration in Ohio, in addition to the interest in the potential in situ oil play in the New Albany shale, has focused interest on Illinois basin exploration.
When a company, student, government agency, or other group samples from the core and cuttings collection at the ISGS, the sampling agreement requires that all data and analyses from the sampling must be provided to the ISGS. Periodically, the information is released to the public.
Harvest to sidetrack two-zone presalt oil find
Harvest Natural Resources Inc. will appraise a two-zone oil discovery in presalt formations at the Dussafu Tortue Marin-1 exploratory well on the Dussafu Marin PSC offshore Gabon.
Harvest, operator of the PSC with a 66.667% interest, drilled to 11,260 ft in the Dentale formation in 380 ft of water.
Log evaluation and pressure data indicate 42 ft of pay in a 72-ft oil column in the Gamba formation and 123 ft of pay in stacked reservoirs in the Dentale formation.
Harvest plans fluid sampling and a sidetrack to appraise the Dentale sands in a structurally superior position and the lateral extent of the Gamba reservoir with a provision for flow testing one or more of the subject pay intervals.
HRT proves Solimoes gas trend south of Jurua
A unit of HRT Participacoes em Petroleo SA, Rio de Janeiro, said an exploratory well in Brazil—s Solimoes basin has confirmed the existence of a new structural trend on the company—s blocks south and southwest of the well.
Drillstem tests of the Jurua formation lower member at the 1-HRT-192/02-AM well on the Tucuma prospect on the SOL-T-192 block 30 km south of Jurua gas field established the presence of gas. HRT tested the prospect to identify hydrocarbons in a faulted anticlinal structure in a regional southwest-northeast oriented structural lineament subparallel to the Jurua and Tefe gas trend.
The well stabilized at 18.4 MMcfd of gas on a 40/64-in. choke on a drillstem test at 2,254-2,260.3 m. It reached a maximum rate of 5 MMcfd on the same size choke on a second drillstem test at 2,208-2,217 m.
When combined with tests at the 1-HRT-5-AM and 1-HRT-9-AM, the results confirm the gas trend to the south and the potential for gas on SOL-T-191 and the SOL-T-192 block to its west. The results also open an exploratory play fairway for the SOL-T-214, SOL-T-215, and SOL-T-216 blocks, south of SOL-T-191. HRT has identified several exploratory prospects on those three blocks.
"The presence of a richer liquid bearing gas-condensate identified in the DSTs in a relatively underexplored area of the basin, reinforces the geological model interpreted for the area, and consolidates the potential for gas in the region and supports the gas monetization project," HRT said.
HRT is the operator of 21 blocks in the Solimoes basin, which it is exploring in co-operation with TNK-Brasil. Each block covers nearly 4 sq km.
Drilling & Production — Quick Takes
ExxonMobil moves ahead with Hebron oil field
ExxonMobil Corp. reported it will develop the Hebron oil field offshore Newfoundland and Labrador using a gravity-based structure that will recover more than 700 million bbl of oil, an increase over earlier estimates.
Hebron lies in 300 ft of water in the Jeanne d—Arc basin more than 200 miles southeast of the capital of St. John—s and 19 miles southeast of ExxonMobil—s Hibernia project. The field will be developed using a stand-alone gravity-based structure consisting of reinforced concrete designed to withstand sea ice, icebergs, and meteorological and oceanographic conditions.
The base will be designed to store 1.2 million bbl of crude oil and will support an integrated topsides deck that includes a living quarters and drilling and production facilities. The platform is being designed to produce 150,000 b/d of oil. Oil production is expected to begin by yearend 2017.
Construction of the gravity-based structure is under way at the project—s primary site in Bull Arm, Newfoundland and Labrador. Topsides fabrication is expected to begin later this year.
"Hebron is one of several large-scale oil developments that ExxonMobil will bring on stream in the next 5 years," said ExxonMobil Development Co. Pres. Neil W. Duffin.
Hebron—s development will provide employment for as many as 3,500 people during construction in the province, ExxonMobil said. The project received regulatory approval from the governments of Canada and Newfoundland and Labrador in May.
ExxonMobil estimates capital costs for the project to reach $14 billion.
Hebron will be operated by ExxonMobil affiliate ExxonMobil Canada Properties, which holds 36% equity in the project. Other Hebron partners are Chevron Canada Ltd. 26.7%, Suncor Energy Inc. 22.7%, Statoil Canada 9.7%, and Nalcor Energy Oil & Gas 4.9%.
Skarv production begins offshore Norway
BP Norway and partners have started production from Skarv oil and natural gas field in 350-450 m of water in the Norwegian Sea.
Production is expected to rise to 125,000 boe/d within 6 months and peak at 165,000 boe/d by yearend.
Development involved the drilling of 16 wells drilled through five subsea templates.
Produced fluids move through a floating production, storage, and offloading vessel built for harsh waters. The FPSO can handle 85,000 b/d of oil and 670 MMscfd of gas and store 875,000 bbl of oil.
