Microhydraulic Fracturing

What is This?

If you physically isolate an interval and inject into that interval at a high enough rate, the pressure that is developed in the wellbore can ultimately become high enough to break down the formation and grow a fracture. If only a small fracture is created at relatively low injection rates, this is commonly called microhydraulic fracturing.

Why is it of Value?

As in an Extended Leakoff test, if multiple injection and shut-in cycles are carried out, it is possible to infer the magnitudes of the maximum and minimum principal stresses.

This can be done in target and surrounding zones to infer in-situ stress conditions and to determine whether or not a fracture created during injection will grow out of the targeted injection zone.

How is it Done?

The test can be carried out in openhole (with the accompanying risks of sticking tools) or in cased and perforated situations where isolation is possible. Generally in cased and perforated sections, you can only reliably determine the minimum principal stress.

Isolation can be accomplished in any number of ways…

  1. You can pump down casing if there is only one open part of the wellbore that is not too extensive (using the bottom of the hole or fill in a rathole as a lower wellbore barrier. This is not entirely desirable because some fluid loss may occur downwards. In fact, one variation of this is microfracturing during drilling operations where you pump and create a fracture growing out of the bottom of the hole and interpret these pressure time records to infer at least the minimum principal stress. Some operators, after doing this, have taken oriented core and looked at the direction of the fracture that was created.

  2. You can straddle individual zones with production injection packers or similar straddle configurations.

  3. You can set a retrievable bridge plug and a mechanical packer above.

  4. You can use commercial equipment such as DSTs.

  5. You can use commercial equipment specifically designed for this task, such as Schlumberger’s MDT.

After the zone is isolated, injection is accomplished by rigging up the appropriate equipment. In the very early days of microhydraulic fracturing measurements on land in tight formations, small, high pressure air operated pumps were used. As environments became more permeable and higher rate equipment was required, the pumping has been done with frac support units, cementing pumps, etc.

Rate and pressure are monitored. Because of wellbore storage effects, it is desirable but not absolutely essential to have bottomhole pressure measurements. Wellbore storage causes most of the problems that would require bottomhole measurement. For bottomhole pressure measurement, gauges can be run in side mandrel pockets, in bomb carriers below the lower packer, on slick line or on electric line.

Often when pressure-measuring equipment is run in on slick line or electric line, the pressure device is mounted in a spear that is landed in a nipple at the top of the upper packer, when it is desired to shut in the well. This provides a bottomhole shutoff (isolating the packed off zone from the rest of the tubing and with communication ports to the interval accurately records pressure during shut-in. Very slight head corrections can be made to correct for the datum of the device before shut-in.

The procedures are essentially the same as for Extended Leakoff testing with the exception that the fluid in the hole will often be completion brine, injection water or whatever, rather than mud.

What are the Considerations in Interpretation?

  1. Uncertainties in the maximum principal stress calculation can occur if the formation adjacent to the wellbore has failed. Basic elastic relationships for interpretation should be used with caution. The pressure required for breakdown can be “anomalously” high.

  2. Classical theories need to be modified to account for the stress conditions around inclined or horizontal wells (refer for example to McLennan and Roegiers, 1989).

  3. Classical interpretation in a vertical well is often done incorrectly, not properly accounting for poroelasticity. The classical equations that can form a starting point for interpretation are as follows (refer to Detournay and Cheng, 1988):


    For no fluid loss – impermeable formation:



     

    In a porous, permeable medium:


    where:

    h .....................................  poroelastic parameter, (varying from 0 to 0.5),
    a .....................................  Biot's poroelastic parameter, varying theoretically from 0 to 1 and practically from the decimal value of the porosity to 1.
    n .....................................  drained Poisson's ratio,
    To ...................................  tensile strength,
    sHMAX ................................  maximum horizontal principal stress,
    sHMIN ................................  minimum horizontal principal stress, and,
    pb ....................................  breakdown pressure.
  4. Basic interpretation proceeds as follows. The minimum principal stress is determined by processing the shut-in pressure data on the basis that the pressure in the fracture, when pumping has stopped will attempt to equilibrate with the total stress acting to close it. Interpretation is not straight forward, particularly in formations where there is a substantial amount of fluid loss. Guo et al., 1993, provided a good summary of some of the methods that are available. These include:


    5.  
    Authors Method
    Gronseth and Kry Inflection pressure method. Draw tangents to the pressure after shut-in during initial and later stages and use the intersection as the in-situ stress. Guo et al. indicate that this method is not recommended.
    Turnbridge Plot the rate of change of pressure with pressure since shut-in and look for significant reflections. Guo et al. indicate that this method is not recommended.
    McLennan and Roegiers Work on the premise that you are looking for a discrimination between largely linear or bilinear flow to something closer to radial flow – recognizing that this will never be completely true because there is never complete fracture closure. The procedure is to plot pw versus Horner time from shut-in (t+Dt)/Dt.
    Aamodt and Kuriyagawa As above but plot log (pw – pa) versus Dt (pa is an asymptotic pressure selected by the analyst).
    Zoback and Haimson As above but plot log pw versus logDt.
    Sookprasong As above but plot pw versus t0.5. Guo et al. indicate that this method is not recommended. This is somewhat surprising since this can be a characteristic indicator of linear flow.
    de Bree and Walters These authors adopted minifracturing methodology and nondimensionalized the time term as d. The basis of their recognition of the pressure at which a fracture closes is plotting ln(p(t) – po) versus 0.67[d + 1)3/2 – 3/2].
    Plahn and Nolte Simulation.
  5. What method do you select? The answer is not straight forward. Use multiple methods and select the technique that provides the most consistent results.

  6. Uncertainties also arise because the poroelastic contribution is dependent on the rate of injection, the presence of weaknesses (micro-and macro-scales) and stress concentrations beneath the packers.

  7. After the minimum in-situ principal stress is selected from the shut-in cycles, while the fracture tries to close, estimate the maximum principal stress orthogonal to the wellbore from the breakdown equation. There is substantial uncertainty in this estimate.

  8. Precaution: When stresses are reported, particularly from drilling operations and formation integrity evaluations they can be breakdown pressure gradients (gradients of fracture initiation pressure) or fracture propagation pressure gradients and not necessarily the value of or gradient for the minimum principal stress.

References

  1. McLennan, J.D. and Roegiers, J-C.: “Extended Reach and Horizontal Wells,” in Reservoir Stimulation, Second Edition, Schlumberger Educational Services, Houston, TX (1989).

  2. Detournay, E. and Cheng, A. H-D.: “Poroelastic Response of a Borehole in a Nonhydrostatic Stress Field,” Int. J. Rock Mech. Min. Sci. & Geomech. Abstr. 25, (1988) 171-182.

  3. Guo, F., Morgenstern, N.R., and Scott, J.D.: “Interpretation of Hydraulic Fracturing Pressure: A Comparison of Eight Methods Used to Identify Shut-in Pressure,” Int. J. Rock Mech. Min. Sci. & Geomech. Abstr. 30, No 6, (1993) 627-631.

Back to Key Issues Top Monitoring Best Practices