BOEMRE approves Shell's deepwater exploration plan
The US Bureau of Ocean Energy Management, Regulation, and Enforcement approved an exploration plan submitted by Shell Offshore Inc. for three exploratory wells about 130 miles off Louisiana.
It was the first deepwater exploration plan approved in the Gulf of Mexico since the Macondo well accident and subsequent crude oil spill last year, BOEMRE said on Mar. 21.
The agency said that the new plan for three wells in 2,950 ft of water supplements one from 1985 that was approved for the lease in Shell's Auger field.
BOEMRE prepared a supplemental environmental assessment to examine Shell's proposed exploration activities in accordance with new regulations.
The review found no evidence that the proposed activity would significantly affect the quality of the human environment. It then determined that a new environmental impact statement would not be required, and issued a finding of no significant impact, which led to the supplemental exploration plan's approval.
"The successful completion of this environmental assessment, and the resulting approval of Shell's exploration plan, unmistakably demonstrates that oil and gas exploration can continue responsibly in deep water," said BOEMRE Director Michael R. Bromwich. "Shell's submission has satisfied the heightened environmental standards that we are now applying and I am confident that other operators can satisfy the same standards."
National Ocean Industries Association President Randall B. Luthi said, "This decision is a huge first step in a process which we hope will successfully lead to new operations and a rapid return to work for the thousands of people employed by our member companies."
BOEMRE's fourth permit first with MWCC system
Also last week, BOEMRE approved the fourth deepwater exploration permit under its new regulatory regime, and the first to use the Marine Well Containment Co.'s system. The revised permit is for ExxonMobil Corp.'s Well No. 3 on Keathley Canyon Block 919 in 6,941 ft of water 240 miles off Louisiana.
Well No. 3 is new, BOEMRE said on Mar. 22. ExxonMobil had a rig at the location and an approved drilling permit for a new well when it suspended operations during the drilling moratoriums that followed the Macondo well accident on Apr. 20, 2010, and subsequent massive crude oil spill into the Gulf of Mexico.
ExxonMobil confirmed it had received a permit for the well, which is also known as Hadrian North, and said it has a newly built, state-of-the-art rig, the Maersk Developer, standing by. "We support BOEMRE's efforts to restart safe drilling in the gulf so that tens of thousands of Americans can return to work," a spokesman told OGJ in an e-mail message.
BOEMRE Director Michael R. Bromwich said, "As we have seen, the rate of deepwater permit applications is increasing, which reflects growing confidence in the industry that it understands and can comply with the applicable requirements, including the containment requirement. We expect additional permit approvals in the near future."
BOEMRE said ExxonMobil contracted with MWCC to use its capping stack to stop oil flowing during a well control event. BOEMRE said it reviewed the operator's containment capability for the specific well proposed in the permit application and confirmed that the capping stack met requirements specific to the well's characteristics.
The deepwater permit was the first using technology developed by MWCC, which ExxonMobil, Chevron Corp., and ConocoPhillips formed as it became apparent that existing offshore spill control systems were inadequate to capture and contain crude leaking from the Macondo well last summer. The consortium's other members include BP PLC, the Macondo well's operator; Anadarko Petroleum Corp., which had an interest in it; and Apache Deepwater LLC.
Buckeye to buy BP terminals, pipelines
Buckeye Partners LP agreed to acquire 33 refined products terminals and 1,000 miles of pipelines in the US from BP Products North America Inc. and its affiliates for $225 million. The transaction includes BP's 50% interest in Inland Corp., a pipeline joint venture in Ohio.
Closing, subject to regulatory approvals and other conditions, is expected in the second quarter. Buckeye's proposed acquisition of BP's interest in Inland, which represents $60 million of the total price, is subject to Inland's other shareholders' existing rights of first refusal. Other stakeholders are Shell Oil Co., Sun Pipeline Co., and Midwest Pipeline Holding LLC.
Regarding the total transaction, Buckeye said the 33 terminals that it's buying have total storage capacity exceeding 10 million bbl. The terminal and pipelines are in the US Midwest, Southeast, and West.
Buckeye Partners is a publicly traded partnership that owns and operates an independent refined petroleum products pipeline system. It own 5,400 miles of pipeline and owns 69 liquid petroleum products terminals with aggregate storage capacity of 53 million bbl. In addition, Buckeye operates 2,600 miles of pipeline for major oil and chemical companies.
BP is selling assets to help pay for the Gulf of Mexico oil spill, which resulted from the Macondo well blowout in 5,000 ft of water off Louisiana in April 2010. An explosion and fire on Transocean Ltd.'s Deepwater Horizon killed 11 crew members.
Ability to acquire more low-noise seismic data proved
Royal Dutch Shell PLC and HP claimed a breakthrough in the capability of jointly developed inertial sensing technology to shoot and record seismic data at much higher sensitivity and at ultralow frequencies.
