GENERAL INTEREST — Quick Takes
Relief well likely to intercept Macondo soon
Crews drilling a relief well to intercept the deepwater Macondo well in the Gulf of Mexico have started the last drilling leg, and the relief well is expected to intercept Macondo on Sept. 16, National Incident Commander and retired US Coast Guard Adm. Thad Allen said.
"Four days from now it could be all done," Allen told reporters in Kenner, La., on Sept. 15. "We're within a 96-hr window of killing the well" from the bottom.
He said actions to be taken by the relief well crew will depend upon the conditions found when the relief well penetrates the Macondo well annulus.
An Apr. 20 blowout of the Macondo well resulted in an explosion and fire on Tranocean Ltd.'s Deepwater Horizon semisubmersible on Mississippi Canyon Block 252 in 5,000 ft of water. BP PLC is the operator.
The Deepwater Horizon drilled the Macondo well to a final depth of 18,360 ft, BP has said. No oil has leaked into the Gulf of Mexico since July 15. Scientists estimate 4.9 million bbl leaked, and BP said it captured 800,000 bbl of that. The relief well is being drilled by Transocean's Development Driller III.
Jane Lubchenco, administrator of the National Oceanic and Atmospheric Administration, said federal scientists and others continue monitoring the gulf for subsurface oil. More than 30,000 samples of gulf water have been tested so far.
"There continues to be some oil in the subsurface," Lubchenco said, adding it's "very, very dilute." She said tiny droplets of oil are being biodegraded naturally. "We are getting a better handle at how fast it is happening."
On Aug. 4, the federal government issued an oil budget report in which it estimated 74% of the oil had broken down or been cleaned up by various methods.
Authorities eye Marcellus wells in gas leaks
Pennsylvania's Department of Environmental Protection (DEP) said it is continuing to investigate the source of methane detected in the Susquehanna River and at six private water wells in Wilmont Township, Bradford County.
"Chesapeake Energy has been working at the direction of DEP to determine the source or sources of the stray gas," said DEP Secretary John Hanger. "Gas migration is a serious, potentially dangerous problem. Chesapeake must stop the gas from migrating."
DEP said Chesapeake has six Marcellus shale gas wells on well pads 2-3 miles northwest of the Susquehanna River.
"These wells are believed to be the source of stray gas that was detected on Aug. 4 at a residence," DEP said.
DEP said it issued a notice of violation to Chesapeake and required it to implement a remediation plan. "Progress has been made, but, to date, this violation has not yet been fully resolved," DEP said.
While neither DEP nor Chesapeake has been able to conclusively show that the wells are the source, DEP considers them "the most likely" source.
The wells were drilled between December 2009 and March 2010 but have not been fractured and are not producing Marcellus gas. Controversy over hydraulic fracturing of the Marcellus shale has arisen in Pennsylvania and New York.
DEP said it first received information about water bubbles in the Susquehanna River late on Sept. 2, with additional reports received on Sept. 3 of bubbling in two private drinking water wells nearby. In response, DEP sent two teams of inspectors to investigate the source of stray gas on Sept. 3.
One team of DEP inspectors went to the Susquehanna River near Sugar Run, where bubbling had been reported. DEP collected samples of the gas for analysis to identify the source. Results are expected within 2 weeks.
DEP and Chesapeake have taken gas samples from the water and gas wells.
US seen ranking low as an investment base
The US "ranks near the bottom as a home base for overseas upstream oil and gas investment," concludes IHS CERA in a new study.
The study creates a benchmark for assessing competitive positions from two directions.
"To understand the fiscal competitiveness of companies, you have to consider not only the fiscal terms in the country where oil and gas are being developed but also the fiscal terms of the home country of the company," explained David Hobbs, IHS CERA chief energy strategist, at the World Economic Forum in Tianjin, China.
"The costs of repatriating income from international operations back to the United States are higher for US companies than what many of their chief competitors face when repatriating income back to their respective countries," he said. The imbalance helps explain why the share of total investment by US companies is declining.
Companies from countries such as the UK, the Netherlands, Russia, Canada, Norway, Italy, and China pay less in additional taxes on repatriated income and thus have a competitive advantage over US companies, IHS CERA said.
In some cases, the advantage enables companies to bid twice as much as US companies can for oil and gas concessions.
"The combined costs of the fiscal systems of host countries and of home countries create differences in the valuation of assets," Hobbs said. "This difference is reflected in the amounts that companies can afford to bid for oil and gas rights."
The consultancy worked with Deloitte on the study.
Exploration & Development — Quick Takes
Tap Oil finds gas, oil with Mawar wildcat
Tap Oil Ltd. said initial results of its Mawar-1 wildcat, which was drilled on onshore Block M in the Baram Delta basin in Brunei, show natural gas was encountered in the primary Ridan objective and that oil is indicated farther down.
