Trick Is to Get Correct – and Enough – Data
Tools Take Unconventional Turns
The use of geophysical tools has become common in exploiting unconventional resources.
Today, operators can assess play areas and fracture systems with:
- Multi-component 3-D seismic.
- Microseismic monitoring to image the results of fracture stimulation using downhole or surface located geophones.
- Tiltmeter readings to detect small changes over time caused by subsurface activity.
Unfortunately, geoscientists have fallen behind in understanding the uses and benefits of geophysical tools in unconventional plays.
And that includes geophysicists.
“One thing that’s interesting to me as a geophysicist is that the geophysical community is just catching up. It’s new technology that’s really been driven in the past by engineers,” said Shawn Maxwell, chief geophysicist in Calgary, Canada, for Pinnacle Technologies Inc.
The petroleum geologist can contribute essential interpretation when these tools image the subsurface.
Petrophysics, geomechanics and stratigraphy all come into play.
“If we see a hydraulic fracture hitting a barrier that might be associated with a fault, then the geologists tend to get more involved in interpreting those aspects,” Maxwell said.
In one well-known example, hydraulic fracing of wells in an unconventional resource play caused rupturing into a natural fracture system. That system communicated with a water-bearing zone. Consequently, the fraced wells began to water up.
Solid knowledge of the geological setting can contribute to understanding both natural and induced fractures in an unconventional resource.
Many operators already use 3-D seismic for initial evaluation. Bob Hardage said he “preaches to anybody who will listen” about the advantages of multi-component seismic.
“We look at unconventional resources, which tend to be fracture-dominated systems, from the viewpoint of both P-wave and shear waves,” he said. “You really have to use multi-component seismic to do an optimal analysis of unconventional resources.”
The Cost of Value
Hardage is a senior research scientist with the Bureau of Economic Geology at the University of Texas at Austin and heads up a geophysics lab studying multicomponent seismic applications. He’s also editor of and frequent contributor to the EXPLORER’s popular “Geophysical Corner.”
Three-component (3C) seismic uses geophones that have three orthogonal sensors that enable detection of both compressional (P) waves and shear (S) waves, as well as the direction of propagation.
Nine-component (9C) seismic requires that three orthogonal source vectors be created at each source station; yields a three-by-three matrix of orientation combinations; and captures all possible S-wave modes.
“There are certain rock properties where shear waves shine and do things that P-waves just won’t do,” Hardage said. “Fracture-dominated systems are one of those things.”
Analyzing the geophysical aspects of unconventional resources begins with a good petrophysical model, according to Hardage.
“It requires very careful rock physics modeling,” he said. “What we’re really trying to model is to get our hands on enough data to understand the reflectivity of all P- and S-wave models.”
Hardage estimated that 3C seismic provides about 50 percent more information than traditional seismic, and 9C seismic about twice as much.
Because of the higher cost of 3-D/9C seismic, however, operators may choose 3-D/3C.
“What we’re trying to do in our research is to develop the technology that will bring down the cost a little bit,” he said.
Operators also should consider reprocessing and reinterpreting relevant, existing seismic, such as vertical seismic profile (VSP) data.
“VSP technology is quite valuable,” Hardage continued. “VSP data have been acquired with 3C geophones for many years. You can use VSP to get a beautiful picture of fracture orientation.
“I find out again and again people have very valuable VSP data without even knowing the data are in the company archives,” he added.
Structural plays might not require the detailed seismic information needed for stratigraphic plays, but unconventional resource plays tend to be stratigraphic in nature, Hardage noted.
“More and more we’re seeing geological requirements in which you have to understand both P and S seismic stratigraphy,” he said. “It’s really difficult to dismiss the advantages you get from multi-component seismic.”
Needed: Geological Input
The hottest current topic in geophysics related to unconventional resources is probably microseismic monitoring.
Microseismic is sometimes called “passive seismic” because it does not capture data from a specifically provided sound or energy pulse. Instead, it relies on natural or secondary energy sources.
Hydraulic fracturing produces micro-seisms, or mini-earthquakes, around the well bore and to distances of 1,500 feet or more. The location of these events can be determined using downhole 3C geophones to detect discreet acoustic wave arrivals, or by “beam forming” (stacking) the output from a surface-located 1C geophone array.
In unconventional resources, “microseismic is right now predominantly used for fracture monitoring. It has been viewed primarily as a tool for completions and reservoir engineers,” said Chris Neale, vice president of business development for MicroSeismic Inc. in Houston.