The onshore wireless seismic acquisition system is designed to provide a clearer understanding of the earth's subsurface, thus increasing prospects for discovering greater quantities of oil and gas.
The sensing technology has been demonstrated to have a noise floor—a measure of the smallest detectable acceleration over a range of frequencies—of 10 nano-g/sq root Hertz (ng/rtHz), which is equal to the noise created by ocean waves at the quietest locations on earth as defined by the Peterson Low Noise Model. The tests were conducted in the seismic testing vault at the US Geological Survey's Albuquerque Seismological Laboratory facility.
Dirk Smit, Shell chief scientist for geophysics and vice-president of exploration technology, said, "Responding to the energy challenge, the oil and gas industry is tackling ever-deeper and more complex reservoirs, as well as reservoirs in very tight rock systems. In particular, for onshore settings, this requires enhanced quality seismic data as well as the cost-efficient, flexible deployment of seismic sensor networks. The collaboration with HP demonstrates Shell's strategic approach to driving innovative technology solutions through active partnering."
Rich Duncombe, senior strategist, Technology Development Organization, Imaging and Printing Group (IPG), HP, said, "This new sensing milestone is the latest step in the collaboration between HP and Shell, which is on track to produce a leap forward in onshore seismic data quality to improve the exploration risk evaluation and decisions, illustrating the industry-wide benefits that can be achieved through cross-company innovation."
At the test facility, HP was able to compare the seismic response of the new sensor side by side with a USGS reference sensor when an earthquake occurred in the Gulf of California during the test period. The signal from the reference sensor was matched by the new sensor down to 25 mHz, verifying the sensor's response at low frequencies.
The seismic system uses the breadth of HP's technology development capabilities as well as Shell's advanced geophysical expertise in seismic data acquisition systems and operations. As such, this collaboration builds on the core strengths of each company to advance technology in this field.
The system will be delivered by HP Enterprise Services and IPG. It is based in part on the high-performance sensing technology originally codeveloped by HP Labs, the company's central research arm, along with IPG and Shell research in seismic network design.
Woodside, Apache make gas finds off W. Australia
Woodside Petroleum and Apache Energy have had separate successes with natural gas discoveries off Western Australia.
Woodside announced a natural gas discovery in its Martin-1 wildcat in its wholly owned permit WA-404-P in the Carnarvon basin.
Wireline logs confirmed the well had intersected 100 m of gross pay within the Triassic-age target reservoir following the recovery of gas samples and the establishment of a gas pressure gradient.
Martin-1 lies within 14 km of the company's earlier gas discoveries at Martell-1, Noblige-1, Larsen-1, Larsen Deep-1 and Remy-1, all of which add to Woodside's total gas reserves earmarked to support expansion of the Pluto LNG project.
Meanwhile, in permit WA-290-P, Apache continues to find gas zones in its already successful Zola-1 wildcat.
The company says the well has now intersected a total of 100 m thickness of gas-bearing sands. The resource could total 1-2 tcf of gas.
The gas is contained in three thick Mungaroo formation channel sands, but it is too early to determine whether these are discreet individual sands or one single accumulation.
Zola prospect is a tilted horst block on trend with the Gorgon gas field.
Apache, operator, holds 30.25% interest in WA-290-P Partners include OMV AG 20%, Santos Ltd. 24.75%, Nippon Oil Exploration 15%, and Tap Oil Ltd. 10%.
Drilling & Production — Quick TakesAnadarko, KNOC plan Eagle Ford joint venture
Anadarko Petroleum Corp. and a subsidiary of Korea National Oil Corp. agreed to form a joint venture in the liquids-rich Eagle Ford shale.
KNOC will invest $1.55 billion in the form of a carry for about one-third of Anadarko's Maverick basin assets in South Texas.
The carry will finance 100% of Anadarko's 2011 post-closing capital costs in the basin and up to 90% of the costs after that until the carry is exhausted, expected by yearend 2013.
National oil companies, international oil companies, and others are investing in US shale gas plays in an accelerating trend (OGJ, Feb. 28, 2011, p. 18).
Anadarko President and Chief Operating Officer Al Walker said the transaction involves acreage in the play's higher-margin condensate window.
KNOC also will reimburse Anadarko for net cash outflows, relative to acquired interest, subsequent to the effective date of Jan. 1, 2011. These costs are expected to be $50 million.
In exchange, KNOC will receive 80,000 net acres in the Eagle Ford and 16,000 additional prospective net acres for the deeper dry-gas Pearsall shale and Pearsall opportunities underlying the Eagle Ford acreage
KNOC may also elect, no later than 30 days post-closing, to participate as a partner with a 25% working interest in associated gathering systems and facilities.
Anadarko plans to boost the number of rigs working in the Eagle Ford shale to 10 from 9 early in the second quarter.
