General Interest — Quick Takes
Impacts estimated for hydraulic fracturing
US economic strength would be reduced by several billion dollars in the next 5 years if hydraulic fracturing was federally regulated, the second part of an American Petroleum Institute-commissioned study found.
Adopting proposals to essentially duplicate existing state regulations of a process that is helping to open up significant domestic shale gas resources would lead to job losses and a wider trade deficit, API said on July 1 as it released the second part of the study by IHS Global Insight.
The latest report looked at three scenarios: a hydraulic fracturing ban, restrictions on fluids that could be used, and the implementation of federal underground injection control (UIC) compliance regulations in addition to current state regulations.
With a total ban, the study said real gross domestic product would plunge $374 billion, or 2.3%, from the economic reference case and 2.9 million jobs, or 2%, would be lost by 2014 as a result of the 79% drop in oil and gas well completions which would result.
US GDP would drop by $172 billion, or 1.1%, and 1.3 million jobs, or 0.9%, would be lost under the study’s fluid restrictions scenario. The UIC compliance approach, meanwhile, would cut GDP by $84 billion, or 0.5%, and oil and gas industry payrolls by 635,000 jobs, or 0.4% during the same period, the study said.
Economies of the leading US gas production states (Texas, Louisiana, Wyoming, and Oklahoma) would probably be hit the hardest, although many states with little or no oil and gas production would indirectly feel the effects rippling through the overall US economy, it added. Impacts would be particularly severe in states with relatively small economies such as Arkansas, Mississippi, Montana, Utah, and Virginia, it said.
The latest report follows the study’s initial findings, which API released on June 9. They indicated that the number of new US wells drilled would drop 20.5%, reducing domestic gas production by about 10% from 2008 levels if Congress placed additional federal hydraulic fracturing regulations on top of existing state programs.
“Hydraulic fracturing is a safe, proven, 50-year-old technology that is critical to developing the natural gas used to heat homes, generate electricity, and create basic materials for fertilizers and plastics,” said API Pres. Jack N. Gerard. “More than 1 million wells have been completed using this technology. Unnecessary additional regulation of this practice would only hurt the nation’s energy security and threaten our economy.”
Santos increases its CSM assets
Santos Ltd., Adelaide, increased its coal seam methane (CSM) assets in Australia with a corporate acquisition and an acreage buy in the Gunnedah basin of northern New South Wales.
The company acquired 19.9% interest in Sydney-based CSM explorer and producer Eastern Star Gas Ltd. from ESG’s major shareholder Hillgrove Resources Ltd. for $176 million (Aus.).
In addition, Santos paid Gastar Exploration Ltd. $300 million for its 35% interest in several Gunnedah basin permits and production areas operated by ESG.
Santos said the Gunnedah area could be the country’s second major CSM province after the Surat/Bowen Basin of eastern Queensland.
The combination of ESG and Santos permits in northern New South Wales will cover 63,000 sq km. Santos estimates a resource potential in excess of 50 tcf of gas.
Santos first entered the region in 2007 and is already undertaking a 23-well exploration program. ESG has been in the basin since 2002 and is recognized as the leading independent explorer.
ESG’s Narrabri CSM joint venture’s drilling program is on track to delineate 1,300 petajoules of proved and probable CSM gas reserves by yearend.
Industry Scoreboard
Exploration & Development — Quick Takes
McMoRan finds apparent pay below Mound Point
Log-while-drilling tools indicated an encouraging 150 gross ft of resistive zones at the Blueberry Hill deep gas exploratory sidetrack well in Louisiana State Lease 340 just off western St. Mary Parish on the Gulf of Mexico shelf, said McMoRan Exploration Co., New Orleans.
McMoRan plans to deepen the well, now at 21,900 ft true vertical depth, to 24,000 ft after it resolves an undisclosed mechanical issue.
The wellsite is in 10 ft of water southeast of Mound Point oil and gas field, discovered in 1958.
McMoRan reentered an existing well bore on Mar. 29 and sidetracked to target Miocene Gyro sands downdip on the flank of the structure encountered in the original Blueberry Hill well. It plans to run wireline logs across the resistive zones. Deepening to 24,000 ft is to evaluate other prospective sands found in the first well.
