Robert D. Kuhlman
Halliburton Services
Duncan, Okla.
Microfracture testing is providing operators with data for optimizing fracture treatments and determining the placement of wells.
This type of testing has increased during the last 5 years because operators can obtain actual stress magnitudes in various zones and the fracture azimuth direction. Entire multiple-well programs have been planned around this testing.
Microfracturing is a test for determining the minimum principal stress at a point in a formation. The test is usually performed at relatively low injection rates of 3-25 gpm (0.010-0.095 cu m/min) over a short period of time such as 3-10 min.
The least principal stress, smin, is usually determined by analyzing the pressure decline after shut-in. The least principal stress of a zone is defined as equal to the fracture closure pressure (FCP).1-3 A portion of the resulting small fracture from this test can be recovered in an oriented core, yielding the fracture azimuth.
The least principal stress data are useful in determining the minimum pressure at which an existing fracture closes. The least principal stress magnitude from several points in the pay and nonpay zones is valuable in determining fracture geometry and containment.
Microfrac data have been used for placement of perforations, for optimizing of treating rate and fracture treating fluid viscosity, and for selection of overall treatment volume.
A 3-D or pseudo-3-D fracture simulator may use microfracture data to determine overall fracture geometry; combined with minifrac fluid loss calibration data, the simulator can be more accurate.
Microfrac data are also frequently used to calibrate sonic rock-properties logs.
FIELD PROCEDURE
Microfracture tests may be performed on either cased or open holes.
There are some differences in procedure, and each has its advantages and disadvantages. Some special equipment is also required in obtaining and ensuring adequate quality data.
OPEN HOLE MICROFRACTURE
Open hole microfracturing is often performed alongside an extensive oriented core study. An unfractured core may be used in an anelastic strain relaxation test in which the fracture azimuth may be obtained.4
Another method of obtaining fracture azimuth is to create a microfracture at the bottom of a drilled well bore and retrieve part of the induced fracture within an oriented core.5 The created fracture angle is then correlated to the core orientation data, yielding fracture azimuth.
Azimuth may also be found with the borehole televiewer or downhole video camera.
Theoretically, the open hole microfracture is the preferred method for obtaining FCP (umin) because there is no interference from perforations and cement. In open hole testing, however, fluid loss at the well bore sometimes makes determination of FCP difficult.
The tested zone should be mostly homogeneous, so it is good practice to isolate the center of the zone of interest. The smallest possible zone should be isolated, usually 36 ft. However, longer intervals are sometimes used because of work string limitations.
A small segment is required for better resolution of umin and helps in ensuring that only one zone is fractured. If the interest is to observe the potential for out-of-zone frac growth, then one may intentionally want to isolate the interface for fracturing.
The isolation may be accomplished with an impermeable plug, such as an open hole testing packer. Sand should not be used as the bottom plug, since the low injection rates will allow for hydraulic communication through the sand.
One packer may be used for the isolation if the microfracture is to be created at the bottom of the well. As mentioned earlier, a fracture induced at TD may be partially recovered through oriented coring. See Fig. 1 for a microfrac setup diagram and Fig. 2 for an example of a typical tool string.
A surface readout, downhole pressure-temperature gauge, or a memory gauge may be used to obtain downhole pressure data. The bottom hole pressure (BHP) may be accurately calculated from surface data if the hole is loaded with injection fluid and density and Theological properties are known. This method is not as desirable as actual downhole data.
Because of the low injection rates, the frictional pressure drop through the tubulars is sometimes ignored in BHP calculations.
Before beginning a microfrac test, hydraulics and load calculations should be made to determine the maximum allowable surface pressure. If the formation breakdown pressure is excessive, pressure during injection may unseat and push up the open hole packer. The rig's weight indicator should be monitored throughout the test, but especially when breaking down the formation.
A downhole tool with hydraulic holddowns or slips can be used to anchor the work string to the casing. Such a tool can be placed on the work string close to where it overlaps with the bottom of an intermediate casing.
