GENERAL INTEREST — Quick Takes
Nova Scotia puts fracing on 2-year hold
The Nova Scotia government said it needs 2 more years to study hydraulic fracturing, a practice that has raised concerns about potential contamination of drinking water in some US areas where it has been used on unconventional plays.
No fracing will be approved until the extended review is completed, Nova Scotia officials said. Previously, Nova Scotia was slated to release a fracturing report this year, but officials announced Apr. 16 that the report was delayed until mid-2014.
Energy Minister Charlie Parker said the province wants time to review emerging regulations by the US Environmental Protection Agency and Environment Canada.
"We think it's important to get the best possible information that's out there and make an informed decision after we've learned all that," said Parker.
Premier Darrell Dexter said the province was conducting "a scientific review and coming up with the right decision on it based on the science."
No comment was immediately available from the Canadian Society for Unconventional Resources in Calgary.
API: 1Q total drilling down, well completions up
Exploratory well completions increased by 12% in this year's first quarter, the American Petroleum Institute said in its latest quarterly well completion report. But overall well completions, including exploration and development completions, declined by 9% from a year earlier with 8,963 total wells being completed during the quarter.
The report showed that both oil and natural gas well completions declined from year ago levels, with 5,352 oil well completions, a 1% decline from a year earlier. API reported 2,495 natural gas well completions during the recent quarter, a 28% decline from the first quarter of 2011.
Dry hole completions increased by 11% to 1,116 completions. Estimated total drilling footage during this year's first quarter was 66,254,000 ft, a 9% decline from a year earlier.
Russia reports oil spill at Trebs field
Russian environmental officials reported an oil spill at Arctic Trebs field in the Nenets Autonomous District near the town of Usinsk. The spill from an exploratory well was stopped after 2 days. The size of the spill was estimated at 800-2,000 tonnes.
A Russian Environmental Agency spokesman told the Associated Press that the spill contaminated at least 8,000 sq m of land. Trebs field has estimated reserves of 82.469 million tonnes of oil (OGJ Online, Sept. 9, 2010).
The field is developed by a joint venture involving Lukoil and Bashneft, AP reported.
Plains All American drops SemGroup offer
Plains All American Pipeline LP has withdrawn its unsolicited October 2011 proposal to acquire pipeline operator SemGroup Corp. No additional comment or details were available.
In early October 2011, Plains offered to buy SemGroup for $24/share. SemGroup rejected the offer. In November 2011, Plains reiterated its offer to acquire SemGroup.
Plains first approached SemGroup in March 2010 with a $17/share offer.
Exploration & Development — Quick Takes
Heidelberg downdip sidetrack finds deeper oil pay
An Anadarko Petroleum Corp.-operated downdip sidetrack of the Heidelberg appraisal well in the US Gulf of Mexico has confirmed oil pay, found an oil-water contact, and greatly increased the field's known areal extent, said partner Eni SPA.
Since mid-February, the Anadarko group has drilled the GC 903-3ST1 sidetrack, which has now located the oil-water contact 700 ft deeper than the previous oil discovery well (OGJ Online, Feb. 20, 2012).
Heidelberg is in 5,260 ft of water 130 miles off Louisiana. The appraisal well is 1.3 miles from the discovery well on Green Canyon Block 903. The updip appraisal well went to 31,030 ft measured depth, and the downdip sidetrack went to 30,440 ft.
The group is evaluating well data to accelerate the overall sanctioning process for the project.
Anadarko has 44.25% interest in Heidelberg. Eni and Apache Corp. hold 12.5% each, and Cobalt International Energy LP and ExxonMobil Corp. have 9.375% each.
Eni owns lease interests in 305 blocks in the gulf, where it is among the leading producers with net production capacity of 90,000 b/d of oil equivalent, 60% operated.
Wells abandoned off Sierra Leone
The West African Transform Margin remains "highly prospective" despite two Anadarko Petroleum Corp.-operated exploratory wells that encountered water-bearing reservoirs with oil shows off Sierra Leone and Ivory Coast, said Tullow Oil PLC.