The Blueberry Hill structure, an example of McMoRan’s deeper pool concept, appears to have large reserve potential and further development and exploration opportunities, the company said. It is 11 miles southeast of Flatrock, another deeper pool field with six wells capable of totaling 300 MMcfd of gas equivalent.
Blueberry Hill represents the deeper expression of the structural features of the shallower Mound Point field, which has produced more than 2.5 tcf of gas equivalent from multiple wells above 12,500 ft.
McMoRan has 42.9% working interest and 29.7% net revenue interest in the Blueberry Hill well and controls 150,000 gross acres in the Tiger Shoal-Mound Point area covering federal OCS Block 310 and state lease 340. Plains Exploration & Production Co., Houston, has 47.9% working interest.
Sonatrach, GDF Suez to develop project in Algeria
Algeria’s Sonatrach and GDF Suez SA of France announced plans to develop the Touat gas license in west-central Algeria, in the Timimoun basin near Adrar.
This follows an exploration and appraisal campaign that began in 2003 with seven wells. The development plan was approved by the National Agency for the Promotion of Hydrocarbon Resources (ALNAFT).
Development will start this year with gas production due on stream in 2013 and peaking at 4.5 billion cu m/year.
Sonatrach and GDF Suez will jointly operate the Touat project involving development of 10 fields in an area of 3,000 sq km on which 40 production wells will be drilled. The project also includes construction of gas collection and processing installations as well as a connection to the pipeline Sonatrach is planning to build to link fields in the area to Hassi R’Mel.
Sonatrach will be in charge of selling the gas produced. GDF Suez is one of the largest liquefied natural gas companies in the world and the largest buyer of Sonatrach’s LNG.
The 10 fields are Hassi Ilatou, Hassi Ilatou Cambrien, Hassi Ilaout Nord Est, Gour Nefrat Gedinnen, Gour Nefrat Ordovicien, Bou Hadid, Bou Hadid Ouest, Oued Hamou, Oued Zine, and Sbaa.
Israel’s Tamar gas may vie with LNG terminal
Noble Energy Inc., Houston, hiked its resource estimate 26% to 6.3 tcf after the Tamar appraisal well in the eastern Mediterranean off Israel “confirmed continuous high-quality reservoirs.”
However, the Noble Energy group may have to compete with LNG because Israel’s Natural Gas Authority last week published prequalification documents in connection with construction of an LNG receiving terminal by 2013. Noble Energy Chairman and Chief Executive Officer Charles Davidson said the group’s focus is to ship Tamar gas to shore by 2012.
Tamar-2, in 5,530 ft of water on the flank of the structure 3.5 miles northeast of the Tamar-1 discovery well, considerably reduced the uncertainty in previous resource estimates, Noble Energy said. Total depth is 16,880 ft.
Tamar-2 found reservoir thickness and quality consistent with those at Tamar-1. It encountered the gas-water contact as projected in the middle reservoir and, as expected, no water contact was seen in the top reservoir.
Noble Energy obtained whole core samples in three reservoirs to assist in geologic and engineering studies needed for field development and retained a reservoir consulting firm to prepare an independent estimate of the discovered resource.
The 6.3 tcf figure is double the predrill resource estimate for the prospect (see map, OGJ, Oct. 6, 2008, p. 41).
Noble Energy said the Tamar and Dalit discoveries represent “perhaps 2 decades of future supply [of gas for Israel] based on projected needs.”
Noble Energy operates the Matan license, on which Tamar was drilled, with 36% working interest. Other interest owners in the wells are Isramco Negev 2 with 28.75%, Delek Drilling 15.625%, Avner Oil Exploration 15.625%, and Dor Gas Exploration 4%.
The group is preparing to shoot 1,200 sq miles of 3D seismic over several leads on its acreage in the Levantine basin starting in the third quarter.
The government said buying LNG internationally would provide a backup to domestic supplies. It estimated maximum capacity of the LNG terminal at as much as 560 MMcfd but said early imports would likely be small because of the offshore gas discoveries, implying possible priority for Tamar and Dalit.