The open hole well bore is a source of concern in planning the microfracturing test. The well bore should have a close tolerance and be nearly circular to ensure proper seating of open hole packers. Naturally fractured formations are not easily tested and can yield erroneous data. A competent borehole is required.
A long uncased annular zone can also be a cause of concern. It is desirable and likely that the fracture will propagate around the packer, and hydraulic communication between the injection side and annulus side may be broken down or fractures from prior microfracture tests can be reopened.
Annulus pressure is sometimes bled down during injection to ensure that it is within safe limits. Monitoring the annulus pressure during shut-in and correlating it with tubing pressure usually yields FCP.
Because of the small volumes injected during a microfrac test, all surface lines and pumps should be fluid tight. The lines should be tested to the maximum anticipated pressure. An annulus pressure-set or mechanically set downhole valve can be used to close the work string for pressure testing.
After testing the surface lines and the work string, the packer seat should be tested by pressuring up the work string at a nonfracturing rate.
This having been accomplished, the initial injection is begun. Using the work string pressure test or filtration test as a reference, a constant injection rate is established. If the formation does not break down initially, several operations may be undertaken to assist break down. Acid may be dump-bailed or spotted to assist. The well may also be cyclically pressured to break the formation down by fatigue.
After breakdown (Fig. 3) the constant injection rate is maintained for a few minutes to create a small "penny-shaped" fracture. The fracture will likely propagate around the packer, and hydraulic communication is established with the annulus. The well is then shut in and the instantaneous shut-in pressure (ISIP) is noted.
The well is shut in until it is believed fracture closure is observed. Fracture closure can be determined from observing the annulus pressure and/or a pressure decline vs. square root of time plot.
Subsequent tests are performed on the same zone by reopening the fracture at constant rates. The small fracture is created and the ]SIP and FCP are noted as before. A minimum of two such tests should be performed to verify results (Fig. 4).
CASED HOLE MICROFRACTURING
Cased hole microfracturing is performed in a fashion similar to the open hole procedure. It is, however, mechanically simpler since proper setting and fastening of the cased hole packers is more certain.
A 1 or 2-ft interval of perforations should be phased at 120 or 90, closely spaced (4 shot/ft) and should be of the largest allowable charge. This perforation schedule minimizes distortions on the data from casing holes and cement sheath behind the casing. Occasionally, the formation is broken down from the perforation operation.
The cased hole microfracture test has these advantages:
- Tests can be on weak or incompetent formations that would be otherwise difficult to test.
- Casing packers may be straddled or a packer bridge plug combination may be used to isolate the 4-20 ft zone of interest. These packers are mechanically fastened to the casing. Because of the ease of moving the downhole tools around, five or six different zones can be tested in 1 day.
The cased hole microfracture is performed following the same injection procedure detailed in the open hole section. The subsequent injection tests may be followed by a constant rate flow back as shown in Fig. 5. The point noted in Fig. 5 is the fracture closure pressure (smin). At least two of these tests should be performed together with a pump-in/shut-in test for verification of results.
The main disadvantage of the cased hole microfracture is that the fracture azimuth cannot be determined. Results can also be influenced by casing, cement and perforation orientation, and well bore inclination.
FLUIDS
Open hole microfractures may be created with the drilling fluid in the well bore. If drilling fluid is used, cuttings should be removed, and circulation should be used to establish a more uniform density. It is desirable to perform these tests with a clean, nondamaging fluid with stable, predictable Theological properties. Selection of a fluid depends on the same formation properties considered in conventional fracturing.
Fluid compatibility with the drilling fluid is usually a concern, so some type of spacer fluid should be placed between injection fluid and drilling fluid.
Best results are obtained in open hole microfracturing if drilling mud remains in the annular space to check fluid loss to any other zones or fractures.
SPECIAL EQUIPMENT
Because of the small injection rates and higher pressures observed in these tests, some special equipment is required. Conventional pumps can be modified with plunger-assembly kits for low-rate delivery and adequate horsepower.
A special automatic or manual injection manifold can be used to control the injection rate. The use of this manifold may negate the requirement to use the small plunger-assembly kit.
