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The ever changing unconventional world USGS geologist describes how new drilling and development techniques are overturning conventional concepts in gas exploration Alan Bailey Petroleum News
The fountain of oil spewing into the air from the “Lucas Gusher” discovery well in the Spindletop oil field in Texas in 1901 marked the beginning of a new industrial era, as companies clamored to cash in on a new oil bonanza, with the subsequent upsurge in oil production feeding an increasing demand for oil as an essential energy source.
But the fact that the huge and prolific Spindletop oil reservoir sat on an underground salt dome also drove a decades-long philosophy of searching for oil on the tops of major geologic structures, James Coleman, director of the U.S. Geological Survey Eastern Energy Resource Science Center, told the Alaska Geological Society on Feb. 17.
“The whole idea that we might find something not ‘on structure’ went away with the Spindletop discovery,” Coleman said.
A long history But, although the dramatic recent advances in horizontal drilling and rock fracturing, or fracking, have brought in a new era of “off structure” resource development, in unconventional plays such as shale gas and so-called tight gas sands, the history of unconventional resource development actually goes back some 50 years or so before the Lucas Gusher rained oil onto the Texas soil.
In the mid-1800s people would drill wells seeking brine for salt production, with oil and gas being undesirable waste products, Coleman said.
“They tried to figure out ways to drill and not find oil or gas,” he said.
The desire to find water led to the drilling of what geologists call synclines — structures where rock strata have buckled downward — rather than into the upward buckling anticlines subsequently favored in “on-structure” oil exploration, Coleman said. But, although water does tend to migrate into synclines, the mid-19th century drilling did encounter oil in synclines, in situations where water had not saturated the sandstone rock reservoirs.
In the early days of oil exploration the concept of drilling into anticlines was discarded for a time because people were finding oil in synclines, Coleman said.
“We’ve tended to forget this,” he said.
Explosive approach The earliest attempts at reservoir fracturing, or fracking as it has come to be known, also occurred in conjunction with mid-19th century drilling for saline water.
Drillers would haul nitroglycerine out to a well site and drop metal canisters containing the explosive down the well bores in the hopes that the nitroglycerine charges would explode at reservoir depths, Coleman said. The technique did improve well flow rates, but sometimes at the expense of burning down the drilling rig. Apparently, the results of the “fracking” could be especially dramatic in central Illinois, where the water production stream tended to contain oil and gas, which ignited as a consequence of the downhole explosions.
The fracking of rocks to stimulate oil production really started in 1947 in Kansas, when someone figured out that using high-pressure pumps to inject a mixture of water and sand down a well could stimulate the oil reservoir, Coleman said. And from that point fracking went down a route of “the bigger hammer theory,” which supposed that the greater the quantity of fracking material used, the greater the amount of reservoir stimulation that would result, he said. That trend continued right through the 1970s and 1980s, by which time people were putting 1 million pound fracks into the ground.
Nuclear fracking In what appears to be one of the more bizarre twists in the “bigger hammer” approach, in 1957-58 the U.S. Atomic Energy Commission came up with the concept of fracking gas wells by detonating nuclear bombs downhole. Done as part of Project Plowshare, a program to find peaceful uses for nuclear explosives, this initiative resulted in the drilling of several wells and the detonation of relatively small nuclear devices in some wells. But, the experiment could not exactly be described as a stunning success.
“The production rates were not really increased and the gas became radioactive, so it’s not like a win-win situation,” Coleman said.
Curiously, the project was eventually abandoned, not because of environmental concerns, but because it was too expensive.
“They couldn’t recover the cost of the frack job,” Coleman said.
In fact, the big hammer approach overall ran into a problem of diminishing returns, as larger and larger frack operations produced only modest increases in well production rates.
Horizontal drilling But meantime, evolving drilling technologies led to the use of horizontally drilled wells. Carefully controlled fracking done in stages at very specific intervals in these horizontal wells has opened a whole new way of developing oil and gas resources, especially in off-structure geologic situations where oil or gas continuously permeates the rocks, rather than being trapped in underground hydrocarbon pools of the type exemplified by Spindletop.
“Where we’re going with today’s drilling technology is pretty amazing,” Coleman said. “That has really changed the way that industry does things. … Horizontal drilling coupled with multistage completions in tight gas sandstones has radically overturned three decades of conventional development philosophy.”
In fact, in 20 years time people may ask why anyone ever drilled vertical wells that perhaps only penetrated a few inches of hydrocarbon pay.
“Why do you want to put six inches of (hydrocarbon) recovery space down there when you can put 6,000 feet or 10,000 feet, or whatever your horizontals run to?” he said. Moreover, it is now possible to precisely determine how to influence the rock into yielding oil and gas, he said.
In addition, with about 32 percent of all gas produced in the United States in 2007 coming from unconventional tight gas reservoirs, USGS geologists prefer to use the term “continuous resource” for oil and gas that permeates rock strata, as distinct from lying trapped as discrete pools in porous rocks.
Careful assessment Exploring for new resources in continuous hydrocarbon plays involves a careful assessment of the geology of a prospective basin, and an evaluation of seismic data from the basin, Coleman said. The presence of hydrocarbon source rocks is an obvious key in determining whether there is a viable hydrocarbon resource to be developed. And geologists need to determine both the nature of the rocks in the basin, and the geologic history of the basin, in terms of how the rocks have altered over time and how the rocks have been stressed and fractured, perhaps pushed downwards in the basin or pushed upwards.
Tight gas sands, where the gas is trapped as a continuous resource in the fabric of the rock, typically have a low ability to flow fluids (low permeability) and have small pore spaces for storing the fluids (low porosity). Ideally the gas source should lie right underneath the sands, although a source immediately over the sand can also prove effective. Chemical alteration of the rock can impact the rock’s ability to release gas into a gas well. And an optimum gas production situation often occurs where the gas bearing rocks have first sunk down and then been uplifted, with the drop in pressure during uplift causing gas expansion.
Rather than being a single, uniform rock type, a continuous gas play typically involves a variety of rocks, perhaps including sandstones, shales and coals. In fact, when it comes to gas sands, best gas production rates are often found in situations where the sands occur as a multitude of discrete bodies, such as ancient meandering river channels. However, the compartmentalizing of the gas reservoir in this way also tends to drive a need for a greater number of gas wells.
Sweet spots In general, developing a continuous gas resource involves determining the geologic parameters of “sweet spots,” perhaps situations where the permeability and porosity are a little elevated, where optimum gas production is likely to occur, Coleman said.
Exploration entails spending enough money to obtain the data required to assess the viability of the resource and to enable an evaluation of whether the gas market will support resource development.
“You’ve got to go back and look at the market conditions,” Coleman said. “You’ve got to keep rechecking if what you’ve got is what you want.”
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