Unconventional Gas Demands Learning What Practices Work Best

(Tech Connections Column, January 2005, American Oil and Gas Reporter)

Unconventional gas is certainly one focus of domestic explorationists. It helps to clarify the question: What is unconventional gas? There are the obvious such as methane hydrates, but that is for the future. Tight natural gas, extremely deep gas, coalbed natural gas and shale gas are for today. Unconventional gas contributes significantly in nine of the 12 largest U.S. natural gas fields.

Unconventional gas was the focus of an “emerging technologies conference” organized by the Independent Petroleum Association of America with support from PTTC and the provider community following IPAA’s annual meeting in Austin, Tx. Through this column I want to convey technology insights that were shared. Those interested in details can access the presentations online at www.ipaa.org/press/Presentations.asp?G=12.

In some areas shale gas and CBG plays are well developed (Barnett Shale, San Juan Basin CBG, Powder River Basin CBG, Arkoma Basin CBG to name a few), while other areas are still relatively undeveloped (Woodford Shale in Oklahoma, Illinois Basin CBG, Gulf Coast CBG are examples). As industry works to deliver needed gas supplies, companies are working hard to apply lessons learned as they move forward in new areas.

Jeffrey Eppink with Advanced Resources International noted that it was “new strategies and technologies, which contribute to continued significant reductions in drilling time and cost, that are helping to convert ‘unconventional’ resources into reserves.” He cited an example of reducing drilling time in one East Texas Cotton Valley field by more than 50 percent, while at the same time significantly increasing initial production and ultimate recovery.

Rod Nelson with Schlumberger challenged listeners to understand reservoirs at a whole new level, using data mining techniques to work on the right wells in existing fields, and finding novel ways or smarter places to apply new or existing technologies in new completions. Using Schlumberger’s PressureXpress tool to affordably measure pressure in multiple zones to guide subsequent completion and stimulation design in tight gas wells is one example he gave. Tests with PressureXpress can be done in a minute, a significant improvement over past technology.

Most now recognize that drilling, completion and operations practices for different basins will be different. With unconventional gas typically requiring many wells, it is important economically to find the best drilling, completion, stimulation and operations practices early in field development, rather than thinking, “We should have done it this way,” after most wells have already been drilled.

The Barnett Shale is present in Johnson County, TX., but the area is missing the Viola and Forestburg fracture barriers that help keep fracs from going into the Ellenburger. As Hallwood Energy started developing its Johnson County properties, it knew it faced a learning curve. But by systematically varying major variables in drilling, perforating and hydraulic fracturing from the start, the company was quickly able to home in on what practices performed best. For Hallwood’s situation, horizontal wells perform convincingly better. The answer may be different somewhere else, but the important concept to remember is the “systematic process” for discovering early what performs best.

Innovation also includes finding new approaches for environmental challenges. In the Pinedale Anticline, Questar’s tight gas development was limited by wildlife restrictions that compressed drilling activities into a narrow window during summer. Full development would take a long time for hundreds of locations with conventional drilling, plus there would be a major number of surface disturbances.

Questar’s proposed solution was year-round operations with extensive directional drilling from three pads, using two rigs per pad. Installing water- and condensate-gathering lines would minimize truck traffic impacts. Not only would there be significantly less surface disturbance with this approach, but with year-round drilling, the time required to fully develop the resource would be shortened by more than a decade. The Bureau of Land Management approved Questar’s proposal in mid-November, allowing one pad this winter and three pads beginning in the 2005-06 winter after the water- and condensate-gathering systems were completed.

Mention Wyoming and CBG, and one automatically thinks of the Powder River Basin. But there is activity farther west in Carbon County in the Atlantic Rim play on the shallow eastern margin of the Washakie Basin. The play area is 55 miles long (north-south) by five miles wide (east-west). Production there comes from Upper Cretaceous coals within the Mesaverde group.

Early wells indicate rates of 1 million cubic feet a day are achievable, although average rates are half that. When fully developed, there may be as many as 3,800 wells. Initial development is occurring in nine pods, or drilling areas. The learning curve in these pods (and somewhat different completion and stimulation practices are evolving in the different pods) will help establish those practices that are most economically attractive when full-scale development occurs.