Mercury-2, on Block SL-07B-11 off Sierra Leone 12 km northwest of the Mercury-1 oil discovery, targeted an area where the extensive 3D seismic coverage indicated a high probability of finding thick reservoir quality sandstones. It intersected more than 270 m of reservoir quality sandstones that were water bearing with oil shows at this location, Tullow said.
Mercury-2 went to 5,142 m in 1,815 m of water. Anadarko operates the block with 55% interest, Repsol YPF has 25%, and Tullow has 20%.
Kosrou-1 went to 5,241 m in 2,275 m of water on Block CI-105 off Ivory Coast 17 km east-southeast of the previous South Grand Lahou-1 well. Kosrou-1 targeted a channel system identified on 3D seismic survey shot in 2010. The well cut 90 m of reservoir quality sandstones with oil shows in the primary target and more than 120 m in total in the well.
On completion of operations the rig will return to the Paon-1 location to finish drilling that well. Paon-1 is a high-impact prospect geologically independent from Kosrou and closer to recent discoveries in Ghana. Anadarko operates CI-105 with 50% interest. Tullow has 22%, Petroci 15%, and Thani 13%.
Tullow said it will integrate data from the two wells into its regional models to improve the chances of making a hub-class discovery with the ongoing exploratory campaign that includes the Strontium-1 well off Liberia and Paon-1 off Ivory Coast.
Thicker Toro gas found at P'nyang South
A sidetrack of the P'nyang South-1 well in Papua New Guinea is interpreted to have extended the gas-bearing Toro sandstone 200 m deeper than the lowest known gas in P'nyang South-1, indicating an increase in the total gas column to 380 m, said Oil Search Ltd., Sydney.
The sidetrack intersected the top of Toro downdip and 1.1 km south of the original P'nyang South-1 well. It successfully drilled through the gas-water contact as planned.
Seismic interpretation and structural mapping suggest further updip potential above P'nyang South-1 and indicate a potential vertical gas column in P'nyang South field of more than 650 m, Oil Search said.
Oil Search, with 38.5% interest, drilled the sidetrack to 2,944 m under contract with the operator, Esso PNG P'nyang Ltd. ExxonMobil affiliates have 49% interest in the sidetrack, and JX Nippon has 12.5%.
Explorer New Guinea Energy Ltd., Sydney, pointed out that Oil Search's P'nyang South well on PRL 3 is 2 km north of the boundary with NGE's PPL 269. Oil Search said the presence of gas is indicated in the Toro, Digimu, and P'nyang sands at the initial P'nyang South-1 well but the underlying Koi-Iange sandstone appears to be water wet. P'nyang South is 90 km northwest of giant Juha gas-condensate field.
Silurian, Ordovician shales to be explored in Lithuania
UAB Minijos Nafta will spud an exploratory well in May on the Gargzdai license in western Lithuania that will evaluate several targets including shales of Silurian and Ordovician age.
The well, which targets a previously undrilled Cambrian sandstone, will also be extensively logged and cored in the Silurian and Ordovician shale sections, said Tethys Oil AB, Stockholm. The 2012 work program also includes two sidetracks and a 50 sq km 3D seismic survey.
Tethys Oil said its share of production in Lithuania averaged 159 b/d of oil in the quarter ended Mar. 31, 2012. Gargzdai gross production averaged 638 b/d.
Tethys Oil's share of reserves in Gargzdai, according to the agreement with Odin Energi AS, as of the end of 2011 were 700,000 bbl proved, 1.7 million bbl proved and probable, and 3 million bbl proved, probable, and possible.
Work programs for the Rietavas and Raiseiniai licenses have not been finalized, but reprocessing of seismic data continues. The Silale-1 well on Rietvas, which flowed 150 b/d from Cambrian when drilled in the 1980s, will be worked over.
