Discoveries made in 2011 will help support O and G production in the decades to come. Here’s is a look at some of the most significant discoveries of 2011.
Peak oil production is not expected to be reached any time soon, according to a Dec. 8, 2011 MENAFN.com report. Although a number of experts at the World Petroleum Congress did warn that the world “oil and gas demand must decline if energy prices and population sustainability are to remain stable.”
The report quotes Marco Rasi, vice president, Asia Pacific/Established Areas, ExxonMobil Development Company, who said “estimates of global endowments of hydrocarbons are around 4T boe, of which three are conventional oil and 1T is in heavy oil and shale. Since the beginning of the industry, only 1T barrels have been produced.”
Discoveries made in 2011 will help support oil and gas production in the decades to come. Some of the most significant discoveries of 2011 are discussed below.
Repsol YPF announced on Nov. 7, 2011, that it had made the largest oil discovery ever in Argentina. The operator said it found 927 MMbbl of shale oil in the Vaca Muerta basin of Argentina’s Neuquen province.
Repsol YPF also has begun exploratory and production activities in another discovery made in December 2010, in a 502 sq km producing area in the same Vaca Muerta formation. The well is producing 400 boepd of high quality shale oil (35° API). The operator said in a statement, “this new area has significant potential for large volumes to be developed in the future once the appropriate studies and preliminary work to determine resources is completed.”
Apache made a major gas discovery in April 2011, 100 km off the Western Australian coast at its Zola-1 well in the WA-290-P exploration permit. According to a statement from OMV, the discovery well Zola-1 and the subsequently drilled sidetrack appraisal well Zola-1/ST-1 confirmed the existence of sandstone layers with 427 feet (130 m) of net gas pay in an area south of the giant Gorgon gas field. The operator planned to acquire new 3D seismic data to further assess the potential of the discovery.
“Zola-1 is one of OMV’s biggest gas discoveries and is the result of a successful and safely carried out exploration and appraisal drilling campaign,” said Jaap Huijskes, member of the OMV Executive Board responsible for Exploration and Production (E&P).
The WA-290-P joint venture partners include operator Apache with 30.25 percent interest, Santos with 24.75 percent interest, OMV Australia with 20 percent interest, Nippon Oil Exploration with 15 percent interest and Tap Oil with 10 percent interest.
Total EP Norge AS announced in August 2011 that it had made a major gas discovery at production license 535, well 7225/3-1, in the Barents Sea.
Seadrill’s West Phoenix (UDW semisub) drilled the well in 1,234 (376 m) of water. The operator ran a formation test in the upper part of the Kobbe formation. The maximum production rate was 180,000 standard cubic meters per day (scmd) of gas through a 44/64-inch nozzle. According to Total, the gas contains only small amounts of CO2, H2S and N2. The results from the well will be included in the ongoing evaluation of “Norvarg” to establish the size and extent of the gas discoveries.
The well was drilled in 1,234 feet (376 m) of water and is the first exploration well in production license 535. The license was awarded in the 20th licensing round in 2009.
ExxonMobil announced a major discovery in June 2011. According to a statement, the KC919-3 wildcat well confirmed the presence of a second oil accumulation in Keathley Canyon block 919. Drilling with the rig Maersk Developer (UDW semisub), the well encountered more than 475 feet (145 m) of net oil pay and a minor amount of gas in predominantly Pliocene high-quality sandstone reservoirs. The well, which is drilling deeper, is 250 miles southwest of New Orleans in 7,000 feet (2,133 m) of water.
ExxonMobil drilled the KC919 well and extending into KC918 in early 2010, which encountered over 550 feet (168 m)of net oil pay and a minor amount of gas in high-quality Pliocene and Upper Miocene sandstone reservoirs. Previously, the operator encountered 200 feet (61 m) of natural gas pay in Pliocene sandstone reservoirs at its Hadrian South prospect in Keathley Canyon block 964 with the Eirik Raude (UDW semisub) during drilling in 2009.
“We estimate a recoverable resource of more than 700 MMboe combined in our Keathley Canyon blocks,” said Steve Greenlee, president of ExxonMobil Exploration Company. “This is one of the largest discoveries in the Gulf of Mexico in the last decade. More than 85 percent of the resource is oil with additional upside potential.”
ExxonMobil is the operator of KC918, KC919, KC963 and KC964 with 50 percent working interest. Eni Petroleum US LLC and Petrobras America Inc. each hold a 25 percent working interest in KC919, KC963 and KC964. Petrobras America Inc. holds a 50 percent working interest in KC918.
Heritage Oil announced a major discovery in the Kurdistan Region of Iraq in January 2011. The operator estimated that the Miran West structure had P90-P50 gross in-place volumes of gas of between 6.8-9.1 trillion cubic feet (Tcf) with 42-71 MMbbl of condensate and 53-75 MMbbl of oil.
Heritage currently is considering potential development options that could include either bringing gas into Turkey and/or into Europe via the Nabucco pipeline. The company expects first production in 2015.
