DENVER, Feb. 21, 2012 /PRNewswire/ — Grid Petroleum Corp. (OTCBB: GRPR) The Board of Directors are pleased to announce that Grid Petroleum has entered into a Joint Venture Development Agreement with a private holding company, to develop a Mutual Area of Interest in the Northwest Premont Field in Jim Wells County Texas. The Field covers 4,500 acres and is part of the Gulf Coast Trend in South Texas.
Reserves are estimated to contain over 20 million barrels of oil (bbls) and 20 billion cubic feet (bcf) of natural gas from as many as 15 potentially productive zones per well. The initial phase of the Development Agreement outlines the drilling and completion of 20 new wells and the re-entry of 8 additional previously drilled and completed shut-in wells.
The company had previously announced negotiations to purchase the private holding company, however it has been determined a Joint Venture Development Agreement will serve the company and its shareholders more beneficially in the near term.
Grid Petroleum will begin participation with the second well to be drilled under the Joint Venture Development Agreement at a level of 10% for an investment of $152,000.
Grid has the opportunity to make the Companies first investment into the Joint Venture after the results of the first well-drilled and completed are available for analysis, greatly reducing the risk of the investment by Grid Petroleum into the entire field.
The purpose of the development of the Northwest Premont Field is to create value and income by re-entering certain wells, which have been tested and have proven oil and gas producing zones, and the drilling of strategically located wells containing multiple zone production in a manner that produces high rates of stable production; proving the reserves of the underlying pay zones for further development of the field through production.
To date the fields operator has re-entered two wells, the Guerra #2 and the Garcia #2. The Guerra #2 was drilled to 4,000 feet and tested positively for oil and gas in 12 potentially productive sand zones encountering 118 net feet of pay.
AP Yang, Petroleum Engineers of Houston Texas ran 45 days of open flow tests to draw down the pressure of each of the productive zones in the well. The absolute open flow rate calculations indicated the lobe flow of the Laughlin oil sand deposit tested at 15,541,000 cubic feet gas per day. The upper lobe flow tested at 5,063,000 cubic feet peer day. The combined total of 20,604,000 cubic feet per day from 16 feet of net pay zone for this one well with multiple pay zones.
Preliminary Reserves Estimates for the Guerra #2 are 100,000 to 150,000 Barrels of oil and 1.5 Billion Cubic Feet to 2.5 Billion Cubic Feet of natural gas.
The second re entry well the Garcia #2 is co-mingling two gas zones with production averaging 1.0 million cubic feet of gas per day. An Oil zone is also producing an average of 39 barrels of oil per day. Reserve estimates for the Garcia #2 will have similar potential production levels as the Guerra #2.
The current price of gas ranges between $2.75 and $3.00 per mcf.
20 million cubic feet per day of gas production represents a potential gross of $60,000.00 per day.
Grid Petroleum Corp is a development stage company focused on the acquisition and development of low cost high reward oil and gas prospects with infield drilling for proven potential reserves in the United States and Canada.
The company anticipates the initiation of a development plan with its joint venture partners for the purpose of establishing suitable drill sites for the Kreyenhagen Trend leases.
Upon completion the company will have established a time line for the development of its significant Oil and Gas assets.
St. Helena well’s initial production spurs interest
The Encana Weyerhauser well, completed in November, averaged 784 barrels of oil per day and 309,000 cubic feet of natural gas, according to Encana’s filing with the state Department of Natural Resources.
“This is certainly a key well. There’s no doubt,” said Dan Collins, a Baton Rouge landman who spent much of last year negotiating lease agreements with landowners in the shale.
“You know, 800 of anything coming out of the ground daily is a lot,” Collins said.
That’s especially true when the anything in question fetches nearly $100 a barrel.
Around two dozen wells have been drilled or are being drilled in the Tuscaloosa Marine Shale, an oil-rich formation that covers Louisiana’s midsection. Energy companies have leased more than 1 million acres in the formation, but so far the firms aren’t sharing much of their early production figures.
Kirk A. Barrell, president of Amelia Resources, of Texas, said before the formation can be considered economically viable, 10 to 20 wells will have to be completed.
“You need the initial (production) rates for 10 to 20 wells, but you also need to get 12 to 15 months out and see what the decline of that rate is,” Barrell said.
Still, Collins said it appears the energy companies believe they have something.
Oil companies have proposed a number of wells and discussed putting multiple drilling pads on landowners’ property, Collins said. The shale’s future remains to be seen, but there probably wouldn’t be so much activity if the energy companies didn’t believe their investment is worthwhile.
Encana has leased around 270,000 acres in the play, has completed one horizontal well, and has two new wells under way, according to its investor presentations.
Encana spokesman Alan Boras said he could not discuss any details of the company’s Tuscaloosa wells.
But the company will release more information during its fourth-quarter earnings report, scheduled for Feb. 17, Boras said.
A lot of people think every well in the Tuscaloosa should produce 1,000 barrels a day, but it takes time for drilling companies to figure out the best approach, Barrell said.
Barrell, the author of a blog on the Tuscaloosa Trend, said people forget or don’t realize that the early results varied from wells drilled in the Eagle Ford Shale in Texas.
While there were a few good wells whose maximum production was around 1,000 barrels per day, there were a number of wells whose daily production never reached double figures, Barrell said.
Collins said in order to recover the millions in drilling costs, a well’s initial production has to be pretty strong because the production curve declines pretty rapidly.
Shale wells’ production rates generally fall about 75 percent after 12 months.
“I liken it to a ski slope. We certainly don’t want the black ski slope. We want one of those greens or blues that’s going to … gently drop over time,” Collins said.
Gifford Briggs, vice president of the Louisiana Oil and Gas Association, said the Encana well’s results will encourage additional testing.
But it’s difficult to say how significant the well is without knowing the costs and how long the well will continue producing at the same rate, Briggs said.
In this early phase, Encana and other companies operating in the Tuscaloosa are still trying to answer a number of questions, such as what is the right depth to drill and how to get the most effective fracture, he said.
Wells in the Tuscaloosa are drilled vertically for around 11,000 feet and then horizontally. Drillers then fracture the formation in multiple stages, forcing millions of gallons of water, mixed with sand and/or ceramic and chemicals into the formation to crack the shale. The sand and ceramic materials prop the cracks open, releasing the oil.
Fracking has drawn criticism from environmentalists and some landowners, who say the practice pollutes the air, contaminates water and consumes too much water. The oil and gas industry’s position is that fracking has been used for more than 50 years on thousands of wells with no evidence of groundwater pollution.
Collins said leasing activity in the area has slowed this year as companies have turned to drilling, but Barrell said his firm and its partners are still actively leasing.
Lease prices in the Tuscaloosa Marine Shale, compared to other shale plays, remains a “great, great value,” Barrell said.
Last year, leases were going for around $150 an acre.
Briggs said he has heard that leases are fetching $250 to $500 per acre.
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