"Preliminary interpretation of wireline, pressure, and sampling data suggests gas has been encountered in the primary Ridan objective while oil is indicated by data at deeper levels," Tap said.
The Australian exploration and production company said Mawar-1 had reached total depth of 1,292 m MD and wireline logging, pressure, and fluid sampling had been completed. Casing is now being run across the hydrocarbon zones prior to suspending Mawar-1.
The firm said preliminary interpretation of these results indicates Mawar-1 encountered gas in primary objective Ridan sandstone. It said preliminary log analysis suggests Mawar-1 encountered up to 25 m of Ridan reservoir at a depth of 1,005 m MD.
"The presence of gas in this interval is indicated by pressure analysis and sampling," Tap said, adding that the thickness and quality of the Ridan Sandstone "is poorer than expected pre-drill."
A deeper secondary objective Rampayoh Series also had good hydrocarbon indications in cuttings and sidewall cores in an inter-bedded sand-shale sequence. Fluid samples have been taken at 1,040 m MD and 1,048.6 m MD.
"These samples remain sealed for laboratory analysis, but indications are that they contain oil," Tap said. Reservoir quality in the upper part of the Rampayoh Series is "unclear" and will only be confirmed with further analysis of the well data, it said."Once the analysis of all the data has been completed Tap will be able issue more definitive statement regarding the potential of the Mawar-1 well," the firm said.
Block M covers an area of 3,011 sq km in the Baram Delta basin and is the largest onshore permit in Brunei. Block M participants include operator Tap Energy (Borneo) Pty. Ltd. 39%, Triton Borneo Ltd. 36%, China Sino Oil Co. Ltd. 21%, and Jana Corp. Sdn. Bhd. 4%.
Sidetrack extends oil pay in find off Ghana
A sidetrack of the deepwater Owo-1 discovery off Ghana has "significantly extended the column of high-quality light oil discovered," reports Tullow Oil PLC, the operator.
Drilling, wireline logs, and reservoir fluid samples indicate the Owo-1 well cut 174 ft of net oil pay in two Turonian-age zones of high-quality stacked reservoir sandstones. The sidetrack, 0.4 mile east of the discovery well, encountered a total net pay section of 115 ft, including 52 ft of net oil pay in the lower part of the Owo channel system, according to Kosmos Energy, a partner.
The companies earlier reported that pressure data indicate the zones are part of the same accumulation over a gross oil column now estimated at 656 ft (OGJ, Aug. 2, 2010, Newsletter). The Owo 1 sidetrack also discovered 43 ft of net condensate pay and an additional 20 ft of gas pay in the deepest sand encountered. Combined gross hydrocarbon column in both wells is 896 ft.
Neither the well nor the sidetrack encountered water.
The Transocean Sedco 702 semisubmersible drilled the sidetrack to 13,117 ft in 4,685 ft of water. The main well went to 12,766 ft.
The Owo discovery is on the Deepwater Tano block, 37 miles offshore and 19 miles west of Jubilee oil field.
Tullow estimates the Owo oil resource at 70 million bbl at 90% probability, 200 million bbl at 50%, and 550 million bbl at 10%.
Interests in the Deepwater Tano block are Tullow 49.95%, Kosmos and Anadarko Petroleum 18% each, Sabre Oil & Gas 4.05%, and Ghana National Petroleum Corp. 10% carried.
Trinidad and Tobago get bids on six blocks
The Trinidad and Tobago government has received bids on six of seven blocks it offered in its 2010 bid round.
The bid round was closed on Sept. 8. Voyager Energy bid on three of the six blocks.
Energy Minister Carolyn Seepersad-Bachan said the bid round had taken place at a time when gas prices were depressed internationally. All seven blocks are believed to be gas-prone.
She said bids will be sent to a technical evaluation committee. Licenses will be awarded within 2 months.
Here are block descriptions:
• The North Marine Block, in the Gulf of Paria, covers 205 sq km and is now operated by state-owned Petrotrin through its Trinmar subsidiary. Twenty-two wells have been drilled on the block, yielding several oil and gas discoveries in Plio-Pleistocene reservoirs and the Oligo-Miocene Nariva formation. Gulf Central Ltd. was the lone bidder.
• Block NCMA 2 is in the North Coast Marine Area off the northern coast of Trinidad and west of Tobago. It covers 987 sq km in 30-100 m of water. The block is adjacent to Chaconia and Hibiscus gas fields. Voyager Energy and RWE are the joint bidders.
• Block NCMA 3 covers 2,094 sq km in 30-100 m of water off the north coast of Trinidad, south of Hibiscus, Chaconia, and Poinsietta fields. Two wells have been drilled on the block, with one testing for gas. Voyager Energy and Niko Resources Ltd. made a joint bid.