Three Iraqi oil fields sought for development
San Leon Energy PLC and its joint venture partner Iraq Al Meinaa Oil Services Co. signed a joint participation agreement with the Governorate Council of Karbala in central Iraq.
San Leon, Al Meinaa, and the governorate will submit a joint proposal to the Iraq Ministry of Oil to develop Kifl, West Kifl, and Merjan oil fields south of Baghdad under a production-sharing contract. Formal negotiations are to start soon.
San Leon Energy said the project could recover an estimated 600 million bbl of oil. There was no indication when production might begin.
The three fields are on northwest-southeast trending structures in an area known as Middle Furat. Merjan is 2.5 by 2 km, West Kifl is 10 by 8 km, and Kifl is 5 by 1.5 km. Oil has been tested in three Cretaceous reservoirs and one Jurassic reservoir, while strong oil shows were observed in one Triassic reservoir.
Kifl was discovered in 1960, Merjan in 1983, and West Kifl in 1987. Six wells have been drilled in the Middle Furat Fields Contract Area: four in Kifl, one in Merjan, and one in West Kifl. Wells in each of the three fields have been drilled below the Cretaceous to Jurassic/Triassic in Kifl, to Jurassic in Merjan, and to Permian in West Kifl. Iraq had offered the three fields in its second license round (OGJ Online, Dec. 31, 2008).
Two Idaho gas-condensate fields to be developed
The first commercial hydrocarbon finds in Idaho are about to be developed. Willow and Hamilton gas-condensate fields in Payette County were discovered in 2010 and appraised by six wells, said 50-50 partners Bridge Resources Corp. and Paramax Resources Ltd., both of Calgary (OGJ Online, Oct. 22, 2010).
Talks are under way with Northwest Pipeline for the installation of a meter station to connect the fields to its interstate transmission system, providing access to customers in Idaho and the Pacific Northwest. Bitter Creek Pipeline, LLC, a subsidiary of MDU Resources Group, has begun design and permitting for the installation of the pipelines and the midstream facilities upstream of the meter station.
Design and planning of the pending stimulation of the four additional Hamilton wells to determine well production rates and optimal pipeline size is complete. These are very small fracs to clean-up highly porous conventional sand reservoirs. The stimulation program is subject to state approval of fracing parameters, which is expected in April, and on availability of equipment to be contracted once approval is received.
In addition to the work at Hamilton field, planning and design of the installation of the facilities and the 8½-mile pipeline to tie-in Willow field has started.
PROCESSING — Quick TakesPearl GTL receives first gas
Qatar Petroleum and Royal Dutch Shell PLC announced the first flow of dedicated offshore natural gas to the Pearl gas-to-liquids plant in Ras Laffan Industrial City north of Doha.
Full start-up of the plant later this year will expand an exclusive list: There are only three other operating GTL plants in the world: South Africa (160,000 b/cd Sasol, 22,500 b/cd PetroSA); Qatar (34,000 b/cd Sasol-Qatar Petroleum Oryx), and Malaysia (Bintulu, Shell Malaysia, 14,700 b/d).
Operator of Pearl, which has been developed under a production-sharing agreement with QP, Shell opened offshore gas wells to flow through twinned 60-km, 30-in. sour-gas subsea pipelines into the plant. Sections of the plant will be started up progressively over the coming months, said the announcement.
Launched in July 2006 for a total of about $19 billion, the entire Pearl GTL project is the largest energy project in terms of investment ever launched in Qatar, said Shell. It includes two offshore platforms in North field.
Once fully operating, Pearl will produce 1.6 bcfd, which will generate 120,000 b/d of condensate and NGLs and 140,000 b/d of products, such as gas oil, high-specification lubricant base oils, and chemical feedstock.
The gas-separation process at the plant removes metals and sulfur, turning the sulfur into pellets and shipping it to the nearest market to make hydrosulfuric acid, fertilizer, or other products, according to other information released by Shell.
Anadarko to buy BP Wattenberg gas plant
Anadarko Petroleum Corp. will buy BP America Production Co.'s 93% interest in the Wattenberg processing plant in northeastern Colorado for $575.5 million, closing by midyear.
The 195 MMcfd plant in Adams County can extract 15,000 b/d of natural gas liquids and condensate. Anadarko, which provides 70% of current throughput, will operate the plant with 100% ownership. Anadarko is Wattenberg field's largest producer with sales of 63,000 boe/d.
"Our early efforts in the emerging horizontal Niobrara play are very encouraging. With the anticipated growth in the DJ basin, we expect this acquisition to improve field recoveries, allow for future expansion and capture efficiencies that enable us to reduce operating expenses," Anadarko said.
