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Fracture diagnostic techniques
Fracture diagnostics involves analyzing the data before, during, and after a hydraulic fracture treatment to determine the shape and dimensions of both the created and propped fracture. Fracture diagnostic techniques are divided into several groups.
Direct far-field techniques
Direct far-field methods consists of tiltmeter-fracture-mapping and microseismic-fracture-mapping techniques. These techniques require sophisticated instrumentation embedded in boreholes surrounding the well to be fracture treated. When a hydraulic fracture is created, the expansion of the fracture causes the earth around the fracture to deform. Tiltmeters can be used to measure the deformation and to compute the approximate direction and size of the created fracture. Surface tiltmeters are placed in shallow holes surrounding the well. Downhole tiltmeters are placed in vertical wells at depths near the zone to be fracture treated. As with surface tiltmeters, downhole tiltmeter data are analyzed to determine the orientation and dimensions of the created fracture.
Microseismic fracture mapping relies on a downhole receiver array of accelerometers or geophones to locate microseisms or microearthquakes that are triggered by shear slippage in natural fractures surrounding the hydraulic fracture. Fig. 1 illustrates the principle of microseismic fracture mapping. In essence, noise is created in a zone surrounding the hydraulic fracture. With sensitive arrays of instruments, the noise can be monitored, recorded, analyzed, and mapped.
Although direct far-field techniques can be used to map hydraulic fractures, the technology is still under development. When the technology is used in a field, the data and knowledge gained are often used on subsequent wells to spread out the costs. Knowing the fracture orientation is useful in planning field development and in optimizing future fracture treatments.
Direct near-wellbore techniques
Direct near-wellbore techniques are run in the well that is being fracture treated to locate or image the portion of fracture that is very near (within inches of) the wellbore. Direct near-wellbore techniques consist of tracer, temperature, production, borehole image, downhole video, and caliper logs. If a hydraulic fracture intersects the wellbore, these direct near-wellbore techniques can be of some benefit in locating the hydraulic fracture.
However, these near-wellbore techniques are not unique and cannot supply information on the size or shape of the fracture once the fracture is two to three wellbore diameters in distance from the wellbore. In naturally fractured reservoirs, in which multiple fractures are likely to exist, the reliability of direct near-wellbore techniques are even more speculative. As such, direct near-wellbore techniques are used only to find where the hydraulic fracture exited the wellbore and to map the fracture that is essentially connected directly to the wellbore.
Indirect fracture techniques
Indirect fracture techniques consist of:
- Hydraulic fracture modeling of net pressures
- Pressure-transient-test analyses
- Production-data analyses
Because the fracture-treatment data and the post-fracture production data are normally available on every well, the indirect fracture diagnostic techniques are the most widely used methods to determine the shape and dimensions of both the created and the propped hydraulic fracture.
The fracture-treatment data can be analyzed with a pseudo-three-dimensional (P3D) fracture propagation model to determine the shape and dimensions of the created fracture. The P3D model is used to history match the fracturing data, such as injection rates and injection pressures. Data, such as the in-situ stress and permeability in key layers of rock, can be varied (within reason) to achieve a history match of the field data.
Post-fracture production and pressure data can be analyzed with a 3D reservoir simulator to estimate the shape and dimensions of the propped fracture. Values of formation permeability, fracture length, and fracture conductivity can be varied in the reservoir model to achieve a history match of the field data.
The main limitations of these indirect techniques are that the solutions may not be unique and may require as much fixed data as possible. For example, if the engineer has determined the formation permeability from a well test or production test before the fracture treatment, so that the value of formation permeability is known and can be fixed in the models, the solution concerning values of fracture length become more unique. Most of the information in the literature concerning post-fracture analyses of hydraulic fractures has been derived with these indirect fracture diagnostic techniques.
Limitations of fracture diagnostic techniques
Warpinski discussed many of these same fracture diagnostic techniques. Table 1 lists certain diagnostic techniques and their limitations. Fracture diagnostic techniques do work and can provide important data when entering a new area or a new formation. In most cases, however, fracture diagnostics is expensive, which limits its widespread use in industry. In the future, if costs are reduced, fracture diagnostics may become more widely applied.
