Upstream News
Apache plans $1.75B expansion of North Sea assets as it eyes success in Egypt's Western Desert
Houston-based Apache Corp. is expanding its presence in the North Sea while continuing its drilling success in the Faghur Basin.
A company subsidiary, Apache North Sea Ltd., has agreed to acquire Exxon Mobil Corp.'s Mobil North Sea LLC assets — including the Beryl field and related properties — for $1.75 billion in cash.
The fields have current net production of approximately 19,000 barrels of oil and natural gas liquids and 58 million cubic feet (MMcf) of natural gas per day. At year-end 2010, estimated proved reserves totaled 68 million barrels of oil equivalent.
The transaction, with a planned close at year-end 2011, is expected to increase Apache's North Sea production by 54% and proved reserves by 44%. The assets include operated interests in the Beryl, Nevis, Ness, Nevis South, Skene and Buckland fields; operated interest in the Beryl/Brae gas pipeline and the SAGE gas plant; non-operated interests in the Maclure, Scott and Telford fields; and Benbecula (West of Shetlands) exploration acreage.
"These major legacy assets will expand Apache's presence in the North Sea. They bring us significant remaining life, high production efficiency and quality reservoirs — the best North Sea assets we've evaluated since acquiring the Forties Field in 2003," said G. Steven Farris, Apache's chairman and CEO. "There is a portfolio of low-risk exploitation projects, and we believe the complex structural setting holds reserve upside."
Since acquiring the Forties Field in 2003, Apache has drilled about 100 development wells, invested $3.2 billion, produced approximately 161 MMboe — more than the proved reserves at the time of the acquisition — and added an estimated 171 MMboe in new reserves. Second-quarter 2011 net production from Forties averaged 56,985 barrels of oil per day, up from approximately 33,000 barrels per day in the second quarter of 2003, after Apache assumed operations.
A September 21 note to investors from Global Hunter Securities (GHS) echoed Apache's success story in the Forties field, noting the company was able to increase production in the property acquired from BP in 2003. GHS analysts see this recent transaction as "another large portfolio of assets to redevelop and add significant Brent priced production volumes."
Days before the acquisition in the North Sea, Apache reported results from two new wells in Egypt's Western Desert that it says "signal continued drilling success in the Faghur Basin and on concessions acquired in 2010."
A production test of the Cretaceous Alam El Buieb (AEB) sand in the Tayim South 1-X well in the Faghur Basin flowed at a rate of 8,196 barrels of oil per day.
The Tayim South 1-X well is the latest in a series of discoveries in the Faghur Basin based on Apache's interpretation of recently acquired 3-D seismic surveys across several of its concession areas, including the West Kalabsha Concession, where Apache owns a 100% contractor interest.
"The Tayim South discovery is located along a prominent east-west fault trend that stretches nearly 25 miles, all within Apache-operated concession boundaries, and includes productive intervals in the AEB, Safa and Paleozoic formations," said Tom Voytovich, vice president of Apache's Egypt Region. "We have drilled 13 exploratory tests along this trend during 2011, 11 of which were discoveries. We are planning five additional tests before year-end."
Tayim South 1-X is the highest-oil-rate completion Apache has tested since it began operating in the Western Desert in 1996.
The Lower Bahariya formation in the AG-90 development well in the Abu Gharadig Field, which was acquired in 2010, flowed 7,614 barrels of oil and 1.5 million cubic feet (MMcf) of natural gas per day during a completion test.
"The AG-90 well was drilled as part of an aggressive campaign to develop oil reserves in the Abu Roash and Bahariya formations in the Abu Gharadig field," said Voytovich.
The latest well encountered 189 feet of pay in six separate zones. It was completed with 18 feet of perforations from a total 84 net feet of oil pay in the Lower Bahariya and is currently producing 5,200 barrels of oil and 5 MMcf of gas per day.
Apache has drilled 11 successful wells in the Abu Gharadig Field since acquiring the properties, with oil production rising 20% to 24,000 barrels per day, and gas production increasing 70% to 60 MMcf per day. Existing facilities allow wells to be brought on production rapidly, although pipeline and mechanical issues have restricted condensate production.
Chevron to proceed with Wheatstone construction in Western Australia
On September 26, Chevron Corp.'s Australian subsidiary said the company will proceed with the construction of its Wheatstone Project in Western Australia.
John Watson, chairman and CEO, Chevron Corp., said, "The Wheatstone Project is a legacy, value-creating investment that will provide Chevron with significant reserves and production growth."
