The dynamic drilling action in shale gas plays has occurred in large part because operators want to hold onto their leased acreage, in addition to bringing in some early return on their sizeable investment, i.e., bump up the cash flow.
But holding onto leases for the land itself is not the point.
Operators often need time to acquire in-depth scientific knowledge to plan drilling programs to strategically develop their holdings in order to drill the most productive wells.
Given the relatively new big thrust in shale oil action, these plays can benefit from the fact that operators in the earlier gas plays quickly realized there’s a steep learning curve for all things shale.
AAPG member Nathan Meehan, senior executive adviser at Baker Hughes in Houston, gets to the heart of the matter.
“Some operators go quickly to what we call the factory approach,” Meehan said. “They do a little science, drill a couple of good wells and quickly decide to drill a few hundred more of these based on the assumption this one successful design is good to go on any location.
“Still, we all know that heterogeneity and variability from every location to the next are really high, and the odds you’ve really optimized things are pretty low,” he noted.
“Actually,” Meehan quipped, “the only thing about the drainage areas of shale reservoirs that we really don’t understand is how far out they go and how vertically tall they are and how long they are.
“In other words, we don’t understand anything about them.”
Indeed, wells in close proximity can be drilled almost identically and yield pretty much identical logs and cores yet demonstrate significant differences in production performance.
“There can be a physical, geological and geomechanical explanation for this,” Meehan said. “But in most cases, we don’t run enough logs and don’t characterize the reservoir enough to be predictive of exactly what locations will be better than others.”
Understandably, a broad area with higher TOC and higher silica content than a broad area nearby will perform better overall. Yet there will be significant variations within the “good” area.
“We must do as much science as possible to understand these reservoirs,” Meehan emphasized.
Shales in general contain miniscule or no porosity and permeability. In very low permeability reservoirs there’s the issue of how large the gas or gas/oil molecules are compared to the size of the pore throats.
“It’s not that hydrocarbons can’t move through pore spaces that are really small,” Meehan said, “it’s that they kind of line up and go behind each other, sort of like one or two at a time. With oil, it’s a bigger issue, because if you have some of the extremely low permeabilities in some of the gas shales the larger oil molecules might just be trapped there.
“The relative permeability to that oil might be near zero,” he continued. “The only way to get it out would be through some microfractures that would give it the ability to move.
“Understanding the microfracturing in shales is probably more important for oil and rich gases rather than dry gas, given that the larger crude oil molecules require better effective permeability to flow from the reservoir in economic volumes,” Meehan noted.
“Even if microfracturing is a small part of the total permeability of a particular petroleum system,” he said, “it could be extremely important if the rest of the permeability is extremely low.”
Geomechanics’ True Value
In the Bakken shale oil play, microfractures often are associated with hydrocarbon generation.
“When kerogen cooks out of the Bakken shale, it experiences an intense volumetric increase of about 114 to 170 percent,” said AAPG member Scott Stockton, executive vice president of Vector Seismic Data Processing in Denver. “There’s great energy stored in that volumetric increase, and it wants to fracture the rock, mainly along the bedding planes.”
During the hydraulic fracturing procedure that operators commonly implement in shale plays, the critically stressed fractures – those that are optimally aligned to fail in the present-day stress regime – are the ones that actually fail and shear when they feel the impact of the increased strain caused by the hydraulic frac, according to Meehan.
“A large amount of microseismicity occurs outside of the primary plane of the hydrofracture,” he said. “The slippage along all those little fractures enhances the bulk permeability quite a bit, because even a very small amount results in permeability much higher than before – albeit ‘much higher’ in this case is relative to a very small number.
“The slippage generates a lot of the ability to drain some incredibly tight rock,” Meehan said. “To understand the location and direction of those, you need to do the geomechanical studies of the reservoir.”
For some time, geology, petrophysics, geophysics and engineering have contributed to characterizing and understanding subsurface assets. The addition of geomechanics as a practical science to help the evaluation can be invaluable, according to Meehan.
“The early work was focused on wellbore integrity and forecasting pore pressures,” he said, “and a lot of geomechanical issues are not as important in vertical wells as in horizontal and multilaterals – especially those oriented in multiple directions.”
The real opportunity for understanding critically stressed fractures came about because more people are building real geomechanical models – particularly with the image logs, i.e., acoustic or microresistivity logs.
“They’re able to see both natural fractures and drilling induced fractures in boreholes and then integrate that interpretation along with other data to model stress state in the rocks,” he said, “and be able to build predictive models.
“The technology is really important to understand the stress regime, the fractures, be able to get the magnitude and direction of the in situ stress and to understand the normal and shear stresses that act on fault planes,” Meehan said. “It’s essentially understanding where those fractures are to identify the ones with high conductivity.
“Critically stressed fractures are the ones most conductive to fluid flow,” he said. “That’s where the flow will be predominant, and you can’t get that from running a triple combo in a vertical well.
“A lot of forward thinking operators are increasingly realizing the importance of geomechanics issues and that you don’t have to do a geomechanics study on every well to understand a very large area,” Meehan said.
“You have to do more than one, but not a thousand.”
Just In Time
Smaller companies are not sitting around enviously watching the larger folks better evaluate their holdings. These small players also are on board the geomechanics science bandwagon, according to Meehan.
He emphasized that the science came about just in time to be used in conjunction with shales.
Besides the overall technical/scientific understanding it affords, it can go far to help determine just how much and what part of that expensive leased area an operator really needs to hang on to.
There’s also the potential to drill bigger, more expensive wells where overall cost to drain the reservoir may decrease. Meehan noted there are few multilaterals in unconventional gas reservoirs, but several have been attempted.
In the case of assorted multilaterals each having undergone 30 individual frac jobs, geomechanics can make all the difference in reducing risk.
“We’ve done it now and had good success,” he said. “The question for us is, ‘Can we get the reliability and cost such that people will want to do this all the time?’
“Geomechanics has probably changed my opinion more about understanding natural fractures than anything else I’ve learned in the past decade,” Meehan noted.