Net pressure is defined as the pressure in the fracture minus the in-situ stress. Nolte and Smith published a classic paper that can be used to interpret net-pressure behavior in the field or after the treatment to determine estimates of fracture growth patterns. Their analysis method uses the Perkins-Kern-Nordgren (PKN) theory, which assumes that as long as the fracture height is contained, the net pressure will increase with time according to
where 1/8 < e < 1/5, and slope e = 1/5 for low leakoff and 1/8 for high leakoff.
When Nolte and Smith began analyzing bottomhole pressure data collected during fracture treatments, they found that the PKN theory held for certain situations, but other fracture propagation modes were observed. Fig. 2 summarizes their findings. In Fig. 2, Mode I conforms to Eq. 1; however, three other modes were identified by analyzing field data.
Fig. 2—Interpretation of fracturing pressures.
Mode II conforms to either stable height growth or increased fluid loss. Mode II fracturing is not unusual, nor is it cause for concern. Lateral fracture growth during Mode II is less than Mode I, but the fracture is still being propagated and can be filled with proppant.
When the slope of the graph of log(pn) vs. log(Δt) increases to a unit slope (Mode III), then the fracture has stopped propagating in length, and the fracture is being inflated as the net pressure increases. This is the desired behavior if a tip screenout treatment has been designed. During Mode III, it is still possible to pack the fracture with proppant; however, the pressure has to be monitored closely to be certain the maximum allowable surface injection pressure is not exceeded. Mode IV occurs when the fracture height is increasing rapidly. Normally, rapid height growth is not desirable, and the fracture treatment should be flushed and terminated if Mode IV is reached during the treatment.
The pressures analyzed in a "net pressure graph," such as Fig. 2, are bottomhole pressures and should be corrected for near-wellbore pressure drops. Fig 3 shows the pressures in the entire system. During every fracture treatment, the surface pressure can be measured. On certain wells, the bottomhole treating pressure (BHTP), which is the pressure inside the wellbore at the perforations, can be measured. If the BHTP is not measured directly, then that value must be computed with the surface pressure and the estimates of pipe friction and hydrostatic head. The hydrostatic head can be estimated accurately, even when propping agents are being added, because a densitometer is used to measure the density of the slurry as it is pumped. Problems may occur in trying to estimate the pipe friction when using crosslinked polymer fluids containing propping agents. Significant errors can occur in the pipe friction estimates when high proppant concentrations (> 4 ppg) are being pumped.
If the BHTP is computed or measured successfully, the near-wellbore pressure drop must be subtracted to determine the pressure in the fracture near the wellbore, pf. The pressure in the fracture near the wellbore is the value that must be known and analyzed to determine the width, height, and length of the fracture with either net pressure theory or P3D fracture propagation models. The near-wellbore pressure drop is composed of two parts: the perforation friction and tortuosity. By running a step-down test before the main fracture treatment, the near-wellbore pressure drop often can be estimated accurately. One problem is that the perforation friction and the tortuosity pressure drop can change during the treatment as the propping agent is introduced. The propping agent can erode perforations or plug some of the pathways that are causing the tortuosity pressure drops. At the end of the treatment, the pressure data need to be analyzed as the pumps are shut down to determine if the near-wellbore pressure drop has changed during the treatment.
|'p′n||=||critical net pressure, m/Lt2|
|Δt||=||change in time, t|
- Cipolla, C.L. and Wright, C.A. 2000. State-of-the-Art in Hydraulic Fracture Diagnostics. Presented at the SPE Asia Pacific Oil and Gas Conference and Exhibition, Brisbane, Australia, 16–18 October. SPE-64434-MS. http://dx.doi.org/10.2118/64434-MS.
- Warpinski, N.R. 1996. Hydraulic Fracture Diagnostics. SPE Journal of Petroleum Technology 48 (10): 907-910. SPE-36361-MS. http://dx.doi.org/10.2118/36361-MS.
- Nolte, K.G. and Smith, M.G. 1981. Interpretation of Fracturing Pressures. J Pet Technol 33 (9): 1767–1775. SPE-8297-PA. http://dx.doi.org/10.2118/8297-PA.
- Williams, B.B., Gidley, J.L., and Schechter, R.S. 1979. Acidizing Fundamentals, 55. New York: SPE/AIME.