Tethys' assets in Lithuania will be held through a 25% net indirect interest in UAB Minijos Nafta and a 20% net indirect interest in UAB LL Investicos. MN holds the Gargzdai license, and LLI holds Rietavas and Raiseiniai.
Drilling & Production — Quick Takes
PTTEP starts production from GBS field
PTT Exploration & Production PCL (PTTEP) and its Bongkot joint venture partners reported the start of production from Greater Bongkot South (GBS) natural gas and condensate field in the Gulf of Thailand. GBS field lies on Blocks B16 and B17 about 200 km east of the southern Thai city of Songkhla.
This stand-alone development consists of a central processing platform, a living quarter platform, and 13 wellhead platforms. The processing platform has capacity to process 350 MMcfd of gas and 15,000 b/d of condensate. Gas is exported via a newbuild spur line to the PTTEP grid; condensate is exported to the existing floating, storage, and offloading vessel at Greater Bongkot North field, which lies 80 km north.
Bangkot field is operated by PTTEP, which holds 44.45% interest. Total SA holds 33.33% and BG Group, 22.22%.
Total starts up natural gas field offshore Scotland
Total SA has started production from Islay natural gas field straddling the UK-Norwegian sector line in the North Sea 440 km northeast of Aberdeen (OGJ Online, July 15, 2010).
Production from a single well, completed subsea in 120 m of water and tied back to the Alwyn North platform, has reached 15,000 boe/d. Total estimates reserves at 17 million boe of gas and condensate.
Discovered in 2008, the field lies mostly on Block 3/15 of the UK sector and partly on Blocks 29/6a and 29/6c of the Norwegian sector.
Total holds 100% interest in Islay and the Alwyn production hub (OGJ Online, Nov. 6, 2006).
Samburskoye flow starts in West Siberia
SeverEnergia, a Russian joint venture of Eni SPA, Novatek, Gazpromneft, and Enel, has started production of natural gas and condensate from Samburskoye field in the Yamal-Nenets autonomous district of western Siberia, Eni reported (OGJ Online, May 21, 2009).
The initial production rate is 43,000 boe/d. Output is to peak in 2015 at 145,000 boe/d.
The joint venture is developing the field with two integrated production systems incorporating three trains for gas and condensate and two trains for rim oil. Facilities are in the Purov district of Tyumen about 150 km northeast of Novy Urengoy.
Gas and condensate development involves 98 production wells, including 68 new horizontal wells, 15 slanted wells, 11 workovers of existing wells, and 4 sidetracks. Most drilling of the wells, to be located in 12 clusters, is to be finished by 2017.
Facilities include a treatment plant with 18.75 million standard cu m/day of total capacity, a 48-km, 40-in. gas export pipeline, and a 22-km, 12-in. condensate export line.
Oil development will include 55 new horizontal producing wells, 3 workovers, and 35 water-injection wells, 25 new and 10 converted from oil wells. Most of the oil wells are to be drilled and completed by 2018.
Oil treatment capacity will total 1.3 million tonnes/year, 200,000 tpy in a first train and 1 million tpy in a second. There will be a 110-km export oil pipeline.
Interests in SeverEnergia are Eni 30%, Novatek and Gazpromneft 25.5% each, and Enel 19%.
Petrobank: Kerrobert output up in March
Petrobank Energy & Resources Ltd. said production from its Kerrobert in situ combustion project in southwestern Saskatchewan increased in March to an average 264 b/d of apparently upgraded bitumen (OGJ Online, Feb. 1, 2012).
The company is using its proprietary THAI technology in the project, production of which in January and February averaged 155 b/d. To support combustion, it injects air through vertical wells drilled near the toes of horizontal producing wells.
That the produced oil has average API gravity of 13-14º indicates upgrading is occurring in situ, Petrobank says. The reservoir oil is 10.4º gravity.
The company brought Kerrobert field on production last September.
PROCESSING — Quick Takes
Oneok plans more processing Cana-Woodford shale
Oneok Partners LP, Tulsa, reported it will invest $340-360 million through first-quarter 2014 to expand natural gas gathering and build new processing in the Cana-Woodford shale in Oklahoma.
