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The acreage acquired by 3Legs Resources in the Polish shale play in the Baltic Basin was “the pick of the litter,” according to Michael Lewis, 3Legs chief geologist. However, even the pick of the litter can lead to unexpected discoveries in learning how to best complete and produce wells in a new play.
“We’re on the frontier. We had the pick of the Baltic Basin. We’ve run three 3D seismic surveys. We’ve drilled four wells and two of those were horizontal. We have over one million gross acres. We have a partner -- ConocoPhillips. We have an unrisked estimate of gross resources in place of 170 trillion cubic feet (Tcf) of gas,” he said enthusiastically.
Only a dozen or so wells have been drilled in the shale play so far, Lewis told the Jefferies 2011 Global Energy Conference on Dec. 1 in Houston. His company drilled the first two horizontal wells and the results have been impressive and frustrating.
“Europe has an area of very large potential -- 700 to 1,200 Tcf. A whole lot of majors and large independents have come into the European theatre. The whole U.S. thing blew past most companies and now these are trying to get in and take advantage of the European play,” he stated.
The company has its acreage in the northern end of Poland around Gdansk. There is a trend that goes southeast in the Baltic Basin. “We picked the sweetest spot in the trend and still to this day, we are in the sweetest part,” he emphasized.
The shale in the area that 3Legs is drilling is at a depth of 2,500 to 3,500 m (8,250 to 11,550 ft). Going south in the basin, the shale goes down quickly to 5,000 m (16,600 ft) and the porosity seems to go away. There is also a higher risk for CO2.
“As you go northeast in the trend, you migrate into the wet-gas window. Further east, you get into the oil window. This is a great place to be. Liquids, of course, have extra value and there doesn’t seem to be any downhole reason why that would be a problem. That’s where we’re focused,” he said.
The first two horizontal wells -- Lebien and Warblino -- are where 3Legs learning went up very steeply. No modern logs had been run in Poland previously. There were, however, a lot of shale cores to study. Russians had drilled wells in Poland before, and the Russians paid their crews on the basis of cores. Even that didn’t prepare the company for what it found.
“As you go east, the maturity was originally defined as being the same type across the basin. Our drilling determined that was not the case at all. There was not a heat source on the east side of the window and that ended up being the oil window,” Lewis explained.
The first well, Lebien, encountered 115 m (380 ft) of net pay in the Ordivician. The well was about 4,000 m (13,200 ft) deep with a 1,000-m (3,300-ft) lateral in the Ordivician. Average porosity was 6% with 3.5% of total organic content (TOC).
The second well, Warblino, found 22 m (73 ft) of net pay in the Cambrian. The well depth was 3,800 m (12,540 ft) with a 500-m (1,650-ft) lateral. However, the porosity was 8.3% and the TOC was 11%. The Cambrian had superior rock quality that you don’t see in shales like this in the U.S., he noted.
“I want to talk about the fracs because that is really the story,” Lewis said. “We used Spectrascan logs because these tell you where the frac went. Our first well was fraced in a natural, primary-fracture network.
“This is the most fractured rock I have ever seen. Schlumberger said the same thing. Core Analysis said the same thing. These are all natural fractures that are the primary fractures where the sand went. Basically, we pumped sand into these fractures and never got to the matrix where the rock really is. The result was an initial production (IP) rate of 2.2 million cubic feet per day (MMcf/d) that rapidly ramped down to 450,000 cf/d.
“We basically drained the primary system but didn’t have enough matrix proppant to get into it. In this play, that’s probably not the way to do it. You need to drill either oblique or parallel to these fractures so you can get a lateral laid out and make the frac spread effective,” he continued.
In the second well, hole stability problems limited the lateral to 500 m. “We drilled a 1,200-m lateral. At this point, the well started heaving. I called it quits. We got the pipe out of the hole and went in to clean it. The hole collapsed on the pipe and we had to cut it off. We drilled another lateral. Unfortunately, I drilled it in the same direction because I hadn’t yet figured out what was going on because the log hadn’t been run,” he explained.
“We got to 500 m and the hole was unstable and we quit. We did get 500 ft of casing in the ground. We did do a frac. The Spectrascan showed we not only didn’t have a good cement job so our frac didn’t get diverted, but also, instead of going vertical, the frac went horizontally and spread the frac plane. It went into the rock plane. But, after the pressure was released, it collapsed again,” Lewis said.
“We’re dealing with all those issues now to determine what the best frac is going forward. We’ve certainly proved gas is there and we proved it will flow. We just need to get the frac right. You know you don’t get it right in the first well and the Lebien was our first well,” he emphasized.
In January and February, 3Legs will be meeting with ConocoPhillips in a “go-forward” meeting. ConocoPhillips carried 3Legs on three wells and three seismic surveys.
“ConocoPhillips has an option to pick up 70% interest by next March, leaving us with 30%. At that point, they would take over as operators,” he noted. “Frac redesign is probably the number one issue.”
From two to five wells are likely to be drilled in 2012, he added. Another 12 to 15 wells are expected to be drilled by other operators during the year.
“Unconventional oil and gas involves a lot of variables,” Lewis concluded. “It is a tough hill to climb. However, we are significantly ahead of where we would have been in the U.S. because of the core data and extreme amount of other data.”
Contact the author, Scott Weeden, at email@example.com.