What's new in production

	Vol. 226 No. 2
ROBERT E. SNYDER, EXECUTIVE ENGINEERING EDITOR

Deep gas stimulation. Deep gas represents a significant gas supply, with US resource estimates ranging from 87 to 133 Tcf. For the next few years, some 600 deep gas wells per year will be drilled in the US, representing only 1% to 2% of wells, but their contribution to production will be much larger. Effective completion/ stimulation practices are central to realizing this potential. Pinnacle Technologies Inc. is finishing a DOE-supported project directed toward deep gas well stimulation technologies.

They discovered that much of the “deep” stimulation literature is 10 to 20 years old, when deep was > 10,000 ft and hot was >200°F. To fill this public domain data gap for deep gas well stimulation, Pinnacle and operators worked together documenting case studies that integrated fracture modeling with production data analysis and well testing and/or fracture diagnostics. Case studies were developed for the Bossier sand in East Texas, Lobo sand in South Texas and a Wyoming deep gas reservoir. Working through PTTC’s Texas Region, Pinnacle recently presented insights from these case studies in a workshop in Houston.

Microseismic data reveal the fracture was fairly well contained near the wellbore. However, a fault encountered not far from the wellbore dissipated much of the energy. As the job progressed and the frac moved farther out, a communicating fault allowed the frac to move upward into another zone and back toward the wellbore.

As reported in the Petroleum Technology Transfer Council’s (PTTC) 4th-quarter Networks, knowing where the frac goes is just one challenge. Getting proppant distributed is critical, then there’s the matter of keeping that productivity up for the long term. Service providers are actively developing new-generation frac fluids; and there is more to learn about proppants. Those attending the workshop noted that true real-time stimulation optimization is a key enabling technology. PTTC and Pinnacle will repeat the workshop on February 23 in Norman, Oklahoma. The website www.pttc.org/events.htm has more information.

New coalbed methane technology. Coalbed methane (CBM) production has long been touted as one of the most promising means of maintaining natural gas production, at least in the US. Estimates of gas-in-place in CBM provinces result in some truly staggering statistics, as reported by Weatherford in its 3rd-quarter W Magazine. Worldwide CBM resources are reported as between 3,500 Tcf and 9,500 Tcf, with more than 2,300 Tcf in North America alone. However, these “tomorrow’s” reserves are being developed with “yesterday’s” technology.

The standard method for developing a CBM field is to poke a series of holes in the ground as closely as permits will allow, to drain as much of the gas as possible. These methods generally comprise an easily drilled vertical hole. However, perforating and fracing don’t help open the “soft” coal seams to gas flow. Weatherford proposes a change. If horizontal drilling works so well in conventional fields, why not use it in unconventional gas reservoirs? They suggest a lengthy horizontal wellbore with a number of multilateral junctions.

The proposed method is neither low-tech, nor inexpensive; but it can double economic benefits. Just one or two horizontal wells could drain the same square mile of coal seam as 16, 40-acre or eight 80-acre vertical wells. And estimated production from those horizontal wells could be 10 to 20 times that realized by vertical wells.

Most CBM wells require dewatering before realizing much gas production because the hydrostatic pressure of the well stops the gas from being liberated from the coal matrix. Maximal reservoir contact realized in a horizontal well speeds up the dewatering process, meaning first production is achieved more quickly and at greater rates. And there’s an environmental benefit. In areas like Wyoming’s Powder River basin, for example, the number of vertical wells needed to fully exploit vast CBM resources is estimated at 80,000.

Weatherford has combined several technologies to develop a system for drilling horizontal CBM wells. One of the main drivers is underbalanced drilling. It’s important to control-drill to keep the hole clean and also monitor and maintain the circulating pressure environment to continue to drill underbalanced. When the wellbore reaches a tangent angle between 60° and 75°, that tangent is held constant and laterally drilled through all of the coal seams, extending about 150 ft beneath the deepest coal seam to be completed. This additional rathole serves as a sump for the artificial lift pump. This main wellbore is then cased and cemented using 7-in. casing.

This “mother wellbore” is now used for drilling multiple horizontal laterals into the coal. The next step is to mill a 6-1/8-in. window and drill a “main lateral.” Then, side laterals are placed off the main lateral at 500-ft to 600-ft intervals. Each side lateral will extend roughly 1,500 ft into the reservoir. The main lateral is usually drilled slightly updip so water will drain back toward the rathole, where an electric submersible pump will pump it to the surface.

Weatherford has just begun to emphasize this type of CBM development; an operator in Australia has awarded it a multi-well contract in Queensland; and several operators in India are contemplating developing their considerable CBM holdings with horizontal technology. In the US, the concept is gaining ground, though operators there tend to be a “bit more skeptical.” One major operator is considering developing its perimeter acreage using this technology.

Hurricane Ivan’s problems persist. The US Minerals Management Service has been regularly reporting shut-in oil and gas totals in the US Gulf of Mexico since Tropical Storm Bonnie and Hurricane Charley caused the shut-in of over 480,000 bopd and 1.11 Bcfd gas in mid-August. In mid-September, MMS was reporting the shut-ins as resulting from Hurricane Ivan, and they were 1,042,839 bopd, and 4.198 Bcfd gas.

In the latest report of January 18, there was still 140,564 bopd shut-in, equivalent to 8.27% of daily GOM oil production, and 0.71% of the 19,700,000 bbl of US daily oil consumption. Shut-in gas has dropped to 559 MMcfd, or 4.54% of GOM daily output. Production is coming back slowly, but the present worth of that lost oil/gas production at year-end prices, plus the cost of repairs is a huge dollar amount, likely close to one billion dollars by year-end for oil alone.