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THE EXPLORERS 2004: XTO steps up pace of Cook Inlet drilling Fort Worth-based independent buys existing fields with complex geology, adds to production Kay Cashman Petroleum News
Activity for XTO Energy’s operations in Cook Inlet was up in 2004. The company, which employs 30 people in its Nikiski office on Alaska’s Kenai Peninsula, drilled just one well in 2003, a horizontal sidetrack, as compared to three sidetracks expected to be drilled by the end of 2004 from its two offshore platforms.
XTO’s wells are expected to be the only wells drilled offshore in the Cook Inlet basin in 2004.
Lindsey Dingmore, Fort Worth, Texas-based XTO’s manager of governmental and regulatory affairs, told an Alaska legislative committee in April 2004 that decline curve management is important for XTO and that at its Middle Ground Shoal platforms production is long-lived and, along with oil production from the Permian basin, helps the Fort Worth company balance its quickly declining East Texas gas wells.
XTO is “not really an exploration company,” Dingmore said, but is “the kind of company that the majors look to when they are selling assets” that no longer fit their portfolios, but where a smaller company can come in and do “a lot of the work in terms of in-fill drilling and development.”
Goal to keep production flat “A good acquisition company must be a great development company,” and XTO tries to double reserves at the properties that it buys, Kyle Hammond, XTO’s top executive for Alaska, told the same committee.
That is close to what has happened at Middle Ground Shoal, he said, and as a result, production from the A and C platforms has remained almost constant since the company acquired the platforms in 1998 from Shell.
Shell installed the platforms in 1964 and 1967; Unocal installed the other two platforms at the field, Baker and Dillon, in 1965 and 1966. Both of Unocal’s platforms have since been shut-in.
About 90 percent of XTO’s production is natural gas, Hammond said, and its oil properties in Alaska and the Permian basin in Texas have flatter decline curves that help balance declines from other areas.
XTO doesn’t buy companies, it buys oil and gas and it looks for “long-lived, high-margin-properties,” he said. The high-margin part of the company’s equation is important, so it can “continue to operate in a low-price environment.”
XTO also looks for geologically complex reservoirs. If “it’s very simple, anybody can find it,” but “in geologically complex reservoirs, the probability that the previous operator missed something goes up dramatically,” Hammond said. “We want to buy properties that as we continue to add capital into these properties, we can keep the decline essentially at zero.”
Combined, the company’s two Cook Inlet platforms average 3,700 barrels per day, Hammond said in April 2004.
Output dropped to 3,600 barrels per day in mid-2004; something Hammond said he expected the 2004 sidetracks being drilled in the second half of the year to correct.
XTO has invested some $50 million to keep the decline curve flat, and plans to invest $8 million in 2004 and $7 million in 2005 at Middle Ground Shoal. (in 2005 Hammond said two sidetracks are planned.)
West flank tipped on end Shell had developed the east side of the reservoir at Middle Ground Shoal. Hammond said on the east side “the rock is significantly better rock, with more oil in place and more permeability — the ability of the oil to flow to the wells — and it’s much easier to drill.” On the east flank, where Shell worked, the structure is “relatively flat.”
The west flank, where XTO has worked, is on the other side of a major north-south trending fault, and tectonic activity has essentially turned the strata on the west side of the field “on end,” he said, so when XTO drills on the west side, it drills directionally, penetrates the formation, then goes back and penetrates it again on the bottom side of the well.
“The wells are a lot more expensive to drill that way and technically more of a challenge,” Hammond said, “but it’s what makes drilling a well on the west flank economically viable.”
Costs vary from $2-$4 million a well to as high as $7 million, he said. The company had drilled eight wells as of Oct. 1, 2004, including some drilled as injection wells, and has also converted wells to injection to “artificially pressure the reservoir and move the oil to our producing wells.”
That’s another thing the company liked about Middle Ground Shoal: “This is essentially a water flood that’s out under the water. It’s a very similar water flood to what we do in the Permian basin of West Texas,” Hammond said, “it just happens to be in a little bit more challenging environment, but the basic reservoir rocks and the basic water flood is something that this company’s done for years …,” and the field fits well with XTO’s portfolio.
Although, he said, it’s a bit of a challenge to water flood in a vertical environment.
Costs going up The Alaska Legislature passed a royalty reduction bill for Cook Inlet oil and gas properties in 2003, and Dingmore said XTO’s properties ended up in a category where royalty relief would be applied at 975 barrels.
He said XTO anticipates that it is a few years away from that production level, but said costs are a concern.
Since Unocal has shut-in its Baker and Dillon platforms at Middle Ground Shoal, “that’s caused us to take control of some onshore properties, some pipelines that we were sharing with them,” and thus taking on additional cost (see sidebar on coalbed methane).
Average production from its new wells has been 400 barrels per day, but that ranges from zero (one well was a dry hole) to 1,200 bpd, with average reserves per well drilled of 750,000 barrels, ranging from zero to some that are “much greater,” Hammond said.
We like being here, he told the committee, but “one of the things that I try to explain to people is this reservoir has an inherent risk that does make it very challenging for us to present projects to our management.”
Editor’s note: Cook Inlet production — onshore and offshore — declined from a peak of 225,701 barrels per day in 1970 to 29,267 bpd in 2003, according to the 2003 annual report from the Alaska Division of Oil and Gas.
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