• Block NCMA 4 covers 1,779 sq km in 30-160 m of water off the northwest coast of Tobago. It is east of the Hibiscus-Chaconia-Poinsietta area and contains two proven gas accumulations. Centrica Energy was the lone bidder.
• Block 4(b) lies off the east coast of Trinidad in 100-800 m of water, just east of Dolphin and Starfish gas fields. It covers 750 sq km. Niko Resources Ltd. and Voyager Energy have a joint bid for the block.
• Block 5(d), covering 684 sq km, lies off eastern Trinidad in 450-800 m of water. There have been several discoveries of gas in adjacent blocks, including Manakin to the south and Corallita and Lantana to the west. BG Group PLC was the lone bidder.
Block NCMA 5 received no bids.
Drilling & Production — Quick Takes
Gulfsands presses exploration of Syria Block 26
Gulfsands Petroleum PLC is pressing seismic and exploratory drilling on Block 26 in northeastern Syria, where Khurbet East and Yousefieh fields have produced 10.75 million bbl of oil and average 20,000 b/d of oil with negligible water.
Gulfsands is operator with 50% working interest in the block, of which it relinquished 25% to a contiguous 5,414 sq km. License term is extended until August 2012.
Gulfsands has expanded the 2010 3D seismic program to 1,020 sq km. Shooting has begun on a prospective region west of the Greater Khurbet East survey area. The data will be used to identify new leads and prospects for drilling in 2011 and 2012. Delivery of processed data is expected in the first quarter of 2011.
The rig has spudded the Yousefieh South-1 exploratory well 2 km south of Yousefieh field to target an objective similar to the field's producing reservoir. The prospect's unrisked gross speculative resource is 9-15 million bbl. The rig will then return to drill the vertical Khurbet East-18 delineation well.
The horizontal Yousefieh-4H, the field's third development well 500 m north of the discovery well, encountered the Cretaceous Massive formation at 2,068 m measured depth, 1,543 m true vertical depth below mean sea level. A gross horizontal reservoir section of 718 m was drilled easterly across the Yousefieh structure, with an average net reservoir pay section being assessed from formation logging as 710 m, average porosity 17.9%, and average oil saturation 86.5%.
The gross horizontal reservoir section drilled was a company record, exceeding that of 311 m previously achieved at Khurbet East-5H. Assessment of reservoir facies along hole via the running of a formation imaging logging tool suggests that the Yousefieh structure is of increased vertical thickness to the east than previously understood from the evaluation of seismic data.
The well is to be flow-tested in late September, followed by a fieldwide pressure survey to further assess the extent of the resource. Tie-in of the well appears to have the capability to greatly increase daily production from the field, Gulfsands said.
Syria Block 26 encompasses existing fields that produce more than 100,000 b/d of oil and are operated mainly by Syrian Petroleum Co. Gulfsands' working interest proved and probable reserves in Syria were 46 million bbl at Dec. 31, 2009.
Jackpine bitumen mine starts production
The new Athabasca Oil Sands Project (AOSP) Jackpine bitumen mine in northern Alberta has begun production operations. Shell Canada Energy is the operator of AOSP.
The new mine, with a 100,000 b/d capacity, is AOSP's second mine. Its existing Muskeg River mine has a capacity of 155,000 b/d (OGJ, Sept. 6, 2010, p. 80).
Bitumen from both mines will flow through a 493-km pipeline to feed ASOP's Scotford upgrader, near Edmonton. The upgrader currently is undergoing an expansion and upon completion of the expansion in early next year, production from both mines will rise towards their combined 255,000 b/d capacity.
Construction of the Jackpine mine took about 5 years and at its peak involved more than 6,500 employees and contractors on site, according to Shell.
To reduce the carbon dioxide footprint of its oil sands operations, Shell has underdevelopment a proposed carbon capture and storage project, Quest, which could capture and store underground about 1 million tonnes/year of CO2 from the Scotford upgrader.
Shell Canada Energy owns 60% of AOSP. Its partners are Chevron Canada Ltd. 20%, and Marathon Oil Corp. 20%.
Iran plans to triple gas production by 2015
Iran, second in the world behind Russia in reserves of natural gas, plans to triple gas production by 2015.
Mostafa Kashkouli, deputy managing director of National Iranian Gas Co., told the Iranian news agency Shana that the current 5-year plan calls for gas output of 1.1 billion cu m/day.
The BP Statistical Review of World Energy estimates Iranian gas production in 2009 at 360 million cu m/day, up 13% from the year before.
Much of the increase is coming from development of giant offshore South Pars gas field in the Persian Gulf.
PROCESSING — Quick Takes
Williams starts up Echo Springs expansion
Williams Partners LP, Tulsa, has begun operations on the fourth cryogenic processing train (TXP4) at its Echo Springs natural gas processing plant in Carbon County, Wyo.