Shuttle tankers carry away the oil. Gas moves through a new 80-km, 26-in. spur line to the Asgard Transport System.
BP estimates ultimate recovery of 100 million bbl of oil and condensate and more than 1.5 tcf of rich gas. It expects Skarv to serve as a production hub.
According to the Norwegian Petroleum Directorate, the field holds gas and condensate in Middle and Lower Jurassic sandstones in the Garn, Ile, and Tilje formations, with an underlying oil zone in the Skarv deposit in Garne and Tilje. Reservoir quality is good in Garn and relatively poor in Tilje. The reservoirs, faulted in several places, lie at 3,300-3,700 m.
BP, operator, holds a 23.84% interest. Other interests are held by Statoil 36.17%, E.On E&P Norway 28.08%, and PGNiG Norway 11.92%.
Aasta Hansteen, pipeline plans submitted
Statoil and partners have submitted plans for development of deepwater Aasta Hansteen natural gas and condensate field offshore Norway and for an affiliated pipeline that will make further exploration and development possible in the northern Norwegian Sea (OGJ Online, July 13, 2012).
Statoil filed the plan for development and operation of the field with the Ministry of Petroleum and Energy. It will install a spar platform in 1,300 m of water in the first use of the design on the Norwegian continental shelf.
The field, 300 km from land, is expected to start producing in third-quarter 2017. Plateau production will be 130,000 boe/d from a reserves estimated at 47 billion standard cu m of gas. Statoil, operator, holds a 75% interest. Other field interests are OMV 15% and ConocoPhillips 10%.
Statoil and its partners in the Polarled Development Project also have filed the plan for installation and operation of a 480-km, 36-in. gas pipeline from Aasta Hansteen field to processing facilities at Nyhamna. Polarled previously was called Norwegian Sea Gas Infrastructure.
The pipeline will be capable of delivering 70 million standard cu m/day to Nyhamna. It will have a 30-km, 18-in. branch to the Kristin platform connecting Polarled with the Aasgard Transport System.
Other possible field tie-ins include Linnorm, via the Draugen platform, and Zidane, via Heidrun. Two further branches, of 60 km and 173 km, are possible south of Aasta Hansteen, Statoil said.
Statoil—s partners in the Polarled project are Petoro, OMV, Shell, Total, RWE Dea, ConocoPhillips, Edison, Maersk Oil, GDF Suez, and Gassco.
PROCESSING — Quick Takes
Tesoro to cease refining in Hawaii
Tesoro Corp. will halt refining at its 93,700-b/cd Kapolei refinery in Hawaii after a year-long effort to sell the facility proved unsuccessful (OGJ Online, Jan. 11, 2012).
The company will convert Kapolei refinery to an import, storage, and distribution terminal and continue trying to sell it.
It expects to realize $300-350 million in cash by the end of 2013 from reduced working capital related to the conversion.
Tesoro bought the refinery, about 20 miles west of Honolulu, in 1998 from BHP Petroleum Americas Refining Inc.
In its announcement of the attempt to sell the refinery last year, the company said it wanted to concentrate on the US Midcontinent and West Coast (OGJ Online, Jan. 22, 2012).
Tesoro operates six other refineries.
Hawaii—s only other refinery also is at Kapolei, operated by Chevron Corp. with crude capacity of 54,000 b/cd.
EPP PDH unit full; second unit being considered
Enterprise Products Partners LP (EPP), Houston, reported it has executed long-term, fee-based agreements that effectively sell out its 1.65 billion lb/year propane dehydrogenation (PDH) plant scheduled to begin operating in third-quarter 2015.
Anticipating continued decrease in propylene supplies, EPP is discussing with more customers the development of additional PDH capacity.
Last year EPP announced plans to build a PDH plant that would consume as much as 35,000 b/d of propane to produce 1.65 billion lb/year of polymer-grade propylene (OGJ Online, June 21, 2012).
The plant will be integrated with EPP—s existing propylene fractionation that has a capacity of 5.3 billion lb/year. The PDH plant will also be integrated with EPP—s PGP storage, 102-mile distribution pipeline system, and export terminal.
A.J. Teague, EPP—s executive vice-president and chief operating officer, noted that demand is being driven by the combination of a 38% decrease in propylene supplies since 2006 due to additional ethane consumption by US petrochemical companies and the growing supplies of US propane from the nation—s shale plays.
"We are continuing our discussions with several customers that could lead to a second PDH unit or additional propylene manufacturing capacity," Teague said.
Australian gas plant awards EPC contract
Esso Australia Resources Pty Ltd., Melbourne, last month awarded a $550 contract to CB&I, Houston, for work at Esso—s Longford, Victoria, gas plant.
The contract—s scope of includes engineering, procurement, fabrication, and construction of the 400-MMcfd Longford gas conditioning plant, which will receive production from Kipper, Tuna, and Turrum fields in the Bass Strait of southeast Australia.