Small magnetic or turbine flow meters are necessary to accurately measure injection rates. Constant rate flow back tests are performed with special flow back manifolds designed for automatic or for manual control of the flow back rate (Figs. 6 and 7).
Pressure data are best monitored using a downhole gauge with surface readout. Electronic-memory gauges and mechanical gauges may also be used. High-resolution pressure gauges are recommended for monitoring surface pressures.
A computerized data acquisition unit is desirable for recording the pressures and rates for laboratory analysis.
MICROFRACTURE ANALYSIS
As mentioned, the purpose of the microfracture tests is to determine FCP or the pressure required to nominally hold the fracture open. This is defined as equal to the least principal stress of the formation.
The first data point retrieved during a microfracture test is the formation breakdown pressure, a parameter of particular importance in drilling, cementing, and fracturing.
Breakdown is characterized by a pressure "spike" during the initial pressurization of the formation (Fig. 3). Because a crack tip may have been initiated during the perforation operation, breakdown data from a cased hole test may be considered invalid.
Fracture opening pressure (FOP) is the pressure at which an existing fracture may be reopened. This pressure is characterized by a decrease from the constant pressure increase rate during the early time period of a microfracture test cycle. Although it is not as consistent as shut-in or flow back data, this pressure is sometimes used as the value for the least principal stress (Fig. 8).1
Instantaneous shut-in pressure (ISIP) is sometimes referred to in literature as the least principal stress.1 3 This use of ISIP is acceptable in cases where fluid loss is very high and the fracture closes quickly.
The difference between the last pumping pressure and the ISIP is the frictional pressure drop from the tip of the fracture to the pressure recorder. Often, the ISIP is not obvious because of such parameters as fracture width, tortuosity, injection fluid viscosity, change in fluid compressibility, and fluid loss.
A straightforward method is used to determine ISIP. The logarithm of the difference between the last pumping pressure and subsequent pressures vs. the logarithm of time is plotted. The pressure data before ISIP characterizing well bore storage effect are on this plot with a line of unit slope.3 ISIP is often used as an indicator of reliability and repeatability of the various microfracture test cycles.
Fracture closure pressure (FCP) is the preferred definition of smin. The FCP is determined from analysis of after shut-in pressure decline plots.
Classically, if the pressure decline data are plotted vs. the square root of time, the FCP is found to be the point at which the change from straight line to curved line is observed. This method has its difficulties in that sometimes more than one straight line is observed. Some well testing concepts are imported to overcome this problem.
A plot of the logarithm of the difference between ISIP and subsequent pressures vs. the logarithm of time is plotted (similar to the plot in the previous paragraph).6 This plot should yield a line with one-half slope, which usually characterizes a linear or infinite conductivity fracture flow from a fracture treatment. A slope of one fourth characterizes bilinear flow (some combination of finite conductivity fracture and linear flow) in a fracture treatment shut-in.
Microfracture tests usually show little evidence of fracture of bilinear flow in the shut-in tests. Data were usually interpreted using the pressure vs. square root of time plot with the log-log plot as a guide. The end of the one-half slope on the log-log plot usually defines closure pressure.
An alternative method of determining fracture closure pressure from a shut-in pressure decline involves plotting the derivative of the logarithm of the pressure difference with respect to the logarithm of time vs. time.7 Similar to the method in the preceding paragraph, a constant value for the derivative of 1.0 on the plot indicates the well bore storage effect, a constant derivative value of 0.5 indicates infinite conductivity fracture flow, and a constant value of 0.25 indicates finite conductivity fracture flow.
Care should be taken when using these two methods to determine closure pressure because the original theory is based on propped fractures with fixed boundaries. Values of 1, 0.5, or 0.25 are usually approximate. Sometimes these methods cannot be applied to pressure decline analysis.
The microfracture shut-in closure pressure can also be determined from the annulus-pressure reading. When the fracture has propagated around the open hole packers, hydraulic communication is established to the annulus. The annulus pressure increases during pumping and during shut-in until the fracture is closed. The closure pressure can then be determined at the time when the annulus pressure becomes essentially constant (Fig. 9).1
Care should be taken to ensure that thermal effects do not affect analysis of data. Production of gas or the entrapment of air in the surface lines or work string have yielded anomalies similar to those described in Reference 8.