The TXP4 plant adds about 350 MMcfd of processing capacity and 30,000 b/d of NGL production, doubling Echo Springs's capacities in both cases.
Although currently gathered volumes exceed 475 MMcfd, Williams expects this to grow with producers' drilling plans. This expansion, said the company, provides the ability to process gas that is now bypassing the plant along with the ability to process expected future increases in third-party gas production.
Construction began on the expansion in second-half 2009 and was placed into service nearly 2 months ahead of schedule and "significantly under budget," according to Williams.
With this expansion, Williams' Opal and Echo Springs processing plants in Wyoming have a combined inlet capacity of more than 2.1 bcfd of gas and 130,000 b/d of NGL production capacity.
Williams says it owns "large-scale midstream assets" concentrated in major producing basins in Colorado, New Mexico, Wyoming, the Gulf of Mexico, and the Marcellus shale in Pennsylvania.
Western Refining completes Yorktown closure
Western Refining Inc. has completed the shutdown of process units at its 70,000-b/d Yorktown refinery in York County, Va. (OGJ, Aug. 16, 2010, Newsletter).
The company, which also has refineries in El Paso and Gallup, NM, cited expectations for weak refining margins on the US East Coast when it disclosed the move last month.
Announcing completion of the shutdown, Mark Smith, Western's president, refining and marketing, said, "If the refining economics on the East Coast improve, we would consider restarting refining operations."
Western is operating the plant as a products terminal and storage facility for which it is "continuing to evaluate all strategic alternatives," according to a press statement.
TRANSPORTATION — Quick Takes
DOE approves LNG export from Sabine Pass
The US Department of Energy last week approved a request from a unit of Cheniere Energy Inc., Houston, to export LNG produced from US gas fields.
The order approved as much as 16 million tonnes/year of LNG (about 2.2 bcfd) for 30-year supply contracts to begin on or before Sept. 7, 2020, from the Sabine Pass LNG terminal in Cameron Parish, La.
Last month Cheniere Energy subsidiary Sabine Pass Liquefaction LLC applied to the DOE's Office of Fossil Energy under Section 3 of the Natural Gas Act in the first of a two-phase request. The first phase applied to exports to countries that currently can import LNG and with which the US has or will enter into a free-trade agreement. The second phase will apply to countries not currently covered by a free-trade agreement and to which export of LNG is not prohibited by US law.
Countries listed by Cheniere's application are Australia, Bahrain, Singapore, Dominican Republic, El Salvador, Guatemala, Honduras, Nicaragua, Chile, Morocco, Canada, Mexico, Oman, Peru, and Jordan.
Of this list, only Chile, Canada, and Mexico operate LNG regasification terminals. Bahrain and Singapore are in different stages of building regasification capacity. Australia, Oman, and Peru currently export LNG.
In June, Cheniere Partners LP let a contract to Bechtel Oil, Gas & Chemicals for design and construction of liquefaction at the 4-bcfd Sabine Pass LNG terminal (OGJ Online, June 10, 2010). That project encompasses two trains, each capable of production 3.5 million tpy. The company said at the time the Cameron Parish site could accommodate up to four LNG trains.
Another US LNG terminal to export
Another US Gulf Coast LNG terminal is seeking permission to export.
Sempra LNG's Cameron, La., terminal has applied to the US Federal Energy Regulatory Commission for approval to offer export services.
The move follows similar steps by Freeport LNG at its Freeport, Tex., terminal, and by Cheniere Partners LP for its Sabine Pass terminal in Cameron Parish, La.
Cameron LNG wants 2-year authority to reexport as much as 250 bcf. This is a reexport project only, not to be supplied from US production. Also, no new equipment would be required, unlike the other two terminals, because initial design of Cameron LNG allowed for valving that permitted reverse flow, according to the application.
Gas flowing through Iran's IGAT 7 pipeline
Natural gas is flowing through the 907-km, 56-in. OD Iran Gas Trunkline 7 (IGAT 7) from Asalouyeh on the Persian Gulf to Iranshahr in the southern province of Sistan-Baluchistan, National Iranian Gas Co. reports.
The pipeline can carry 1.8 bcfd of gas produced in South Pars offshore gas field under design pressure of 1,305 psi, transiting four other provinces: Bushehr, Fars, Hormozgan, and southern Kerman. Flow began Aug. 23.
According to NIGC officials, capacity is to be expanded to 2.9 bcfd.
A planned extension of IGAT 7 would enable Iran to export gas to Pakistan. If completed, the system would have 1,100 km of pipeline in Iran and 750 km in Pakistan (OGJ, Feb. 25, 2010, p. 29).
In June, the countries signed an agreement for initial deliveries of 750 MMcfd, beginning in 2014.
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