The foundation phase of the Wheatstone Project is estimated to cost US$29 billion (AU$29 billion) and consists of two LNG processing trains with a combined capacity of 8.9 million tons per annum (MTPA), a domestic gas plant and associated offshore infrastructure including the processing platform, subsea equipment, drilling and an export trunkline. First gas is planned for 2016.
The Wheatstone Project was granted final federal government approval for a 25 MTPA LNG development, paving the way for future expansion opportunities.
The Wheatstone onshore foundation project, located at Ashburton North, 7.5 miles (12 kilometers) west of Onslow on the Pilbara Coast, is a joint venture between the Australian subsidiaries of Chevron (operator 73.6%), Apache (13%), Kuwait Foreign Petroleum Exploration Co. (KUFPEC 7%) and Shell (6.4%).
The foundation project will be fed with natural gas from the Wheatstone and Iago fields, which are operated by an Australian subsidiary of Chevron in a joint venture with Shell and represents 80% of the plant's foundation capacity.
The Wheatstone hub concept was developed to provide foundation infrastructure for the commercialization of Chevron's natural gas resources as well as a destination for third-party gas. Under the hub concept, Apache and KUFPEC will provide the remaining 20% of the natural gas from their Julimar and Brunello natural gas fields, Carnarvon Basin discoveries made in 2007. Development of the two third-party fields is not included in the estimated project cost.
About 60% of Chevron's equity LNG off-take is presently covered under binding long-term agreements. Discussions are continuing with potential customers to increase long term off-take to more than 80% and to sell down equity.
G. Steven Farris, chairman of the board and CEO or Apache commented, "This is a long term, legacy asset. Apache will realize value over more than 20 years from its Julimar and Brunello gas discoveries, which combined have estimated recoverable gas in excess of 2.1 trillion cubic feet."
"Wheatstone also represents Apache's first project in the growing worldwide market for LNG, providing an additional pathway for premium pricing of our gas resources offshore Australia," Farris said. "It's also scalable, allowing for development of any future discoveries in the Carnarvon Basin, where we hold interests in several prospective blocks."
Argentina shale gets boost from ExxonMobil, Chevron
The government in Buenos Aires says that ExxonMobil will spend $120 million to help Argentina develop its shale gas reserves. The Texas-based company says the money will be used to determine how to develop known reserves in the Neuquen Basin.
Argentina has an abundance of shale gas trapped in subsurface formations, which the country wants to exploit since its conventional gas production has been declining in recent years due to lack of investment.
The US Department of Energy's Energy Information Administration (EIA) says that Argentina ranks third globally in shale gas reserves behind China and the United States. Earlier this year, the EIA estimated Argentina's shale gas reserves at approximately 774 trillion cubic feet, exceeding its conventional proved gas reserves, which are roughly 13.4 trillion cubic feet.
On Sept. 20, Argentine President Cristina Fernandez de Kirchner met in New York with Mark Albers, senior vice president of ExxonMobil. Argentina has been forced to import LNG in recent years to meet domestic needs, and Kirchner has stated that she wants to ramp up shale gas development to build energy supplies and perhaps turn Argentina into a gas exporter.
ExxonMobil sold a 90,000-bpd refinery and over 700 service stations in Uruguay, Paraguay, and Argentina in early 2011 in order to concentrate on developing gas in the Neuquen Basin. Ultimately, the Texas company plans to invest about $76 million in the project.
California-based Chevron Corp. also plans to team up with Argentina to develop shale gas reserves in the Neuquin Basin, according to an Argentine government minister who was in New York City for the opening on the United Nations General Assembly on Sept. 21. Chevron, one of the largest oil and gas producers in Argentina, also plans to look at other unconventional gas resources, such as tight sands deposits.
Argentine Planning Minister Julio De Vido met in New York with Ali Moshiri, president of Chevron's exploration and production in Africa and Latin America. Afterwards, De Vido issued a press release in which he said, "Energy companies have an enormous future in this area. All of the major oil companies know in detail the possibilities of unconventional gas and the fields of Neuquen."
Petrobras confirms oil and gas discovery in the Sergipe-Alagoas Basin
Petrobras has confirmed the presence of oil and gas accumulations in the ultra deep waters of the Sergipe-Alagoas basin, after completing a lined well formation test in the BM-SEAL-11 concession in Block SEAL-M-426. This is the first exploratory project in ultradeep waters on the Sergipe state area of the Basin.
The 1-BRSA-851-SES (1-SES-158) well, known as "Barra," is located at a water depth of 2,341 meters, 58 km off the Sergipe coastline and 90 km from the city of Aracaju.