Tony Buckingham, CEO, said, “The discovery of a major gas field of up to 12.3 Tcf in-place with exceptional flow rates makes this one of the largest gas fields to be discovered in Iraq.”
Petronas announced in a statement in February 2011 that it had “made major oil and gas discoveries through the drilling of NC3 and Spaoh-1 wells in Blocks SK316 and SK306 offshore Sarawak.”
The operator drilled the NC3 well in March 2010 and followed up with the appraisal well, which proved the NC3 well as a significant discovery. The operator’s early estimation put the find at 2.6 trillion standard cubic feet (tscf) of net gas in place.
The operator said its Spaoh-1 well reached 3,000 m drilling depth in Block SK306 and shows similar promise. Petronas drilled the well in December 2010 and found about 100 MMbbl of oil and 0.2 tscf gas.
Petronas Carigali Sdn Bhd then made a significant oil discovery offshore Sabah in November 2011. The Wakid-1 well in Block 2G-2J is 100 km northwest of Kota Kinabalu. The operator spudded the well on May 30, 2011 and completed it on July 4, 2011. According to the operator’s statement, the well reached 3,330 m total vertical depth (TVD) and confirmed the presence of significant oil and some gas-bearing, reservoirs. Petronas conducted three production tests in three different reservoirs, which flowed oil at a combined maximum rate of 8,200 bpd.
The operator estimates 227 MMboe of hydrocarbons-in-place from this discovery with expected upside potential. Petronas Carigali plans to further appraise the discovery. Wakid-1 is the second well Petronas drilled in Block 2G-2J since the award of its Production Sharing Contract (PSC) in October 2010. The operator drilled the block’s first well, Tambuku-1, early this year, but it yielded only minor gas discovery. Petronas Carigali is the sole equity holder of the PSC for the block.
On Oct. 20, Eni announced a giant natural gas discovery at the Mamba South 1 prospect, in the Area 4 offshore Mozambique. The discovery well encountered 696 feet (212 m) of continuous gas pay in high-quality Oligocene sands.
The Mamba South 1 discovery well is in 5,200 feet (1,585 m) of water approximately 25 miles (40 km) off Cabo Delgado coast, in Northern Mozambique. This was the first exploration well in Area 4. Results exceeded pre-drill expectations and confirmed the Rovuma Basin as a world-class natural gas province.
Just seven days later, Eni announced that its discovery was about 50 percent larger than what was previously announced by the company on Oct. 20.
While deepening the well, it found a new separated pool that potentially contains up to 7.5 Tcf of gas-in-place in clean sands from the Eocene age. The new section contains about 295 feet (90 m) of gross gas pay, which was cored.
The operator said that front-end activities on the discovery have commenced. Eni believes that the discovery may hold up to 22.5 Tcf of gas-in-place in the Mamba South Area.
Eni operates the area with a 70 percent interest; Galp Energia holds 10 percent; KOGAS holds 10 percent; and ENH holds 10 percent, carried through the exploration phase.
Anadarko also expanded its offshore Mozambique portfolio in 2011 with its fourth discovery in the Rovuma Basin in February.
The Tubarao discovery is 2,950 feet of water. The Tubarao discovery well encountered more than 110 net feet of natural gas pay and no water in a high-quality Eocene-age reservoir that is separate and distinct from the hydrocarbon accumulations in Anadarko’s three previous discoveries in the Rovuma Basin.
The operator went on to discover the Camarao prospect in October 2011. Camarao also is in the Offshore Area 1 of the deepwater Rovuma Basin offshore Mozambique. It is 4,730 feet (1,442 m) of water. Anadarko encountered about 240 feet (73 m) of natural gas pay in an excellent-quality reservoir. Additionally, the well found about 140 feet (43 m) of natural gas pay in shallower Miocene and Oligocene sand packages not previously encountered in wells. Drilled by the Belford Dolphin (UDW drillship), the well reached 12,630 feet (3,849 m) total depth (TD).
Anadarko operates the basin, which is also home to Barquentine, Windjammer and Lagosta, with a 36.5 percent working interest. Co-owners in the area are Mitsui E&P Mozambique Area 1, Limited (20 percent), BPRL Ventures Mozambique B.V. (10 percent), Videocon Mozambique Rovuma 1 Limited (10 percent) and Cove Energy Mozambique Rovuma Offshore, Ltd. (8.5 percent).
Anadarko announced in November 2011 a huge shale discovery at its Horizontal Niobrara and Codell drilling program in the Wattenberg field (Wattenberg HZ) of northeastern Colorado.
“Based upon the early results of Anadarko’s program in the Wattenberg field, we are confident the liquids-rich Horizontal Niobrara and Codell opportunity provides a net resource potential of 500 MMbbl to 1.5 Bboe; and it’s located right in the heart of one of our existing core areas,” Anadarko Sr. Vice President, Worldwide Operations, Chuck Meloy said in a statement.
Jaime Kammerzell is an experienced upstream and downstream O&G journalist who has worked for many of the top petroleum publications. Email Jaime at [email protected]