Included will be about $190 million for construction of the 200-MMcfd Canadian Valley natural gas processing plant in Canadian County, Okla. It is to be in service first-quarter 2014.
When completed, the plant will be the company's largest gas processing plant in Oklahoma and increase its total gas processing capacity in the state to 690 MMcfd.
In addition, Oneok will invest $160 million to expand and upgrade existing gas gathering and compression, increasing the company's gas gathering and processing capacity to 390 MMcfd in the Cana-Woodford shale.
"Additional natural gas processing infrastructure is necessary to accommodate increased production of liquids-rich natural gas in the Cana-Woodford shale," said Pierce H. Norton, Oneok executive vice-president and chief operating officer.
The partnership now has announced a total investment of $4.7 billion to $5.7 billion through 2015 for growth projects in natural gas gathering and processing, natural gas liquids and crude-oil infrastructure.
Sunoco, Carlyle discuss JV for refinery
Discussions have begun that might keep Sunoco Inc.'s 330,000 b/d Philadelphia refinery, considered pivotal to East Coast product supply, from closing in July.
Sunoco, which is exiting the refining business, said it has entered exclusive discussions with the Carlyle Group about a joint venture that would keep the refinery in business.
Sunoco would contribute the refinery assets in exchange for a nonoperating minority interest in the joint venture and be relieved of ongoing capital obligations related to the facility.
Carlyle, a global alternative asset manager, would contribute cash, hold majority interest, and oversee day-to-day operations of the joint venture and refinery.
Sunoco has been seeking a buyer for the refinery, its last, and said it would close the facility if one were not found by July (OGJ Online, Dec. 2, 2011).
The Energy Information Administration in February warned of market strains likely to result from the refinery's closure, which would follow shutdowns of other refineries crucial to East Coast supply and come as requirements took effect in New York for ultralow-sulfur heating oil (OGJ Online, Feb. 28, 2012).
Repsol opens Cartagena refinery expansion
Repsol held a ceremonial opening of the expansion of its 110,000 b/d Cartagena refinery in Murcia, Spain, to 220,000 b/d of distillation capacity (OGJ Online, Jan. 7, 2010).
The €3.15-billion project, which Repsol calls the "biggest industrial investment in Spanish history," includes 50,000 b/d of hydrocracking, 60,000 b/d of coking, and 60,000 b/d of desulfurization capacity.
TRANSPORTATION — Quick Takes
Enbridge files application to twin Athabasca line
Enbridge Pipelines (Athabasca) Inc. applied with Canada's Energy Resources Conservation Board for licenses to build a crude oil pipeline with two pump stations from Kirby Lake Terminal south to Battle River Terminal, in the Hardisty, Alta., crude hub. The 344-km pipeline would transport hydrogen sulfide-free crude using new pump stations at the existing Kirby Lake and at Bonnyville Station facilities.
The construction is part of Enbridge's Athabasca Pipeline Twinning Project and will generally follow the existing Athabasca Pipeline right-of-way, using 36-in. OD pipe. The twin line initially will add about 450,000 b/d of capacity between these points, with low-cost expansion potential to 800,000 b/d, according to Enbridge (OGJ Online, Sept. 13, 2011).
Enbridge expects to start work on the project in late 2013 pending regulatory approvals, starting with pump station construction in October 2013 and continuing with clearing ROW and building the pipeline once frozen ground conditions exist in December 2013. Enbridge expect initial shipments by early 2015 and full initial capacity to be available by 2016.
Enbridge described the new line as addressing the need for additional capacity to serve Kirby area oil sands growth, beyond already announced plans to expand the existing 30-in. OD pipeline to its maximum 570,000 b/d capacity.
GDF Suez studies floating LNG unit off India
A unit of GDF Suez is studying feasibility of a floating LNG regasification terminal offshore southeastern India for Andhra Pradesh Gas Distribution Corp. Ltd. (APGDC).