Microfrac flow back data are usually straightforward in interpretation. Classically, the pressure will decrease at a nonconstant rate during the constant-rate flow back. At closure the effects of well bore storage and occasionally radial flow take over and the pressure decline is characterized by a constant rate of pressure decline.2
A filtration test2 is sometimes performed on the well before breakdown. During this test the leakoff rate to the well bore is determined. The test is also a good method of checking the seating of the open hole packers. The test is performed by injecting fluid at low rate until approximate anticipated closure pressure is obtained, then shutting in (more than one test can be performed).
Filtration is calculated as follows:
qL = Qi X P2/(P1 - P2)
where:
qL = Well bore leakoff rate
Q1 = Injection rate
P1 = Pressure increase rate during injection
P2 = Pressure decrease rate during shut-in
FRACTURE DESIGN
These data are often used for placement of perforations. For smaller-sized treatments, the perforations may be biased toward higher stress pay zones. Care should be taken, however, not to isolate or cut off other pay zone areas from fracture flow through this biasing of perforation placement.
The microfrac data may also be used with minifrac fluid loss calibration data (overall fluid loss coefficient and fluid efficiency) as an input in a 3-D fracture-simulator computer program. Adjustments may be made to various input parameters such as rate, total volume, and Theological parameters (n' and K') to design a fracture with a more desirable geometry.
It should be noted that variation of gel concentration and injection rate reduces the validity of an overall fluid loss coefficient or fluid efficiency calculated from a minifrac test.
See Fig. 10 for a radioactive tracer log from that same design. Temperature logs can be used to verify the same.
The stress data and 3-D program can also be used to limit unavoidable fracture height growth. If a barrier is weak, a 3-D program can be used to predict the magnitude of fracture height obtained, given various treatment volumes and rates.
Microfracture data are also essential in the planning of drilling and fracturing a horizontal well bore. Stress magnitudes and fracture design computer programs, such as the 3-D simulators, are used to determine the depth of the horizontal section using data taken from a vertical well.
The azimuth direction of the horizontal well can also be determined using the oriented core retrieved fracture method discussed earlier.
REFERENCES
- Daneshy, A. A., Slusher, G. L., Chisholm, P. T., and Magee, D. A., "In-Situ Stress Measurements During Drilling," SPE 13227, 59th Annual Technical Conference and Exhibition, Houston, Sept. 16-19, 1984.
- Shlyapobersky, J., Walhang, W. W., Sheffield, R. E., and Huckagee, P. T., "Field Determination of Fracturing Parameters for Overpressure Calibrated Design of Hydraulic Fracturing," SPE 18195, 63rd Annual Technical Conference and Exhibition, Houston, Oct. 2-5, 1988.
- Warpinski, N.R., "Determining the Minimum In-Situ Stress from Hydraulic Fracturing Through Perforations," Proceedings of the Second International Workshops of Hydraulic Fracturing Stress Measurements, Vol. 11, June 15-18, 1988, pp. 800-839.
- El Rabaa, A. W., and Meadows, D. L., "Laboratory and Field Applications of the Strain Relaxation Method," SPE 15072, 56th SPE California Regional Meeting, Oakland, Apr. 2-4, 1986.
- Daneshy, A. A., Chisholm, P. T., Magee, D. A.. and Slusher, G. L., "Method of Determining Subterranean Formation Fracture Orientation," United States Patent 4,529,036, July 16, 1985.
- Sookprasong, P. A., "Plot procedure finds closure pressure," OGJ, Sept. 8, 1986, pp. 110-112.
- Jones, C., and Sergeant, J.P., "Obtaining the Minimum Horizontal Stress from Micro-Frac Test Data: A New Approach Utilizing a Derivative Algorithm," SPE 18867, SPE Operations Symposium, Oklahoma City, Mar. 13-14, 1989.
- Stegemeier, G. L., and Matthews, C. S., "A Study of Anomalous Build-up Behavior," Transactions, AIME, 1958.
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