TRANSPORTATION — Quick Takes
AOPL asks FERC to protect construction financing
The Association of Oil Pipelines (AOPL) asked the US Federal Energy Regulatory Commission on Jan. 7 to fix a developing dispute that the trade association says threatens pipelines— ability to get financing for new construction.
"Literally billions of dollars of energy infrastructure project investment vital to new domestic supplies and lower prices is threatened if FERC does not act to protect the ability of project sponsors to finance their projects based on committed rate contracts," AOPL Pres. Andrew J. Black said on Jan. 9.
Financing new pipeline construction depends upon a guaranteed stream of revenue based on rates charged for using the pipeline, Black explained. Shippers and pipeline operators enter into contracts to deliver crude oil, gasoline, diesel and other products at agreed upon rates, he said.
"These committed rate agreements give confidence to shippers that the infrastructure they need to deliver their production to market will be there when they need it," Black said, adding, "They also give confidence to companies and investors ready to fund new pipeline projects that their investments will be repaid."
Unfortunately, FERC staff testimony in a pending pipeline rate case could undercut this financing method by threatening to void mutually beneficial rate contracts agreed to by energy shippers and pipeline operators, according to AOPL.
It filed a motion to interview and comments on Jan. 7 supporting a petition Seaway Pipeline, which extends from Cushing, Okla., to Houston, filed on Dec. 12, 2012, asking FERC to confirm that agreed contract rates are not subject to review in the pipeline—s pending rate proceeding.
FERC—s staff recommended a different rate and rate structure which would retroactively throw out agreements on which private financing depends, AOPL said. It urged FERC to act quickly because pipeline operators and shippers could be deterred from starting new projects or moving forward on current construction based on existing contracts and rates.
Phillips 66 to move Bakken crude by rail to Bayway
Phillips 66 signed a 5-year contract with Global Partners LP under which Global will use its rail loading, logistics, and transportation network to deliver crude oil from the Bakken formation of North Dakota to the Phillips 66 Bayway refinery in New Jersey.
"This is one of several commitments to transportation infrastructure Phillips 66 has made that tie directly to its strategy of delivering advantaged crude oil to the company—s US refineries," Phillips 66 said.
The take-or-pay contract calls for Phillips 66 to transport 91 million bbl of crude oil, or about 50,000 b/d, over the contract term. Cost was not disclosed.
The Bayway refinery at Linden, NJ, can process 237,500 b/cd. Global Partners is a transportation company.
Southern Pacific shipping dilbit by rail
Southern Pacific Resources Corp. (SPRC) said rail shipments have begun of diluted bitumen (dilbit) produced at its STP-McKay thermal oil sands project in Alberta to a terminal in Mississippi as production at the project ramps up (OGJ Online, Oct. 11, 2012).
The first shipment of dilbit left the Lynton terminal south of Fort McMurray on Dec. 22, 2012, and arrived in Mississippi on Jan. 6 for offloading at the Genesis Natchez terminal, where Southern Terminal has exclusive capacity. With steady shipments under way, the company plans to build storage before starting sales to Gulf Coast refiners at the end of January.
While developing the rail transport program last year, SPRC said the system would provide pricing advantages and lower diluent requirements (OGJ Online, July 16, 2012).
Average December 2012 production at the STP-McKay project, 45 km northwest of Fort McMurray, was estimated at 1,200 b/d of bitumen, up 22% from the previous month. Production began in mid-October and is expected to reach 12,000 b/d.
SPRC said it is converting steam-assisted gravity drainage well pairs from steam circulation to production cautiously to assure long-term integrity of wellbores and optimize recovery. So far it has converted seven of 12 wellbores to production. Others are in various stages of circulation.
The firm has begun drilling exploratory coreholes to delineate land north of the project area. It expects to have drilled 10-13 holes by mid-March. Depending on results, SPRC said, the program might support additional expansion or be integrated with planned expansions for which it has applied for regulatory approval. Those project are a 6,000-b/d expansion of the first phase and an 18,000-b/d second phase.
Correction boxThere were some incorrect figures in the Dec. 3, 2012, OGJ Refining Survey. All capacities are in b/cd, unless otherwise noted. The correct figures for Phillips 66 Los Angeles refinery are: delayed coking, 48,150; catalytic reforming, 34,000; kerosine/jet, 11,250; diesel, 28,800; alkylation, 14,400; isomerization C4 feed, 8,550; isomerization C5 feed, 12,500; and steam methane reforming, 100 MMcfd. The correct figures for Phillips 66 Billings refinery are: crude capacity, 59,000; other distillates, 50,000; coke, 900 t/d; and sulfur, 200 t/d. The correct figures for Phillips 66 Whitegate refinery are: diesel, 26,000; other distillates, 9,000; and sulfur, 0 t/d. Finally, Marathon—s Detroit refinery—s correct delayed coking figure is 28,000. |