Israel’s existing gas comes from Egypt and from fields in shallower water than Tamar.
Israel’s gas demand has been rising for several years, but overall prospects for world LNG demand remain bleak (OGJ Online, July 1, 2009).
Drilling & Production — Quick Takes
Tyrihans field off Norway starts production
StatoilHydro started production from the subsea completed Tyrihans oil and gas field in the Norwegian Sea on July 8.
Tyrihans subsea facilities, in 270 m of water, tie back to existing installations and infrastructure on the Kristin and Asgard fields in the Halten Bank area.
The field consists of two parts. Tyrihans South is an oil field with a gas cap and Tyrihans North is a gas-condensate discovery with a thin oil zone. The field lies in Blocks 6406/3 and 6407/1.
StatoilHydro estimates that the field has recoverable reserves of 186 million bbl of oil and condensate, and 41.5 million cu m of gas.
A 43-km pipeline transports the production from Tyrihans to Kristin for processing. From Kristin, the gas is transported ashore through the Asgard Transport pipeline while oil and condensate proceed to the Asgard C storage ship for onward transport by tanker.
Kristin and Tyrihans share the same operations organization.
Statoil Hydro says that Tyrihans is the largest field being brought on stream off Norway this year.
Drilling in the field, discovered in 1982-83, will continue for the next 2 years and StatoilHydro expects the field to reach a 96,000-boe/d plateau production in 2016-17.
In 2005, StatoilHydro submitted the development and operation plan to the Ministry of Petroleum and Energy, which approved the plan in February 2006.
The company installed the seabed templates in spring 2007 and began drilling wells in April 2008.
The development plan includes the installation of a subsea seawater injection facility for reservoir pressure support in summer 2010.
Statoil expects the field to continue to produce until yearend 2029.
Operator StatoilHydro holds a 58.84% interest in the field. Partners are Total E&P Norge AS 23.18%, ExxonMobil Exploration & Production Norway AS 11.75%, and Eni Norge AS 6.23%.
First deepwater circular drilling rig completed
The COSCO Shipyard Group’s Qidong shipyard recently completed construction of the Sevan Driller, the world’s first deepwater circular drilling rig, Sevan Marine ASA reports.
Sevan Marine owns the rig and designed it to drill to 40,000 ft and in 12,500 ft of water. The rig has a 150,000 bbl of oil internal storage capacity and a variable deckload of more than 15,000 tonnes.
Rig construction started at the COSCO Nantong shipyard in May 2007 and moved to COSCO’s Qidong shipyard in April for derrick erection and final commissioning activities.
Sevan Marine says the rig, due for delivery in the third quarter, has a 6-year fixed contract with Petroleo Brasileiro SA for work in the Santos basin off Brazil.
Petrofac brings Don Southwest field on stream
Petrofac Energy Developments started oil production from two wells on Don Southwest (Don SW) in the UK northern North Sea, adding to initial output from the nearby West Don field that began in April.
Total peak production from both fields is expected to reach more than 40,000 b/d.
During the second half of 2010, the company plans to bring on stream additional production and injection wells for the second phase of the Don SW development.
Petrofac is interpreting the structure and lateral of a 60 ft oil column in the Brent formation after drilling a sidetrack to an adjacent fault block, Area H, directly south of Don SW field. This was done to investigate the northern part of the block at low incremental cost.
Amjad Bseisu, chief executive of Petrofac Energy Developments, said the company is firming up plans for a 2010 campaign to optimize Area 5/6 development “and the early indications of our success in Area H give us confidence in the prospectivity of the surrounding areas.”
Don SW is an oil field comprising 450 ft thick Brent sequence sandstones, as producing in the nearby Thistle and South Magnus fields. The under-saturated oil is held in a combination of dip and fault traps at a depth of 11,000-11,500 ft.
Petrofac operates the block with a 60% interest, alongside Valiant Petroleum which has a 40% interest.
