From a start in the 1980s as a new technique to clear methane out of underground coal mines, methane production grew with the help of US government incentives to a serious production plan in the eastern Appalachian coal basins, to the Black Warrior Basin of Alabama. From there it spread west to the San Juan Basin of New Mexico and Colorado, north into the Piceance Basin of western Colorado and the Greater Green River Basin of Wyoming and northeast into the Powder River Basin of Wyoming. Spot plays showed up around the country, including eastern Oklahoma and Illinois.

From an independent’s play, companies such as Amoco (later part of BP), ConocoPhillips and Burlington Northern (now part of ConocoPhillips) became major supporters of the play.
From vertical wells, technology expanded in CBM plays to holes completed with high-pressure water cavitation to open the bottomhole area and break open the cleat system in the coals for better permeability.

The US incentives disappeared as profitability rose and new technologies made production more efficient.

Technology
Amoco tested nitrogen injection into coal beds with its Tiffany program in the San Juan Basin. That program tried to use the greater affinity of nitrogen to coal to displace the methane adsorbed in the coal cleats. About the same time, Burlington Northern tested CO2 injection for the same reason.

Vertical wells with openhole-cavitation completions still work well for high-permeability dry coals. Vertical cased wells with fracture treatments work well in low- to medium-permeability coals in multiple-seam fields.

The technology just keeps coming. A horizontal drilling technique developed by CDX Gas LLC works well in low- to medium-permeability wells in the 1 to 10 md range in areas with a single, thick coal or a few thick seams, and it works particularly well in areas with limited access on the surface.

Speaking at the Hart Energy Publishing Developing Unconventional Gas conference in Ft. Worth, Texas, Michael D. Zuber, vice president of reservoir engineering at CDX, described the company’s patented Z-Pinnate technique designed to give the well maximum contact with the reservoir and cross as many cleat systems as possible.

This is a dual-well system that allows the operator to use underbalanced drilling. First, the operator drills a vertical well to the coal seam and creates a cavity at the bottom of that well.
Next, it drills an offset horizontal well that intersects the bottom of the vertical hole. It can drill any number of branched laterals off the horizontal well bore. That gave the system its pinnate name. It can look like the pinnate branches of stems off the main stem of a leaf. The well produces through the vertical well.

Among advantages, the system can intersect a large number of coals cleats in a wide area. It also allows the operator to drill numerous horizontal-vertical well combinations in different directions from a common well site in restricted areas.

It has drilled 50 wells in the Arkoma Basin of Oklahoma, and it’s working with CNX at that company’s Oakwood field and with Equitable Resources in the Appalachian Basin. In that area, usually with single, thick coals, an operator can drill 16 vertical wells and get 16 Mcf/d of production, but it can drill one pinnate well, speed time to production and get 3 MMcf/d of production. In West Virginia, it is developing 1,400 acres from a single surface location.

At the same conference, Rick Toothman, technical engineer with CNX, said his company, which started by clearing methane out of underground coal mines for Consol Energy, went public in 2006 and now is the second-largest gas producer in the Appalachian Basin. Most of its production comes from CBM. Its Oakwood field in Virginia is the 21st largest gas field in the United States with 1.22 Tcf of reserves and 2,300 active wells. It drilled 250 wells in the area last year and will drill 278 more this year with seven rigs working full time.

Control costs
As in most unconventional plays, a big part of the economics lies in controlling costs. Jay Still with Pioneer Natural Resources, also speaking at the conference, described his company’s technique in the Raton Basin of southeastern Colorado. Basically, the company runs its own service arm.

“With our own service company, we can drill, complete and tie in a well for (US) $400,000. With a third party (service company), it costs 50% more,” he said.

On a typical well, road and pad construction make up 7% of the cost. Pioneer has its own construction operation.

Drilling accounts for 32% of the total cost. Broken down, the drilling rig accounts for 27% of the drilling cost, cementing equipment 24%, third-party services 6% and materials 43%. By controlling the rigs and the cementing equipment, Pioneer has some control over 51% of the cost of its drilling operation.

Stimulation makes up 26% of the total cost, and Pioneer controls its frac equipment and sand, leaving only the 5% cost allocated to chemicals in the hands of outside companies. Completions account for 22% of the cost. Pioneer has its own workover rigs, but it can’t control the 80% share for tangibles. Finally, tie-ins make up a 12% share of total cost, and Pioneer controls 74% of that operation.

It owns its own gathering system and processing operations. In short, it controls the quality, speed of operations, timing and time of first production into the pipeline.

Still said the people part of the job was one of the toughest operations. The company recruited people at a job fair in Pueblo, Colo. The only requirement was that the person had to have a valid driver’s license and pass a drug test. Of the 70 people interviewed, only two qualified, he said.

International operations
As the CBM program grew in the United States, it also expanded into other nations. A CBM play is emerging in Canada as that country looks for more natural gas to replace the fuel used in northeastern Alberta for heavy oil recovery.

India now has regularly scheduled CBM bidding rounds to supplement its successful New Exploration Licensing Policy bidding rounds for conventional oil and gas.
China also has an emerging CBM play at least partially based on licenses taken out by ConocoPhillips. That company recognized the value of the play from its work in the San Juan Basin and has farmed out a huge Chinese prospect area.

A delegation from the Ukraine-Donetz CBM program traveled to the United States to compare production techniques.

In recent activity, Eden Energy of Australia has started drilling in South Wales in the United Kingdom as it seeks to tap the Westphalian coal seams.

Eastern Australia has a strong CBM program that is growing stronger. Far from the massive gas fields of Western Australia, people in eastern Australia currently depend on depleted supplies in the Cooper Basin and small increases from the Gippsland Basin.

The area has a lot of coal, however, and Wood Mackenzie, in its “Eastern Australia Gas and Power Outlook to 2025—Fitting the Pieces Together,” anticipates coal seam gas will account for half of eastern Australia’s supply by 2020, enough supply to meet anticipated demand by that time.

As in most places, gas demand for power generation will drive coalseam gas (CSG) development in all states except South Australia. Growing at 3.8% a year, the eastern Australia market should hit a demand point of 1.1 Tcf by 2025.

According to Andrew McManus, managing consultant, Australia, for Wood Mackenzie, “Queensland will have excess supplies from CSG, whereas South Australia and New South Wales will require new gas supplies from other states to meet the base case gas demand from 2010.”

That means the gas and power system, with the help of CBM, will grow from a local supply-demand market to “a more integrated and dynamic, semi-national energy market.”