"The Wattenberg Plant, when combined with Western Gas Partners LP's ownership position in the Fort Lupton plant and the recently acquired Platte Valley Plant, gives Anadarko and other area producers exceptional midstream options for development within the Wattenberg field and growth in the greater DJ Basin. Given our flexibility to offer this asset to WGP, it is possible that we will recapture the initial and subsequent capital investments in the future, while continuing to benefit from operational improvements in the basin," Anadarko added.
Anadarko has 900,000 net acres in the DJ basin, where it expects to be running nine operated rigs, including three horizontal rigs, by the end of March.
Tesoro to expand North Dakota refinery
Tesoro Corp. will expand crude capacity of its 58,000-b/d refinery at Mandan, ND, to 68,000 b/d to handle oil from the Bakken shale and elsewhere in the Williston basin. The company expects to invest about $35 million in the expansion.
"Tesoro expects to supply the plant with additional crude oil from the burgeoning crude oil production in the nearby Bakken shale/Williston basin area via the Tesoro High Plains Pipeline system," the company said in a statement.
Processing capacities at the refinery include 25,700 b/d of fluid cat cracking and 11,500 b/d of cyclic cat reforming. Average throughput over the past 3 years has been 52,000 b/d.
Uinta basin cat cracker project taking shape
The Uinta basin's high pour point crudes may soon get a processing unit in the Vernal, Utah, area that would increase netbacks to producers and improve air quality in the federal attainment area. Uintah Partners LLC, Park City, Utah, plans to start construction within 12 months of a cat cracker and associated units at a site 10 miles south of Fort Duchesne. There was no firm indication when the plant might start up.
The 40,000 b/d unit would upgrade yellow and black wax crudes from numerous fields in the basin and could be expanded to 90,000 b/d if successful. The integrated project also involves talks with numerous producing and transportation entities that could result in the shift of large volumes of produced and upgraded oil to pipeline shipment and away from trucks.
Producers are drilling hundreds of oil wells per year in Monument Butte, Altamont, Brundage Canyon, and other fields (OGJ, Jan. 3, 2011, p. 47). Much of the upgraded crude would go by pipeline to North Salt Lake City refiners, which are at or near capacity, and Uintah Partners is exploring other pipeline links and markets for the burgeoning production.
Aramco, PetroChina sign MOU for refinery
Aramco Overseas Co. BV and PetroChina Co. Ltd. have signed a memorandum of understanding for joint development of a 200,000-b/d grassroots refinery in Yunnan Province in far southwestern China.
The high-conversion refinery would process Arabian crude oil and yield products including ultralow-sulfur gasoline and diesel meeting Chinese specifications. Under a long-term contract, Aramco would supply as much as all the crude needed by the refinery.
TRANSPORTATION — Quick TakesMidstream JV to spend nearly $2 billion for assets
Energy Transfer Partners LP and Regency Energy Partners LP, both of Dallas, have formed a joint venture to buy LDH Energy Asset Holdings LLC from Louis Dreyfus Highbridge Energy LLC for $1.925 billion.
LDH owns and operates NGL storage, fractionation, and transportation. The storage is mostly at Mont Belvieu, Tex. Its 1,066-mile, 144,000-b/d intrastate West Texas pipeline moves NGLs from the Permian basin through the Barnett shale production area and terminates at Mont Belvieu storage and fractionation. LDH also owns and operates 25,000-b/d fractionation and processing in Louisiana.
At the sale's closing, ETP will contribute $1.35 billion in exchange for a 70% interest in the venture, while Regency will contribute $578 million for a 30% interest. The acquisition will close in this year's second quarter.
The JV will be managed by a two-person board of directors, with ETP and Regency each appointing one director. ETP will operate the assets on behalf of the JV with existing LDH employees.
Mike Bradley, president and chief executive officer of Regency, said Louis Dreyfus will remain a customer of LDH.
Enterprise signs 10-year Eagle Ford transport deal
Enterprise Products Partners LP has entered into a 10-year agreement with two producers in the Eagle Ford shale play of South Texas to provide 50,000 b/d of firm oil transportation and marketing services on its 140-mile, 24-in. OD oil pipeline now under construction. The agreement is a single contract between Enterprise and the two producers and brings the pipeline to more than 175,000 b/d of its 350,000 b/d capacity.
EPP has previous Eagle Ford crude delivery agreements in place with EOG Resources Inc., Pioneer Natural Resources USA Inc., Reliance Eagleford Upstream Holding LP, and Newpek LLC. EPP expects the line to enter service second-quarter 2012, supplying a new Houston-area oil terminal the company is currently building. The second-quarter timing is a one-quarter delay from the first-quarter 2012 start-up initially predicted by Enterprise (OGJ Online, Sept. 13, 2010).
About 150 rigs are presently working in the Eagle Ford shale, according to Enterprise, which have drilled more than 500 wells. Current production from the play equals roughly 80,000 b/d of crude oil and condensate, Enterprise says.
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