The discovery was confirmed by wireline logging and fluid sampling during the lined well formation test. According to Petrobras, permeability and porosity conditions were found to be excellent in the reservoirs located at depths of around 5,050 and 5,400 meters. An oil sample showed API around 43 degrees in the upper interval and 32 degrees in the lower interval.
Exploration of the SEAL-M-426 block by the Petrobras (60%) and IBV-Brasil (40%) consortium will continue within the framework of the Minimum Exploratory Program agreed with the Brazilian Petroleum Agency (ANP).
Max Petroleum confirms oil at Uytas Field, Kazakhstan
Max Petroleum announced that the UTS-4 confirmation well in the Uytas Field, located in Kazakhstan, has reached a depth of 849 meters, with electric logs indicating 36 meters of potential net oil pay in the Cretaceous section at depths ranging from 30 to 158 meters, consisting of six sandstone reservoirs of excellent quality with porosities ranging from 25% to 35%.
This includes 16 meters of potential net pay in the shallow Cretaceous section between depths of 30 and 57 meters, which were not evaluated in the UTS-2 well because the equivalent interval was not logged. Significant oil shows were recorded continuously from depths of 20 meters to 167 meters, which appear to confirm the oil column seen in the original UTS-1 discovery well.
The company cored the UTS-4 well over the interval from 24 meters to 47 meters to allow further study of reservoir properties within this vertical column, with results from the core analysis expected during the fourth quarter of 2011.
Additionally, significant shows of oil and gas not observed in prior wells were recorded in the Kungurian salt near total depth of the well. The UTS-4 well was not designed to evaluate this interval, which will be investigated further in a future well. The Jurassic reservoirs found in earlier wells were not well developed at this location, however, and no pay was logged in the Jurassic section of the well.
The company is running production casing in the well, which will be completed and tested along with the other appraisal wells in the field in the next 60 to 90 days using a workover rig after obtaining the requisite governmental approvals. The company plans to acquire a high-fold 3D seismic survey over the Uytas structure in October 2011.
Robert B. Holland, executive co-chairman, commented, "We are encouraged by the results of the appraisal drilling program at Uytas, which supports the large vertical oil column observed in the discovery well and additional reserve potential in the Cretaceous above 100 meters. The oil and gas show below the salt was a pleasant surprise we plan to evaluate further through future wells and the development 3D seismic data we will acquire in October."
Gran Tierra confirms South American oil discoveries
Gran Tierra Energy Inc. has confirmed oil discoveries in South American exploration wells.
In Colombia, initial testing of the Melero-1 exploration well, located on the Garibay Block in the Llanos Basin, has been completed. The well spud on June 22, 2011, and reached total measured depth at 9,748 feet or 9,561 feet true vertical depth on July 16, 2011. Four drill stem tests were run and average production of 922 barrels of oil per day of 16.8 degrees API gravity with a 0.3% water cut was obtained from an interpreted 16 feet of net pay in the Upper Mirador reservoir. This well is currently suspended for long-term testing.
In addition, the Jilguero-2 appraisal well on the Garibay Block was spud on September 10, 2011. The well is located at the Jilguero oil discovery made by the joint venture between a subsidiary of Gran Tierra Energy and CEPSA Colombia SA, a wholly-owned subsidiary of Compania Espanola de Petroleos SA (CEPSA).
The joint venture is also in the process of acquiring an additional 80 square kilometers of 3D seismic data to assist in the evaluation of other structures identified on 2D seismic on the block.
Gran Tierra Energy, through an indirect wholly owned subsidiary, holds a 50% working interest in the Garibay Block while, CEPSA holds the remaining 50% and is the operator of the property.
In Argentina, the first of three exploration wells to be drilled in the Rinconada Norte Block located in the Neuquen Basin of Argentina has made a new discovery of oil, testing 1,023 barrels of oil equivalent per day (boe/d).
The RN x-1004 well flowed a total combined test rate of approximately 944 barrels of oil per day and approximately 0.5 million cubic feet per day of natural gas for a total of approximately 1,023 boe/d from two intervals tested separately in the Precuyo formation. This well also flowed 43 barrels of water per day or a 4% water cut.
Test and electric log data from the depths of the zones tested (3,222 - 3,255 feet and 3,353 - 3,386 feet) suggests a gross oil column thickness of approximately 197 feet. The oil is 29.6 degrees API gravity.
Having completed the first of the three exploratory wells, the service rig is set to move to complete and test the next two wells, which have already been drilled and cased.
Americas Petrogas Argentina S.A., the wholly-owned subsidiary of America Petrogas Inc., is the operator of the Rinconada Norte Block with a 65% working interest upon completing certain work program obligations, while Gran Tierra Energy, through an indirect wholly owned subsidiary holds a 35% working interest.
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