EPA extends GHG reporting deadline beyond Mar. 31
The US Environmental Protection Agency extended the deadline for initial reporting of greenhouse gas emissions beyond its original Mar. 31 date following extensive conversations with affected industries and other stakeholders. EPA also is in the process of finalizing a user-friendly online electronic reporting program to ensure that requirements are understandable and practical, the agency said on Mar. 1.
The National Petrochemical & Refiners Association applauded EPA's move. "It's a sensible step that will benefit both the American people and businesses across the nation by providing better quality information," NPRA Pres. Charles T. Drevna said.
EPA said it plans to have the final uploading tool for GHG reporting available this summer, with the data scheduled to be published later this year. The extension will let EPA further test the system plants will use to submit data and give industries a chance to test the tool, provide feedback, and have enough time to become familiar with it prior to actual reporting, it said.
"Taking a little extra time to get this program right makes more sense than rushing to meet an artificial and inflexible deadline," NPRA's Drevna said. "Our members have been working for several years to develop an accurate greenhouse gas database for their refineries and petrochemical manufacturing facilities, and we recognize the need for a quality reporting program."
EPA said it will provide more details about the intended changes in the next few weeks, and make certain the reporting extension is in effect before the original Mar. 31 deadline. The agency also has been holding hearings with industries which will be affected first by its programs to limit GHG emissions, and was to meet with refiners on Mar. 4.
BLM issues guidance to its field managers
The US Bureau of Land Management issued guidance to its field managers on Feb. 25 describing how the agency will use its land use planning process to help states, communities, Indian tribes, and other stakeholders develop the best ways to manage public land with wilderness characteristics.
The guidance was issued under Secretarial Order 3310, which US Interior Sec. Ken Salazar issued in December. The order restores a policy that was revoked in 2003 as part of an out-of-court settlement between then-Sec. Gale A. Norton, Utah's state government, and other parties. BLM has not had comprehensive, long-term guidance on managing public land with wilderness characteristics since that time, Salazar said when he issued the order.
The policy is "a common sense approach that also makes good economic sense," BLM Director Robert V. Abbey said as he issued it. The order, which some groups consider a de facto setting aside of additional acreage for wilderness, requires BLM to consider all resources on public lands, including wilderness characteristics, in its land use planning. Land with wilderness characteristics provides outstanding recreational opportunities as well as cultural, scientific, historical, and environmental resources, supports of the policy argue.
EPA revamps boiler rules to cut costs
The US Environmental Protection Agency issued revised Clean Air Act standards for boilers and certain incinerators, saying it cut estimated costs by about 50% from the rules that it proposed last year.
EPA estimates its final rules lower the cost of pollution control installation and maintenance by about $1.8 billion/year less than its original proposal. The rules cover toxic emissions from some 13,800 large industrial boilers, including refineries and chemical plants.
The new boiler rule, known as the maximum achievable control technology (MACT) rule, sets standards to reduce air emissions of mercury, organic air toxics, and dioxins (OGJ Online, Feb. 4, 2011).
Howard Feldman, American Petroleum Institute director of science and regulatory policy, said he was reviewing the rule.
"API understands that EPA has finalized work practices for most gas-fired boilers and process heaters," Feldman said. "We continue to believe that this is the appropriate control measure for all low-emitting gas-fired units. API is committed to work with the agency during its reconsideration period."
In response to a September 2009 court order, EPA issued the proposed rules in April 2010, prompting significant public input. EPA made extensive revisions and in December 2010 requested additional time for review. The court granted EPA 30 days, resulting in the Feb. 23 announcement.
Because the final standards significantly differ from the proposals, EPA believes further public review is required. The agency said it will reconsider the final standards under a Clean Air Act process that allows it to seek additional public review and comment to ensure full transparency.
Perla gas in place hiked to more than 16 tcf
Eni SPA and Repsol-YPF SA have hiked the estimate of gas in place at supergiant Perla gas-condensate field in the Gulf of Venezuela to more than 16 tcf from the previous estimate of more than 14 tcf.
The companies have finalized front-end engineering design for a 300 MMscfd early production phase targeted to start up in 2013 (OGJ Online, Nov. 15, 2010).
The most recent appraisal well, Perla-4, tested at 17 MMscfd of gas and 560 b/d of condensate. The well is in 60 m of water on the Cardon IV block.
Four light offshore platforms would be linked by pipeline to a central processing facility (CPF) on the Paria Peninsula. Full phase development would involve additional wells and an upgrade of the CPF to 1.2 bscfd.
