A relatively unused technique of looking at seismic reflections can reveal vast supplies of undiscovered natural gas.

Hundreds of trillions of cubic feet of gas lie trapped in tight sand reservoirs that either can't flow economically or require prohibitively expensive fracture treatments. The secret to producing more of that gas is finding the sweet spots of higher permeability.
Seismic theory and practice haven't changed much during the years. Typically, a geologist works up a theory for a play and sells the idea to someone with money, either inside the company or outside.
The geologist usually has some off-the-shelf seismic surveys that prove up his or her theory about the traps that keep the gas from migrating and the structure that helps concentrate it. Four-way closure is a buzzword just short of the Holy Grail.
As the discoveries in a given area get smaller and the gas harder to find, the seismic search switches from structures to stratigraphy. Geophysicists search their seismic surveys for formation pinchouts that may trap a porous and permeable gas zone between tight formations.
If the structural traps or the pinchouts don't show up on the surveys, it doesn't necessarily mean there's no gas there, it may mean the gas is in anomalously pressured zones that are hard, but not impossible, to find.
That's not just an idle statement. The US Geological Survey estimated basin-center and deep-basin gas resources in Rocky Mountain Laramide basins at 250 Tcf in a 1995 study, but only a small portion of that gas has been placed in the reserve category.
A significant quantity of Cretaceous shales in the Rocky Mountain Laramide basins is overpressured throughout the basins.
Sandstones within the overpressured shales are subdivided stratigraphically into relatively small, isolated, gas-saturated and anomalously pressured compartments. The driving mechanism for those compartmentalized anomalies is generation and storage of liquid hydrocarbons that react to the gas to form a multiphase reservoir in which capillary barriers control permeability.
Three notable discoveries are McMurry Oil Co.'s Jonah field in the Greater Green River Basin of western Wyoming with more than 2 Tcf in reserves; Cave Gulch field in the Wind River Basin of central Wyoming with more than 1 Tcf in reserves; and the Standard Draw-Echo Springs field complex in the Washakie Basin of south-central Wyoming with similar reserves to Cave Gulch.
Cave Gulch and Jonah are the two biggest discoveries of the past decade in the Rocky Mountain region.
The theory is simple. To find new gas in old fields an operator needs new technology, said Ronald C. Surdam. Surdam, former chief of the Institute for Energy Research at the University of Wyoming, heads Innovative Discovery Technologies LLC (IDT), a division of the Gas Technology Institute (GTI) in the United States formed to spread the word about finding and producing this important source of gas. Much of the research is available at www.idt-gti.com.
During a joint presentation in Houston, Texas, by GTI and the Texas Independent Producers and Royalty Owners Association, Surdam explained this basin-centered gas is not just a Rocky Mountain phenomenon. It occurs all over the world. ITD's method has been tested in 33 basins around the world by at least 11 operators. "The techniques work," he said.
Among test nations are China, Indonesia, Colombia, Argentina and West Africa. It works better in some places than others.
According to an AAPG Explorer article, the technique helped Repsol YPF make a gas discovery in the Neuquen Basin of Argentina. Surdam said the IDT team used its technique in a blind test and discovered significant gas accumulations in the 10 Tcf Loma La Lotta field in the Neuquen Basin. Repsol YPF is working on a full-scale, multimillion-dollar campaign to produce that field's gas reserves.
Anomalously pressured gas
The key to the technique is first finding anomalously pressured gas (APG) and then finding the sweet spots for permeability. APG usually is deep and overpressured, but it can be underpressured as well, and it can be shallow. The APG zone in the San Juan Basin of northwestern New Mexico and southwestern Colorado is about 3,000 ft (915 m) from the surface.
In the Rocky Mountains, the Washakie, Powder River, Wind River and Big Horn basins tend to be overpressured, while the Denver and San Juan basins are underpressured. The Western Canada Sedimentary Basin tends to underpressured at the top and overpressured at the bottom, Surdam said, "and you can't tell if it's underpressured or overpressured until you drill."
South Texas has a lot of anomalous pressures, he said, and the technique should work well in that region.
Finding the resource
A geophysicist looking for basin-centered gas first looks for a gas-charged region. Under normal conditions, a seismic signal speeds up as it travels deeper into the earth. The compacted sediments at greater depths create a better conductor for the signal.
If the signal slows at some point in its trajectory, there's a reason, and that reason may be a gas-charged formation. The inversion is detectable in the same way that amplitude variation with offset brings out bright spots when it reaches a pocket of gas. For best results, Surdam recommended a 3-D survey with an offset as large as the depth of the target formation.
Surdam's technique goes a step further. By processing the 3-D seismic survey to cancel out the normal signal for the basin, he's left with an image of the gas-charged zone.
That signal slowdown often varies by as much as 20% from the basin-normal signal, and the change point shows clearly on the processed seismic as a velocity inversion surface.
At Hoadley field in Alberta, operators drilled more than 200 wells before they found the first commercial well. Once they found the velocity inversion surface, they could find the sweet spots in the reservoir that produced commercial hydrocarbons.