West Don field is on Blocks 211/18a West Don Area and 211/13b was developed via the floating production vessel, Northern Producer, and two production wells. The first tanker shipment of 472,000 bbl of oil from the West Don field has been delivered to a terminal in Rotterdam. Petrofac said, “The second production well and the injection well on West Don are expected to be brought on stream in the early part of the second half of 2009, with the injection wells on Don SW following in the latter part of year.”
Peak production from West Don is expected to reach 25,000 b/d and was a fast track initiative; it came onstream less than 1 year from receiving field development program approval.
Oil export from the Northern Producer floating production facility will take place initially via offshore tanker, switching to pipeline export via a subsea tie-back to existing infrastructure.
Petrofac Energy Developments operates west Don with Valiant Petroleum, Nippon Oil Exploration and Production (UK) Ltd., Stratic Energy, and First Oil.
KNOC acquires riserless mud recovery technology
Korea National Oil Corp. (KNOC) signed a $9 million drilling contract with AGR Drilling Services to use its riserless mud recovery system technology off Sakhalin Island later this year and in 2010.
AGR Drilling, part of AGR Group ASA at Straume, Norway, said its technology would enable KNOC to return drilling fluids and cuttings topside without a riser system and reduce the impact on the environmentally sensitive area.
This is the second time AGR Drilling Services will be supporting drilling operations in the Pacific region.
KNOC has different blocks in Russia: Tigil, Icha, and West Kamchatka. Tigil block is off the Kamchatka Peninsula and covers 3,264 sq km. KNOC and its partners are required to shoot 2D seismic, as well as drill two exploration wells by 2010.
Icha is an onshore block spanning 3,100 sq km and is near Tigil. KNOC and its partners will shoot 2D seismic and drill one exploration well during 2010.
KNOC is exploring the West Kamchatka block in the Okhotsk Sea in partnership with OAO Rosneft. This acreage covers 62,680 sq km in less than 300 m of water.
Last year it shot 2D and 3D seismic and drilled one exploration well. Its operations are controversial as this block is in an area that is one of the world’s richest producers of salmon and hundreds of other aquatic species.
Processing — Quick Takes
Total to sell Dutch refinery stake to Lukoil
Total SA has exercised its preemptive rights to acquire a 45% share in the 147,000-b/d Vissigen refinery in the Netherlands from Dow Chemical and entered an agreement to sell the stake to Lukoil.
Total owns 55% of the refinery. It said the sale to Lukoil is contingent on acceptance of the deal by the “competent authorities,” including the European Commission’s competition regulators and, according to a Total spokesman, workers’ committees in France and the Netherlands.
A purchase price of $725 million reported in the Russian press was not confirmed by Total.
Valero Energy Corp. earlier had agreed to buy the Dow Chemical interest for an enterprise value estimated at $725 million.
Lukoil supplies around 30% of the crude oil for Total’s West European refineries.
Start-up delayed for Kuwait styrene unit
Start-up of Kuwait Styrene Co.’s ethyl benzene styrene monomer unit in Kuwait has been delayed 4-8 weeks by a technical problem with an intermediate storage tank used in the production of styrene monomer.
Officials said they do not know how long the start-up may be delayed, pending a technical assessment of the tank. The unit expected to begin commercial operations within a few days. It was due to start up in the second quarter, according to previous company statements.
KSC, a major producer of olefins in Kuwait, is in contact with customers and has developed plans to help mitigate any production shortfall due to the delay, officials said.
The unit is within Equate Petrochemical Co.’s complex in the Shuaiba Industrial Area. The KSC plant is designed to produce 450,000 tonnes/year of ethyl benzene and 500,000 tonnes/year of styrene monomer. Those facilities will be operated by Equate, a firm largely owned by Petrochemical Industries Co. and Dow Chemical Co. KSC is a joint venture of Dow Chemical and government-owned Kuwait Aromatics Co.
Transportation — Quick Takes
Tangguh LNG sends out first cargo
Indonesia’s Tangguh LNG project, the country’s third LNG center after Bontang and Arun, lifted its first cargo on July 6, according to operator BP PLC. The liquefaction plant is in Papua Barat.
The first cargo marks start-up of the project, slightly more than 4 years after its final approval by the Indonesian government March 2005. The cargo, aboard the Tangguh Foja, sailed for POSCO’s LNG regasification terminal in Gwangyang, South Korea.