Eni said, "Early assessments indicate capacity for Perla gas commercialization via the domestic market due to gas request for power generation, petrochemical, and heavy oil upgrading projects. However, further options for gas export will also be analyzed, jointly with the government, in order to extract maximum commercial value from the field."
The block is licensed and operated by Cardon IV SA, a joint operating company owned 50-50 by Eni and Repsol-YPF. Petroleos de Venezuela SA owns a 35% back-in right to be exercised in the development phase, and at that time Eni and Repsol-YPF will each hold a 32.5% interest in the project, which will then be jointly operated by the three companies.
Colombia's Rancho Hermoso oil field growing
Canacol Energy Ltd., Calgary, will drill as many as seven development wells starting in late second quarter 2011 in Rancho Hermoso field in the northwestern Llanos basin in Colombia, where its latest development well tested oil from five formations including one new field pay.
The RH 10 well went to a total depth of 10,305 ft and cut 110 ft of net oil pay in Ubaque, Guadalupe, Los Cuervos-Barco, Mirador, and new pay Carbonera C7 formations. Combined production rate totaled 26,286 b/d of oil.
The well previously tested a combined 19,066 b/d of oil from the Ubaque and Guadalupe reservoirs.
Los Cuervos-Barco, with 19 ft of net oil pay with 26% average porosity, stabilized at 6,791 b/d of 34° gravity oil with 28% water cut on an electric submersible pump from perforations at 9,410-25 ft measured depth. Mirador had 9 ft of oil pay with 25% average porosity.
The C7 tried to blow out when perforated at 8,962-74 ft MD. Bull heading brought the well under control in 3 days, after which the formation made 429 b/d of 34° gravity oil with 10% load water cut on an ESP. Formation damage is probable, and the zone is to be properly stimulated and tested in future wells.
The C7 is present and oil-bearing in the majority of the field's wells, and Canacol will formulate a development plan.
The well is to be completed next week in the Ubaque, which tested at 8,122 b/d. RH 10 is the last of a five-well development program begun in mid-2010. The 2011 seven-well program is directed at all reservoirs except C7.
Trinidad and Tobago receives bids on offshore blocks
Trinidad and Tobago received five bids on three blocks in its Deep Water Atlantic Bid Round, which closed Feb. 18.
BP PLC was the sole bidder on Block 14. Three entities bid on Block 23(a): BP PLC, Niko Resources Ltd., and a consortium of BHP Billiton, Repsol-YPF SA, and Total SA. A consortium of BHP and Repsol-YPF was the only bidder for Block 23(b).
The twin-island nation's Minister of Energy and Energy Affairs Carolyn Seepersad-Bachan noted that while 11 blocks were put up for bid, it was not surprising that companies opted for the blocks that they felt were more prospective.
"You will recall that we instituted a nomination process asking companies to nominate blocks for the bid round. On the basis of this we chose to offer a wide range of blocks to cover every eventuality," the energy minister said. "In taking this approach, we offered many more blocks than we would usually do and we recognize no matter how many blocks we offer, companies always cluster around what they perceive to be among the most prospective," she said.
Seepersad-Bachan said more than two thirds of Trinidad and Tobago's acreage has not yet been explored. Most of this acreage lies in the deep water and is frontier acreage, carrying significant risks but high rewards.
She said for this reason, the country reformed its fiscal regime to allow companies the flexibility to arrange their exploration programs to reduce some of this risk. She explained, "Therefore in what is perceived to be the less-prospective blocks, companies may bid a seismic option only. And in the more prospective blocks, the number of wells in the obligatory phase may vary. We have also opted for an open biddable profit-sharing matrix, no signature bonus or carried participation."
However the minister said there were minimum benchmarks for bids and the ministry will not accept bids below this threshold.
She said recent studies have gone a long way in establishing the prospectivity of the deepwater acreage. "The studies have shown that there are significant resources in the deep water, in the billion barrel region, and as with Brazil, the early adopters will benefit."
Drilling & Production — Quick TakesPetrobras starts well test in Campos basin
Petroleo Brazileiro SA (Petrobras) commenced on Feb. 23 an extended well test on the Tracaja presalt reservoir, via well 6-MLL-70, which is in the Campos basin's Marlin Leste field, 124 km off Rio de Janeiro.
Petrobras connected Well 6-MLL-70, which made the oil discovery at a 4,442-m depth in September 2010, to the P-53 floating production, storage, and offloading vessel that also handles production from other wells in the Marlin Leste field that produce oil from non presalt reservoirs.