APGDC, a joint venture of state-owned GAIL Gas Ltd. and Andhra Pradesh Gas Infrastructure Corp. Pvt. Ltd., signed a project framework agreement with GDF Suez LNG UK Ltd. for the study of a regas terminal with capacity of 3.5 million tonnes/year, envisioning commissioning early in 2014.
The feasibility study is to be completed by yearend, followed by a final investment decision. GDF Suez, as a strategic partner, would have a 26% stake in the terminal with access to equity regasification capacities.
India's Minister of Petroleum and Natural Gas, in a statement about the agreement, said shortage of natural gas in Andhra Pradesh has led to "underutilization of infrastructure, especially in the power sector."
The problem extends to other parts of the country, said Petroleum Minister Shri S. Jaipal Reddy. "The need for gas in India cannot be overstated," he said.
Chubu signs Wheatstone LNG offtake agreement
Chevron Corp. has signed a nonbinding heads of agreement with Japan's Chubu Electric Power Co. Inc. for the supply of 1 million tonnes/year of LNG from the Wheatstone project in Western Australia.
Chubu also is a foundation member of Chevron's Gorgon LNG project. It will now receive a total of 2.5 million tpy from both developments over a 20-year period. Chevron says 70% of its equity LNG entitlements from Wheatstone are now covered by long-term contracts with Asian customers.
The plant is being constructed at Ashburton North about 7½ km west of Onslow. Initially it will comprise two LNG trains with a combined capacity of 8.9 million tpy as well as production from a domestic gas plant.
The project is a joint venture of Chevron 72.14%, Apache Energy 13%, Kufpec 7%, Shell 6.4%, and Kyushu Electric 1.46%.
KMEP launches Cochin Reversal open season
Kinder Morgan Energy Partners LP launched a binding open season for its Cochin Reversal Project to move light condensate from Kankakee County, Ill., to existing terminal facilities near Fort Saskatchewan, Alta. The project involves KMEP modifying the western leg of its Cochin Pipeline to connect to the Explorer Pipeline Co. in Kankakee County and to reverse flow to move the condensate northwest.
The project would move about 75,000 b/d of light condensate on Cochin to meet the growing demand for diluent in Alberta drawing from both Eagle Ford shale and US Gulf Coast supplies, KMEP said. KMEP has yet to determine the nature of future eastbound service from Illinois to Windsor, Ont.
KMEP is seeking binding commitments from interested customers for a minimum contract term of 10 years and 5,000 b/d. The open season ends May 31. Subject to shipper support, timely regulatory approvals and necessary capital improvements, light condensate shipments could begin on July 1, 2014.
KMEP cited declining propane production in western Canada and increased natural gas production from US shale formations as driving the project, with propane production in North Dakota expected to rise even as demand for Canadian propane export transportation services wanes. At the same time, the company cited Canadian National Energy Board projections of a more than two-and-a-half fold increase in light condensate demand in Canada, reaching 450,000 b/d by 2025, in explaining the decision to reevaluate its long-term strategy for Cochin.
KMEP held an open season in 2009 to solicit market interest in using Cochin to ship light Bakken crude eastward, the demand for propane shipments already waning (OGJ Online, June 2, 2009). More recently, KMEP contemplated reversing Cochin's eastern leg to carry Marcellus shale NGLs from Riga, Mich., to the Chicago area (OGJ Online, Apr. 4, 2010). KMEP withdrew its applications for the new-construction portion of this project—a 250-mile pipeline from the Marcellus region to Riga—in February.
Cochin is a 1,900-mile, 12-in. OD multiproduct pipeline operating between Fort Saskatchewan, Alta., and Windsor, Ont. It currently moves propane and ethane-propane mix to Midwestern US and eastern Canadian petrochemical and fuel customers. Explorer Pipeline is a nearly 1,900-mile common carrier pipeline system moving refined petroleum products, feedstock, and diluent from the Gulf Coast throughout the Midwest.
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