Monitoring - Tiltmeter

Determine hydraulic fracture azimuth and dip (with time).
Discern fracture growth in multiple planes
Approximate the location of a fracture's center
Assess subsidence
The tiltmeters are installed at depths of between 5 and 80 ft below the surface in 3-inch diameter PVC pipe. Deeper boreholes can be used to eliminate "noise" from the surface - including cultural noise, thermallyh-induced earth surface motion ...
A surface array can consist of, for example, 12 to 20 tiltmeters placed in concentric circles around the anticipated fracture trend (distance from well: 15-75% of the fracture's depth).

Back to Key Issues Previous More Details? Monitoring Best Practices

Determine hydraulic fracture azimuth and dip (versus time)
Detect out-of-zone fracture growth and/or unstimulated pay
Approximate hydraulic fracture width (or cumulative width for overlapping multiple fractures)
Help to calibrate fracture growth models

Back to Key Issues Previous More Details? Monitoring Best Practices

This is where the tiltmeters are in the injection well itself and not in an offset.
There remains considerable debate on the influence of noise.
Pinnacle contends that the tilt signal is so high that it can be readily discriminated.
Some people have wondered "Why do you see a tilt for the situation where the tiltmeter is in the injection well?" It requires a very slight offset for tilt (i.e., the fracture grows just a little away from the axis of the wellbore) to be measured, but Pinnacle has indicated that they have found this to be the case. Ask these questions if you are considering this service!

Are there depth limitations for surface tiltmeter arrays? Tilt-mapping, with surface installations of tiltmeters, has been performed to 10,000 feet. Before committing to a program to measure tilts at these depths, seriosuly contemplate the lithology to determine if a reliable and adequate tilt can be measured at the surface.
Can fracture dimensions be determined from surface tilt measurements? If surface tilt mapping is done, you usually cannot reliably get fracture dimensions reliably. At a minimum some sort of supplementary numerical modelling may be required.
What are the main limitations of downhole tilt measurements (tiltmeters in offsets)?
- The problem that you usually encounter is the offset distance (distance from the event to the tiltmeters).
- The offset distance dramatically influences the reliability of the measurement and the predicted length of a fracture.
- For downhole tiltmeters, the resolution is 5 to 10% of the distance to the offset well.
- If there is a large offset, there is better prediction of length than height.
- If there is a small offset, there is a better prediction of height than length.
- There is a large signal-to-noise ratio due to the short distance to the fracture (in comparison to a surface array. A typical scenario might be an array of six to fifteen tiltmeters placed in offset wells. The depth of the instruments is centered around the interval to be fractured in the treatment well.
- The amplitudes of tilts measured downhole are typically 100-10,000 x greater than surface tilt amplitudes.
Important Concept: Tiltmeter monitoring has shown (in some environments) different fracture growth patterns depending on the rate at which you are injecting. It has been reported that for low rate injection, there is strong evidence that shear fracturing was probably occurring and the trends of the measured features did not align with the maximum principal stress direction. At higher rates, mapping has shown a more discrete feature aligned with the principal stress direction.
Interpretation is very difficult!
- It may not always be possible to get a unique relationship between the measured tilt and the fracture that exists in-situ.
- Fracture containment (or lack of), measured with tiltmeters and microseismic monitoring, is not always predicted by available fracturing models.

Back to Key Issues Previous More Details? Monitoring Best Practices

Available Size? For downhole deployment/measurement, the existing tools are 2 7/8-inch. A smaller tool (1-inch) is apparently being built.
"Have they been run in a horizontal well?" The answer is no. Existing tools only have an 8 to 10° tolerance. A new generation tool is anticipated to be able to handle inclinations of plus or minus 30 degrees. This is one of the current limitations.
"What are the restrictions in predicting dimensions in the same well?" There may be difficulties in this associated with resolution. THIS COULD BE THE KEY CURRENT RESTRICTION. IN A HORIZONTAL WELL, IF THE FRAC GOES ALONG THE WELL YOU CAN MEASURE TILT. HOW DO YOU MEASURE HEIGHT IF THE FRAC IS TRANSVERSE TO THE WELL? In most circumstances, offsets will not be available or cost-effective and the real application of the technology in frontier areas is contingent on reliable, cost-effective measurements in the injection well itself.

Back to Key Issues Previous More Details? Monitoring Best Practices

Land-based, surface systemThe typical cost of a job is $20,000 for deployment in offset wells and a couple of days of measurement (minimum). Typically, more wells are used and with detailed interpretation, the price is closer to $50,000 or $100,000 U.S - at least.
Downhole measurements in offsets will be more expensive than this and suitable offset wells are required.