Tangguh consists of the development of six gas fields in the Wiriagar, Berau, and Muturi production-sharing contracts in the Bintuni area of Papua in eastern Indonesia. Gas produced from two normally unmanned offshore platforms is fed via 22-km pipelines to two onshore liquefaction trains, each with a production capacity of 3.8 million tonnes/year of LNG.
Train 1 began LNG production in mid-June, said BP, producing the LNG for the first cargo, and Train 2 will begin later this year.
BP Indonesia (37.16% interest) operates Tangguh as a contractor to the Indonesian oil and gas regulator, BPMigas. Other partners in the project are MI Berau BV (16.3%), CNOOC Ltd. (13.9%), Nippon Oil Exploration (Berau) Ltd. (12.23%), KG Berau/KG Wiriagar (10%), LNG Japan Corp. (7.35%), and Talisman (3.06%).
The project has long-term contracts to supply 2.6 million tpy of LNG to China’s Fujian terminal, 1.15 million tpy to K-Power and POSCO in South Korea, and a flexible contract to supply up to 3.7 million tpy to Sempra’s LNG regasification terminal in Baja California, Mexico.
Main engineering contractors for the Tangguh project’s onshore infrastructure are the KJP consortium: Kellogg, Brown & Root (through its subsidiary PT Brown & Root Indonesia), JGC Corp., and PT Pertafenikki Engineering. Lead contractor for offshore and subsea construction was Saipem.
Enterprise opens central treating facility
Initial volumes of natural gas have begun flowing into the new central treating facility (CTF) in Rio Blanco County, Colo., owned and operated by Enterprise Products Partners LP. The facility was completed in fourth-quarter 2008.
Located about 8 miles south of Enterprise’s recently expanded Meeker gas processing complex, the CTF can handle as much as 200 MMcfd and handles production from ExxonMobil’s properties in nearby Piceance basin. Production from those, according to the Enterprise announcement, is currently running about 100 MMcfd.
Michael A. Creel, Enterprise president and chief executive officer, said the facility provides the necessary services to support ExxonMobil’s Piceance project and “complements our recently completed Meeker II expansion.” That expansion doubled gas processing capacity at the complex.
The CTF treats natural gas to remove impurities then compresses that treated gas for transportation to Meeker. There, Enterprise can use its standalone 200 MMcfd dewpoint-control plant for processing or route the stream through one of the larger cryogenic processing units.
Completion of the Meeker Phase II expansion brought cryogenic processing capacity to 1.5 bcfd and allows extraction of as much as 70,000 b/d of NGL, said the Enterprise announcement. Separation of NGLs into ethane, propane, butanes, and natural gasoline renders the residue-gas stream acceptable for delivery into one of several interstate transmission pipelines accessible to producers through the White River Hub.
That hub is jointly owned by Enterprise and Questar Pipeline Co. Through Enterprise’s Mid-America Pipeline and Seminole systems, the extracted NGLs can be delivered to the partnership’s Hobbs and Mont Belvieu, Tex., fractionation facilities.
Meeker and the new CTF are part of a 30-year midstream services agreement Enterprise has with ExxonMobil, which has estimated 45 tcf of potential natural gas on its acreage in the Piceance basin, said Enterprise.
Total gas production among all the producers in the basin, which covers more than 6,000 square miles, currently exceeds 1.5 bcfd from more than 6,000 wells, said the company. Additionally, production has been growing at about 23%/year over the past 6 years and continues to support sustainable drilling activities.
Authorization pulled for GDF Suez terminal
The Marseille Administrative Court rescinded the authorization granted by regional executive authorities for operation of the GDF Suez methane terminal under construction at Fos-sur-Mer.
The terminal was undergoing final tests before its launch at yearend. Authorization was rescinded after an association for protection of the coastline pointed to the absence of certain documents—including a seismic survey—from the public inquiry process.
GDF Suez said it would appeal. Meanwhile, as the reauthorization process will be lengthy, the company will request provisional authorization since “the project is strategic for southern France,” officials reported.