Initial flow from Well-6-MML-70 was 23,300 b/d.
In December 2010, Petrobras began a similar test at Carimbe also in the presalt cluster in the Caratinga area.
Petrobras submitted the discovery assessment plan for Tracaja to the National Petroleum Agency in 2010. The plan calls for the drilling one or two wells for delineating the accumulation.
In addition to Tracaja and Carimbe, Petrobras has discovered oil in other Campos basin presalt areas and will start an extended well test at Brava (Marlim concession), Aruana, and Oliva (exploration Block BM-C-36) in 2011.
In the northern portion of the Campos basin, off the coast of Espirito Santo, Petrobras has been producing presalt oil from Parque das Baleias since August 2008.
Solar technology supplies steam to EOR project
The world's first commercial thermal enhanced oil recovery project that uses solar steam generators went on line Feb. 24 at Berry Petroleum Co.'s heavy oil 21Z lease in McKittrick, Calif.
Solar house for Berry Petroleum Co.'s heavy oil 21Z lease in McKittrick, Calif. Photo from GlassPoint Solar.
The project incorporates GlassPoint Solar's single transit trough technology, specifically designed for rugged oil field environments. The solar facility uses a glasshouse enclosure to protect and seal the solar mirror from the elements, including dust, dirt, sand, and humidity.
GlassPoint said the protected environment allows for the use of ultralight, low-cost reflective materials.
Other features of its system noted by GlassPoint are:
• Creation of a protected environment, where high-performance, front-surface reflectors are now practical and durable for the first time.
• Automated washing equipment that eliminates manual cleaning and operator intervention, further reducing costs and water use as well as worker health and safety concerns.
• Elimination of multiple light transits through dirty glass, delivering higher real-world optical efficiency than today's other solar systems.
• Efficient land use, offering the highest steam production per acre of any solar technology—five times more steam per acre than solar tower systems.
• Directly raising steam with standard oil field boiler feedwater, eliminating reboilers and expensive deionizing units required by older solar systems.
• Delivery of steam at a constant price for the entire 30-year life of the system.
GlassPoint built the solar unit in less than 6 weeks and estimates that its facililty on the 21Z lease will supply during the day about an average 1 million btu/hr of solar heat and replace 25-80% of the steam generated by gas-fired boilers on the lease.
In a February presentation, Berry Petroleum noted that it acquired the 21Z lease in 2009 and that it considered the development of the lease as a next generation heavy oil project. It said these projects have higher viscosity crude and will require higher steam-oil ratios and tighter spacing than traditional Midway-Sunset developments.
Berry completed a pilot on the 21Z lease in 2010 and has targeted a 50-well development program for the lease in 2011.
Alberta Blackrod SAGD pilot injection nears
BlackPearl Resources Inc., Calgary, plans to inject steam in the second quarter of 2011 at a steam-assisted gravity drainage pilot at Blackrod in Alberta's Athabasca area.
BlackPearl expects pilot results in late 2011 and would apply for a 40,000 b/d commercial development in the 2012 first quarter. The project involves 9° gravity oil in 18-26 m of pay in the Lower Grand Rapids formation on 30,080 net acres (OGJ Online, Mar. 30, 2010).
Since receiving regulatory approval for the pilot last October, BlackPearl has drilled a horizontal well pair and water source, water disposal, observation, and monitoring wells. The company has 100% working interest and is operator of the project.
PROCESSING — Quick TakesPBF unit completes Toledo refinery purchase
Toledo Refining Co. LLC, a wholly owned subsidiary of PBF Holding Co. LLC, has completed its purchase of a 170,000-b/d refinery in Toledo, Ohio, from Sunoco Inc. (OGJ, Dec. 13, 2010, Newsletter). The purchase price was $400 million, half in cash and half in a 2-year note.
The deal also included a participation payment of up to $125 million, based on profitability of the refinery, and sale of inventories. The high-conversion refinery processes mainly light, sweet crudes from the US Midcontinent and Canada.
Oman awards refinery expansion contract
Oman Refineries & Petrochemical Co. let a $40 million contract to CB&I, Houston, for front-end engineering and design and project management at the Sohar refinery.
The project will increase capacity of the refinery to 187,000 b/sd from 116,000 b/sd by installing various clean fuels units and increasing capacity of and debottlenecking existing units, said the CB&I announcement.
Two Chilean refineries due technical services
SGS Industrial Services Chile, Santiago, has been assigned a 2-year contract to provide comprehensive asset integrity management and nondestructive testing services for two oil refineries in Chile.