At Elmdorff field in Alberta, underpressured gas signals areas of enhanced porosity and permeability, he added. Canadian Hunter mapped the whole velocity inversion surface of the field. "They're 20 years ahead of the US," Surdam said.
In the Mahakan Delta in East Kalimantan, Indonesia, the technique helped operators find 13 Tcf of gas.
Surdam said he probably would not look for basin-center gas in shallow basins that couldn't generate high temperatures.
Trapping the gas
Normally, when Surdam and his crew find a basin-center APG accumulation, it is water-saturated and held in place vertically by a tight, but not impermeable, shale layer. That layer acts much like a cement dam. The cement is permeable, but gas bubbles in the water that press against the dam form an impermeable seal.
That seal holds as long as the pressure against the dam falls in a certain range. For example, a cement sidewalk will absorb water poured on it, because there's not enough pressure to form the bubble barrier. Going the other way, at some point the pressure could become so great it would break through the ability of the bubbles to maintain their barrier.
In a gas reservoir, the differential between normal pressure and the underpressured zone or the overpressured zone could be about 2,000 psi. "That means if you don't get at least 2,000 psi (differential), you don't get hydrocarbons through the rock," he said. A trap forms. "That's what we see at Jonah and Cave Gulch. At the boundary, the only two ways to break the capillary seal are to exceed the displacement pressure or hit a fault."
Most Mesozoic gas is produced from a gas velocity inversion zone. A lot of that gas comes from 2,000 ft (610 m) above or below anomalous pressures.
Between 80% and 90% of the gas in Louisiana along the Gulf Coast is in an area up to 2,000 ft (610 m) below the anomalous pressure boundary, he said, and the only way it can move vertically is through vertical permeability, through a well or through faults or fractures.
Underpressured zones are harder to explain than overpressured zones. Surdam said he thinks some compartments were faulted, allowing gas to seep out. With the drop in pressure, the faults resealed. Even though the reservoirs released gas, they weren't open long enough to become charged with fresh water. Underpressured zones always are associated with salt water.
Finding the sweet spots
"All you need to do to find commercial gas is find enhanced porosity and permeability," Surdam said. Just because a survey finds an APG boundary doesn't necessarily mean the company will find commercial quantities of gas.
Typically these are tight sands.
In a sweet spot, something occurs to increase the permeability. That occurrence might be the type of rock or faults and fractures, or both.
Often that "something" is fine fractures within the reservoir. Typically, larger fractures are sealed in these reservoirs and the smaller fractures remain open. Those microfractures only remain open if the area is in tension. They won't stay open if the area is in the compaction phase.
Once again, seismic mapping comes into the picture. Through seismic interpretation, an operator can find and diagram the orientation of linear faults. That technique helped IDT find three successful wells in one area.
Jonah field is highly compartmentalized. Mapping the velocity anomaly showed a high associated with the velocity inversion surface. Surdam and his crew could "see" the geological trail the gas made as it rose up the boundary faults and spread like a mushroom into the Lance formation.
Backing up that evidence, all the wells with more than 4 Bcf of gas reserves fall within the AGP area along the faults.
McMurry Oil Co. came to Surdam's group for advice when Jonah field was young. Less than 100 wells had been drilled at that point. After mapping the APG areas, members of the group could correlate their findings closely with areas where gas had been found and produced in commercial quantities.
Using the technique, operators should learn before drilling:
• the extent of gas-charged rock, including pressure compartment boundaries;
• the location and nature of the regional pressure surface boundary or boundary between normal and abnormal pressures;
• the gas and water content of the fluid;
• the identification and spatial distribution of microfracture swarms; and
• the orientation and timing of faults.
Results
Once they had that information and cataloged the readings, the company never drilled a bad well in Jonah field, and the average well it drilled had reserves of 2 Bcf of gas. Of 20 wells drilled in 1999, the calculated estimated ultimate recovery after the well was drilled matched the Surdam group's predictions.
That doesn't mean the process is automatic. The operator still has to drill and stimulate the well correctly to get good production, and McMurry had a reputation for exacting specifications for its frac jobs. The company subsequently sold its producing wells in Jonah field to AEC Energy of Canada.
The success also doesn't mean there are no problems. Sometimes a compartment holds remnants of trapped water, and an operator can wreck a well by fracturing into that water.
Often, there will be a lot of underpressured gas on top of the anomalously pressured zone. In that situation, it's easy to continue drilling with a 10-lb mud when 5- or 6-lb mud is the correct call.
The predictions aren't all accurate either, Surdam said. One Standard Draw field well already has produced 25 Bcf, 2 Bcf more than projected for the reservoir. It continues to produce at a rate of 1 MMcf/d with no decline, and updated projections show it will produce 55 Bcf of gas.
Apparently the gas is coming from a series of laminated sands with 400 psi of pressure differential. As the well draws gas down from the top zone, the pressure differential drops below 400 psi and allows gas from a lower lamination to rise to the top reservoir.
The process isn't perfect, but it has been successful enough that several companies have taken a hard look at the advantages it can give them around the world.

Comments