A long-time Appalachian Basin player, Houston-based Cabot Oil & Gas Corp. has revised its strategy in recent years, expanding from its Appalachian roots, where long-life production is still an important part of the whole, to include activity along the Gulf Coast onshore, offshore and in the Rockies. This year, within the company's Gulf Coast region, Cabot plans to drill 37 wells-and 24 of those will be exploiting older fields. The remaining 13 are extensions to expand a field's boundaries, or wildcats. About 70% of the budget will be devoted to turning the drillbit, not counting expenditures for seismic, land or production facilities. Here's a look at two fields that figure prominently in the plans. Lake Pelto In Terrebonne Parish, Louisiana, this field lies in about 10 feet of water, between some barrier islands and the beach, in that zone where land and sea are hard to distinguish. Drilling must be done from a barge rig. Cabot acquired the property in January 1999 from Oryx Energy, which is now a part of Kerr-McGee Corp. "We purchased a number of fields at that time, but we feel we've had the greatest success at Lake Pelto," says Michael Walen, Cabot senior vice president who oversees the company's exploration and development drilling activity throughout the U.S. The numbers bear out that assessment. At the time of purchase, the field was producing about 7.5 million cubic feet of gas per day, gross, from 10 wells. After standard field exploitation based on looking at the seismic data again, Cabot has more than quadrupled production to a peak of 33 million a day. Of the six new wells Cabot drilled off the new seismic data, five were successful. They established some 44 billion cubic feet (Bcf) of new reserves, at a finding and development cost of about 80 cents per thousand cubic feet (Mcf). That includes drilling, completion, pipelines and all production facilities. The wells produce from Upper Miocene in the M, R and J sands. Depths range from 12,000 to 17,000 feet. In April, Cabot announced its latest success there, the #4-19, flowing to sales at the rate of 15 million cubic feet a day from an Upper Miocene sand. "All the new production is in the same zones that are productive in the area, but we did tap into a new fault block that had not previously been recognized," Walen says. "These are not overpressured sands, so we could drill the wells fairly quickly. It's all been fairly uneventful on the drilling side." Reprocessing old seismic data has been the key to Cabot's success at Lake Pelto. "There was some 3-D data on Lake Pelto when we acquired it, but it was pretty rough. We reprocessed the data and saw some seismic amplitudes that had not been exploited by Oryx," he says. "Our team was really able to identify these opportunities early by recognizing that the seismic suggested something else. We thought there was enough encouragement that we were able to make the right bid on the properties. Our team then worked to reprocess and reinterpret the 3-D." Walen credits the multidisciplinary Lake Pelto team, including reservoir engineer Tom Huebinger, geologist Lindsey Tade, geophysicist Mark Steele and landman David Boudreaux. Cabot closed the deal on January 1, 1999, but did not complete its first well on the property until April 2001, as it took more than a year to reprocess the data, work up the prospects and drill. The company just drilled the sixth well recently but had to plug and abandon it. "You drill the best-looking prospects first and leave the ideas you're a bit nervous about until the end," Walen says. "Of course with product prices where they are today, you're willing to take a bit more risk in your drilling programs. "At this point we have fully developed the field and have no further plans to drill. We estimate it will produce another 15 years or so, on a relatively flat decline. No fracture stimulation has been required, just the standard perforation job. We put in satellite platforms with separation tied back to our main production facilities." Cabot owns the older part of the field 100%, but on the new wells it owns 75%, with Houston-based partner Palace Exploration. The western part of the field was discovered by Texaco and recently purchased by Burlington Resources. The latter participated in Cabot's dry hole and operates one other well in a joint unit with Cabot. "Lake Pelto has been very profitable. I think it's one of the success stories in our acquisitions effort. We have a lot of behind-pipe reserves there, so we'll do workovers as time goes on. It's a nice little field." Raymondville Field Cabot has enjoyed success as well at the Raymondville gas field in Willacy County, South Texas, where it has quadrupled production based on new seismic interpretation. It bought the property in August 2001 from Denver-based Cody Energy. At that time, the field had cumulative production of about 106 billion cubic feet equivalent (Bcfe) from about 100 wells. It was producing 9.5 million cubic feet of gas a day, gross, from multiple stacked Miocene and Frio pay sands between 4,000 and 10,000 feet. Cabot has grown production to about 35 million a day. "Since we bought the field, we've drilled 25 more wells with only two having been plugged and abandoned-we have not drilled a dry hole since the middle of last year." Once again, he credits a team-Huebinger, geologist Tony Venditti, geophysicist Dave Homan and landman Tyler Woodruff. They reprocessed and interpreted the 3-D seismic data to exploit Raymondville, which is characterized by complexly faulted stratigraphy. Seismic data is an essential tool to develop a deeper understanding of the subsurface. "After the acquisition, our geophysicists worked very hard on velocity variations we saw within the field. We thought we could improve the velocity control and pick better well locations," Walen says. The result? Given current gas prices and finding costs of around $1 per Mcf, the rate of return is in the 60%-plus range, he says. The average well finds 1- to 1.5 Bcfe and initially produces 1- to 4 million cubic feet a day. "The wells have very steep declines initially and then they flatten out. We do multiple completions and occasional fracs. Some of the wells have three, four sands and others have up to a dozen thin pays that do produce at economic rates." In addition to drilling 25 new wells, Cabot performed 64 capital workovers to tap behind-pipe reserves in existing wells from September 2001 through March 2005. Explains Walen, "Our workover program has been very successful in capturing these behind-pipe reserves and turning them into producing assets. Our geologists and reservoir engineers have done a great job identifying new reserves that had not been booked by Cabot at the time of the acquisition. "We knew the sands were there but did not know what constituted a pay sand or not. Over time we found that many low-resistivity sands were actually pay sands. As we developed the field, our average workover contributed about 720,000 cubic feet equivalent per day to our production stream." Cabot reprocessed a lot of data with new technology and as it learned more, it reprocessed more-there were a lot of iterations, he adds. In 2005, Cabot plans to drill six new wells in Raymondville Field." We aren't done with the field yet. We think there are still more opportunities, based on our results to date."

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