But the geoscientist’s input into interpretation is essential because “what really makes these plays work is understanding the geomechanics of the surrounding rock and how the completions strategy interacts with the rock,” he noted.
“For instance, there are certain kinds of rocks that produce a louder acoustic ‘bang’ than others when fractured,” he said.
The petroleum geologist can explain microseismic results in terms of rock properties and the geological setting. Neale described variances in microseismic in adjacent wells that required a geological explanation.
“Stacked fluvial tight gas sands, where there is almost no correlation between wells, even when they are close together, creates complex and unpredictable fracture patterns as the induced fracs follow three dimensional pathways within the sand bodies,” he explained.
“In the Delaware Basin, we may see very high amplitude events in one well and very low amplitude events in the other. There can be significant changes in rock properties even (when wells are) within thousands of feet of each other,” he said.
Because interpretation is so important, companies often assign a geologist as well as a completion engineer to a microseismic project, according to Neale.
“The real underlying issue is that the geological understanding of what microseismic is actually telling you is critical, maybe even more so than the engineering side,” he said.
“I think that’s the piece that’s missing right now,” he added. “There’s not enough geological, geomechanical input into what we’re seeing.”
Tiltmeter fracture mapping in unconventional resources also has gained wide acceptance by the industry.
“We’re seeing a large uptake of the technology,” Maxwell said. “People have started to look at coalbed methane recently to try to figure out how to best stimulate the fracture set in a coal.”
Most tiltmeters today work on the same principle as a carpenter’s level or bubble-level, with extremely precise measurement by electrodes.
Tiltmeters downhole and on the surface can be used to measure the tilt induced by hydraulic fracturing.
“I don’t know if heavy oil counts as an unconventional, but we also do a lot of work in that area,” Maxwell said.
“In these thermal deposits, we quite often put an array of tiltmeters on surface and look at the surface uplift. As you inject steam even at relatively large depths, the rock is heated up and expands and you get the surface rise,” he noted.
Tiltmetering can be used for hydraulic fracture imaging even at depths of 10,000 feet, according to Maxwell.
“When you’re creating a hydraulic fracture you’re pushing the rock to create the void space for that fracture, and the tiltmeters are so precise you can pick up the very small associated surface uplift,” he said.
“If you’re fracturing a shale, the tiltmeters can be used to determine the azimuth of the fracture that’s being created. You also can determine, for instance, if you are creating a vertical fracture as opposed to a horizontal fracture,” he added.
Hydraulic fracture imaging can be used on every well in an unconventional play, or the operator may decide to map only selected wells.
“In the Barnett it seems to be going more toward mapping every well. In other areas, some clients like to use it on test pilots (wells) to figure out what’s happening and to get the frac design down,” Maxwell said.
‘A Very New Science’
With either microseismic or tiltmeter, a time-series of images can be produced to show the spread of fracturing. Downhole geophones are used for essentially real-time imaging in microseismic.
“We typically produce a little ‘movie’ of the fracture with time, and it’s surprising how much complexity there is in the creation of the fracture,” Maxwell said.
A major concern in current fracture imaging is how to broaden the application of the technology to more of the nearly 25,000 wells fractured in the United States every year. Downhole monitoring traditionally has required an observation wellbore with 2,000 feet of the stimulated well. New plays typically have a limited number of older wells that can serve this purpose.
In response, several service companies are developing stimulated-well geophone arrays for downhole monitoring.
Also, surface-based monitoring obviates the need for an observation well if surface access is available.
The other consideration is cost, with fracture imaging jobs usually ranging from $75,000 to over $300,000, depending on complexity and location.
“Longer term, the microseismic service providers must find methods of data acquisition that will reduce overall cost, allowing for a broader application of the monitoring technology,” Neale said.
Applications in heavier oil deposits and methane hydrates represent a new frontier for unconventional resource geophysics. Hardage’s lab already is looking at mapping hydrates offshore.
“You’re not going to be able to turn your back on it,” he said.
“When Mother Nature makes these hydrates, the gas molecules are compacted so closely that the energy density is 42 percent of LNG,” he noted.
For microseismic, the next big step might be in continuous, “passive listening,” 4-D reservoir applications, according to Neale.
“Where the real value of this is in the future is in using microseismic as a reservoir monitoring tool,” he observed.
“Fracture monitoring is accepted and relatively well understood,” he said. “Long-term microseismic reservoir monitoring has the potential to produce much higher increases in added reserves, but it’s a very new science that will require a true multi-disciplinary approach.”