The U.S. Energy Information Administration (EIA) said in a report that the U.S. dry natural gas production has increased since late 2005 due mainly to rapid growth in production from shale gas resources. However, there have been two notable instances (see red ovals in the chart) in the last seven years when natural gas production leveled off during a period of falling spot natural gas prices.
The first was during the recent economic recession and the latest began in the fourth quarter of 2011 and continued through the first quarter of 2012.
Weather events (see green ovals) have also affected U.S. natural gas production.
The major events over the past seven years that have caused dry gas output to level off or even decline include:
- Hurricanes Katrina and Rita (Sep-Oct 2005) – Disrupted up to 12.2 billion cubic feet per day (Bcf/d) in offshore natural gas production.
- Hurricanes Gustav and Ike (Sep 2008) – Disrupted up to 9.5 Bcf/d in offshore natural gas production.
- Economic recession and falling prices (Oct 2008- Sep 2009) – Reduced industrial and manufacturing activity, and lower electricity use eased demand for natural gas as a feedstock and a power generation fuel. Natural gas prices fell sharply as a result.
- Winter well freeze-offs (Feb 2011) – Disrupted up to 7.5 Bcf/d in natural gas production from Texas to Arizona, when water froze inside wellheads during extremely cold weather and blocked gas flows.
- Supply overhang and falling natural gas prices (Oct 2011-Mar 2012) – A warm winter that reduced heating fuel demand and record high gas inventories resulted in a nearly 50% drop in gas prices, causing some energy companies to postpone new drilling and cut back on some existing operations.
Natural gas production was relatively flat between October 2011 and March 2012, when Henry Hub spot gas prices declined from just above $3.50 to around $2.00 per million British thermal units in March. Preliminary EIA data indicate a slight drop in production during March, according to the Natural Gas Monthly report released on May 31.
Of the five large gas-producing states tracked monthly by EIA—Texas, Louisiana, New Mexico, Oklahoma, and Wyoming—New Mexico had the highest percentage decline in its March gross natural gas production, down 2.2 percent from the previous month, while Texas had the largest volumetric drop, down 150 million cubic feet per day. States that EIA does not presently track on a monthly basis, such as Pennsylvania, may have seen their gas output increase during March.
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Niko will partner with Zaratex N.V. in the 5908km2 Lhokseumawe PSC in western Indonesia. The block is located directly adjacent to the giant Arun field (>3.1BBOE) and associated LNG plant. A 3865km2 3D program was acquired on the block and a number of high impact prospects were subsequently identified. Drilling is to commence in the shallow water portion of the block in April with two wells. The Candralila-1 and Ratnadewi-1 prospects will be drilled back to back and if successful will be monetized relatively quickly by accessing the existing extensive local infrastructure.
Niko’s deep water rig, the Diamond Ocean Monarch, is scheduled to arrive in Lhokseumawe in September to drill the Jayarani-1 well. This will be the first well in Niko’s planned program of more than 25 deep water wells in Indonesia. In addition, in the North Ganal PSC in which Niko is a participant, operator Eni will be using the Transocean Seven Seas to drill the Lebah-1 well in the second half of 2012. The Lebah prospect will test the extension of the Jangkrik and Jangkrik-NE discovery trend (>400MMBOE of reserves to date). Eni has already filed a POD for the development of these discoveries and first production is expected in 2015.
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The partnership announced today that it has made a high impact discovery in the Pão de Açúcar prospect located in the BM-C-33 block in the Campos Basin. The well, drilled by the Stena DrillMAX drillship, is located some 195 kilometres offshore Rio de Janeiro State in 2,800 meters of water.
The Pão de Açúcar well encountered two pre-salt accumulations comprising a hydrocarbon column of 480 meters with a total pay of around 350 meters. A test performed in a partial section of the pay zone flowed 5,000 barrels per day of light oil and 28.5 million cubic feet per day of gas. This was a choked Drill Stem Test (DST) with very limited drawdown. The Pão de Açúcar discovery is the third find made in the BM-C-33 block after Seat and Gávea and confirms the area’s high potential.
“The development potential of the Pão and Gávea discoveries will now be evaluated by the partnership. This discovery increases our understanding of the pre-salt potential in the Campos Basin and improves our confidence in the recently acquired acreage position in the pre-salt Kwanza basin of Angola,” says executive vice president for Exploration in Statoil, Tim Dodson.
“Statoil’s exploration strategy focuses on high impact opportunities and the deepening of core areas. The Pão de Açúcar success shows that we are delivering on our strategy,” continues Dodson.
“Statoil has clear ambitions to grow in Brazil through new exploration opportunities. The Pão discovery will become an important building block in our growth ambitions,” says Kjetil Hove, country president for Statoil in Brazil.
Repsol Sinopec is operator of the exploration consortium with a 35% stake. Partners Statoil and Petrobras hold respective 35% and 30% shares.
Statoil is also the operator of the Peregrino field in Brazil, which came on stream in April 2011.
The Pão discovery is the sixth high impact discovery made by Statoil in the last 12 months. The other discoveries are Skrugard and Havis in the Barents Sea, Johan Sverdrup (former Aldous/Avaldsnes) in the North Sea, Peregrino South in Brazil and Zafarani in Tanzania.
(*) ”High-impact well” = a total of more than 250 million barrels of oil equivalent (boe), or 100 million boe net to Statoil.
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Drilling operations are still on-going and it is too early to give any indication of size and commerciality, Statoil said in a statement.
The well was spudded in early January 2012 and drilling operations are expected to take up to a total of 3 months to complete.
The well is being drilled by the drill ship Ocean Rig Poseidon and is located some 80 kilometers off mainland Tanzania.
It is the first exploration well that has been drilled in the license which covers an area of approximately 5,500 square kilometers. The water depth at the well location is 2,582 meters and the well itself is planned to reach a total depth of 5,150 meters.
Statoil operates the license on Block 2 on behalf of Tanzania Petroleum Development Corporation (TPDC) and has a 65% working interest with ExxonMobil Exploration and Production Tanzania Ltd. holding the remaining 35%.
Statoil has been in Tanzania since 2007 when it was awarded the license for Block 2.
“TPDC is pleased about these preliminary results and is eagerly awaiting further information on this operation,” says Yona Killaghane, Managing Director of TPDC.
The final assessment of what has been encountered will be released at a later stage once drilling operations have been completed and the well results fully analyzed, Statoil said.
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Britain’s Cove Energy PLC believes its offshore Mozambique Rovuma block it is exploring has an upside potential of 40 trillion cubic feet of gas, almost triple the 11 tcf it has proven, the company’s chairman said on Tuesday.
“We believe to date that we have already proven up more than 11 tcf, however Cove estimates the overall potential of the (Rovuma offshore Mozambique) block only to be more 40 tcf . and the total potential for East Africa is easily 100 tcf,” Michael Blaha, executive chairman of Cove Energy, told an African oil and gas conference on Tuesday.
Oil and gas companies, including U.S. firm Anadarko , are flocking to the southern African nation following huge gas finds.
Blaha said the first gas from Mozambique was eyed for 2018, with the first LNG gas trains likely to supply the growing Asian market.
“The Mozambique LNG project alone could be a game-changer for the LNG industry,” he said.