Despite substantial amounts of time spent on gathering and evaluating seismic data, reviewing logs and examining well test results, no one knows how a well is likely to produce for at least six months.
But it could be up to a year before a company learns whether a well will measure up to production expectations, justifying investment. By that time, more wells have probably been drilled in the area using particular completion and well spacing techniques, not knowing whether a different design would have yielded better results for geologic conditions present in this part of the play.
Peter Duncan, founder and co-chairman of MicroSeismic, explained the scenario and how microseismic data can be collected in weeks or days, instead of the months it typically takes to get production data to determine the effectiveness of completion and other techniques. The saved time could translate into improved efficiency amid the continuing downturn.
He believes that appraising unconventional well performance with microseismic monitoring provides a “real-time, well-specific in-situ observation of how we are changing the permeability around that wellbore— permeability that we are going to see as the well produces,” Duncan said Jan. 19 during a webcast.
Data collected will make way for more accurate appraisals, he added, noting that could be accomplished within a few weeks or days of a well’s completion instead of six to 12 months. This, he said, could put the oilfield services company in a better position to understand how to respond to a particular play.
“We can get an early appraisal of how good the reservoir is around that well, how good our completion procedure is and how appropriate the well spacing we decided to use is and do that early,” Duncan said.
The microseismic-based well appraisal process includes use of three indexes that when combined could shed more light on a completion technique’s success for a well.
One index converts a fracture intensity map into an estimate of tensor permeability within the stimulated reservoir volume. The number, which takes into account both volume and the intensity of permeability, gives a sense of how permeability has been enhanced, Duncan said, adding the average permeability can be given on a stage-by-stage basis or along the whole well. Well-to-well comparisons are also an option.
Being able to determine where permeability is stronger allows companies to better predict which well might produce better and from which stages, he said, describing PermIndex. This, he added, could factor into determining which well completion procedure is more appropriate for a given area.
Reservoir simulation comes into play when evaluating the distribution of permeability.
“With an assumed pressure depletion curve and with an assumed PVT (pressure, volume, temperature) and fluid property porosity distribution value, we can make an unscaled assumption or prediction of how the well is going to produce and compare one well to another,” within a few days of having completed the well, Duncan said. “We can look at the rate at which that production will be delivered so that you can look at your return on investment and perhaps evaluate both a completion procedure in one area versus another, where you should be drilling more wells.”
A byproduct of the production prediction is a map of pressure depletion. Duncan said the map is a better way to evaluate how one well can interact with another or how to drain the reservoir. Such data can be used to justify whether to drill another well, where to drill it and how soon. “Well spacing now becomes an economic decision based on an estimate on where you are going to complete your wells,” Duncan said.
As companies look for ways to become more efficient, microseismic monitoring could be another tool in the well appraisal toolbox.
“Overall, it’s a prescription for a better development of your assets,” Duncan said.
Velda Addison can be reached at email@example.com.