Downturns in the oil and gas industry are rarely embraced by its players – but timeouts can sometimes be advantageous.
“When the industry slows down, we have the opportunity to catch our breath and think about how we can improve for the future,” said Tom Bratton, a professor at the Colorado School of Mines who spoke at the 21st Annual 3-D Seismic Symposium on Feb. 5 in Denver.
“When we as an industry come back, we want to come back smarter.”
Bratton, who teaches petroleum engineering while working on his doctorate degree in geophysics, spoke about optimizing production from unconventional wells by overhauling current seismic models.
“Our models are often incorrect. They don’t capture all of the variability that we observe in the data, and we make assumptions in models that violate the reality,” Bratton explained.
When horizontal wells were being drilled and hydraulically fractured at break-neck pace, many operators could financially tolerate a “statistical play,” in which the top 10 percent of the producing wells absorbed the cost of the remaining less productive
and non-commercial wells, Bratton said.
As a result, the process of improvement was often delayed.
Now may be a good time to change that.
Many operators rely heavily on offset production data to determine well locations and on current industry trends to determine the number of hydraulic fracturing stages. As a result, many choose not to log or core wells to cut costs, Bratton said.
Rather, they rely on educated guesses in developing their fields.
“When we look at unconventional wells, we find an incredible variability in their production,” Bratton said. “Some wells are good but some wells are not even commercial.”
To optimize results, more accurate seismic models are needed. To build more accurate models, ironically, more data is needed from cores and logs.
Decisions about where to develop in the field, the number of hydraulic fracturing stages and the rate at which to stimulate the rocks all can be made from integrated geophysical data, Bratton said.
Integrating core samples, well logs and seismic data is the first step toward building better seismic models. Cores show detailed information about a formation on a scale of one to two inches from the wellbore. They are the “magnifying glasses” in the reservoir,
Bratton said. The logging scale ranges from two to five feet from the wellbore, making it the “glue” that holds core data and seismic data together, Bratton explained.
Seismic, which has a wavelength of 200 feet, covers the entire reservoir.
“To make better predictions,” he said, “we need to understand all three scales.
“We are not as effective as we could be or should be in convincing the people who make the financial decisions to understand the value that geosciences can bring. Geoscientists are under the gun to reduce costs, and the engineers control the money,” Bratton
added. “One of my challenges is how to illustrate to the young engineers I am teaching how to become better at our craft and trade. There are so many guesses in the engineering process.”
Bratton emphasized that while acquiring additional data costs more money, it leads to cost savings in the long term.
“A better understanding of the geoscience will give us more guidance in predicting how many wells we need to drill to drain a reservoir,” Bratton said. “The fewer wells we need to drill, the more money we save.”
Constants and Variables
When data from cores, logs and seismic is combined, a system of constants and variables is established to help determine the gaps in current models that result in wells spaced too closely or too far apart, and therefore not 100 percent efficient in draining
oil along the lateral, Bratton explained.
“There are more unknowns in unconventional reservoirs than in conventional reservoirs,” he said. “When you have a complex problem where you have many unknowns, the more data you have the better your chances are of solving for all of those unknowns.”
Currently, a roughly 400-year-old principle called Hooke’s Law is used to interpret seismic data in horizontal wells, Bratton said. Hooke’s Law assumes that velocities are independent of load or stress in the earth.
It is an assumption that when applied to seismic data, is often incorrect, he said.
“If Hooke’s Law, when applied to seismic interpretation, were correct, no matter what magnitude of stress is applied on subsurface material, the acoustical velocity in the formation would always be the same,” he explained. “But stress often affects the velocities.
Hooke’s Law doesn’t work. It makes the wrong prediction.”
While the equation works for some formations, “More terms are needed for most formations in all of these unconventional fields,” he said.
A non-linear model is needed to take into account all variables, including porosity, lithology and stress, as all are changing within the formations in unconventional wells, Bratton said, adding that the industry needs to better understand the stresses in
the earth and how they affect velocity. Only then can seismic data be more accurately interpreted.
“When we apply a simple model to data, it indicates that one decision ought to be made,” he said. “If we had a better model, we might make a different decision.
“If acoustics are a function of stress,” he continued, “then seismic data can illuminate where the completions are efficiently draining the reservoir and where they are not.”
Overhauling the Models
Bratton is currently using time-lapse seismic data to build non-linear models tailored for horizontal drilling and hydraulic fracturing in the Wattenberg Field of the Denver Basin. He is working with the Colorado School of Mines and the Reservoir Characterization
Project, which integrates the acquisition and interpretation of multi-component, three-dimensional seismic reflection and downhole data with the geology and petroleum engineering of existing oil fields, in an attempt to understand the complex properties of
By comparing seismic data shot before and after hydraulic fracturing operations, Bratton has seen for himself that acoustical velocities change as a result of stimulation.
He added that production should further chance velocities.
A more accurate velocity model would allow operators to better estimate formation properties and stresses between wells.
“We need to be able to look at seismic data and know where the sweet spot is,” he said. “You don’t want to drill and miss the good stuff.”
Better predictability also might encourage engineers to allocate more funding toward acquiring geophysical data after seeing its benefit to drilling projects.
“When you start making accurate predictions, engineers start to get on board with acquiring geophysical data,” Bratton said. “We’ve got to be friends with these guys and not work on separate floors. We need multidisciplinary teams.”
When geophysicists and engineers understand they are working for the same goal, the tug of war that tends to exist between them will likely dissipate.
“Once you prove yourself,” Bratton said, “the engineers will be in your office asking for your opinion.”