The company didn't identify the plants. OGJ's annual survey indicates that Chile's state Empresa Nacional de Petroleo operates the country's only three refineries, Anconcagua, Gregorio, and BioBio.
SGS said its role will be to help the client manage the refineries' assets and to ensure their integrity and reliability. The services include inspection of reactors, tanks, certain pipelines and distillation columns, conventional and advanced nondestructive testing (NDT), including vibration analysis for rotary equipment, and rope access services to enable access at different inspection points.
TRANSPORTATION — Quick TakesPetrobras announces third LNG terminal
Petroleo Brasileiro SA (Petrobras) reported it will install a third offshore LNG terminal. The Bahia regasification terminal (TRBA), with capacity to regasify 14 million cu m/day (cmd), will supply natural gas to the state of Bahia, the heaviest consumer of gas among the northeastern Brazilian states.
TRBA will be installed in the Bay of All Saints and interconnect with a pipeline network at two sites: one in the Bahia network, at Candeias, and the other at kilometer 910 on the Cacimbas-Catu pipeline, a section of the Southeast-Northeast Gas Pipeline started up in March 2010.
As part of Brazil's Growth Acceleration Program, Petrobras said, work will begin in March 2012 with completion scheduled for August 2013 under an investment of nearly $425 million.
Currently, Brazil has LNG terminals at Pecem (State of Ceara) with a regasification capacity of 7 million cmd, and in the Guanabara Bay (State of Rio de Janeiro) with capacity of 14 million cmd. When the TRBA terminal comes online in September 2013, Brazil's total regasification capacity will reach 35 million cmd, overtaking the gas imports via pipeline from Bolivia (31 million cmd).
At the Pecem and Guanabara Bay terminals, tankers moor at a two-berth pier and LNG is transferred over cryogenic arms from supply vessel to regasification vessel. At the TRBA terminal, LNG will be transferred directly between vessels using side-by-side docking, which means that the regasification vessel will dock at a single-berth, island-type pier, said the company.
With direct connection to the supply vessel, LNG will be transferred over short hoses or loading arms to the regasification vessel, which will convert LNG back into a vapor. Gas will then be injected into the pipeline network through a 28-in. pipeline that is 49 km long including a 15-km subsea section.
Petrobras noted that currently only two other LNG terminals in the world use this configuration: Bahia Blanca in Argentina and the UAE's Dubai terminal.
KMEP enters Bakken, Eagle Ford rail partnership
Kinder Morgan Energy Partners LP (KMEP) and Watco Cos. LLC will build and operate several rail facilities in key markets for loading and unloading crude oil, along with other commodities and products tied to the oil and gas industry.
The network will include markets such as Dore and Stanley, ND; Stroud, Okla.; and Houston as well as strategic loading facilities in the Eagle Ford shale in South Texas. Each facility will handle large unit train crude volumes along with manifest commodities such as frac sand, pipe, and drilling supplies.
The Dore facility will include Pioneer Oil LLC and have more than 10,000 ft of track in Phase I along with warehousing for inside storage. Watco expects the facility to enter service Sept. 1. Stroud will handle unit train volumes starting Oct. 1, providing customers direct access to Cushing, Okla. KMEP is 50% partner in a new venture building 750,000 bbl of new storage at Cushing (OGJ Online, Mar. 1, 2011).
The other locations are still in design phase and will be operational first-quarter 2012. Burlington Northern Santa Fe Railway Co. will provide rail services for the project. BNSF also is serving Rangeland Energy LLC's North Dakota oil terminal, COLT Connector, set to enter service by December (OGJ Online, Dec. 1, 2010).
Venture to add storage capacity at Cushing
Kinder Morgan Energy Partners LP is investing $25 million for a 50% interest in a tank farm at Cushing, Okla., to which a related joint venture will add storage capacity.
Kinder Morgan formed the JV with Deeprock Energy Resources LLC, the construction manager and terminal operator, and Mercuria Energy Trading Inc., which will remain anchor tenant for the next 5 years with an option to extend.
The JV will build three storage tanks with capacity totaling 750,000 bbl. Capacity of the tank farm now is 1 million bbl. KMEP also entered a development agreement in which it receives an option to participate in future expansions on the remaining 254 acres of Deeprock's undeveloped land.
Partly because crude in storage at Cushing is at nearly capacity levels, West Texas Intermediate crude is trading at an unusually large discount to Brent.
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