1 Sep, 2019
Introduction to Hydraulic Fracturing
Oil and gas are produced from various types of reservoirs. With geologic time and tectonic forces, hydrocarbon is trapped in the porosity of different types of sedimentary rock located in various parts of the world. When a wellbore is drilled into a pressurized hydrocarbon-bearing formation, there is a tendency for the oil and gas contained in the pore spaces of the formation rock to flow into the wellbore and then to the surface. Because of the distribution of the hydrocarbon around the wellbore, it migrates to the wellbore from all parts of the formation. The flow regime under these conditions is called radial flow (see Figure 1).
Figure 1. Radial Flow into an Unfractured Wellbore
When a well produces under radial flow conditions, production capacity is dependent upon the difference between the reservoir pressure and the pressure at the wellbore, ΔP, and the formation flow capacity, kh, a product of the formation permeability (k) and the formation pay thickness (h).
The flow of a producing well can be greatly altered (and improved) with hydraulic fracturing. This Tip of the Month discusses hydraulic fracturing with a focus on why we do it, fracture mechanics and factors that influence fracture geometry.
In the fracturing process, a fluid is injected at sufficiently high hydraulic pressures to actually cause the formation to fail (fracture) at the wellbore. With continued pumping, a high permeability fracture is created in the formation. In sandstone formations and sometimes also in carbonates, the created fracture is kept “propped open” using proppant such as graded sand or synthetic granulated material. In carbonates, acid can be pumped as part of the fracturing fluid to react with and dissolve the formation rock along the crack. The acid reaction increases the permeability of the fracture by creating acid-etched channels that remain open when the fracture closes. Flow along the fracture into the wellbore is linear (see Figure 2).
Figure 2. Linear Flow Through a Fracture System
Creation of a linear flow pattern results in an accelerated rate of recovery from the reservoir. The fracture greatly reduces the amount of pressure drop (ΔP) required to flow hydrocarbon from the formation.
It has been shown that favorable economics and improved reservoir drainage can be accomplished with the use of fracturing. Accelerated recovery from a reservoir means that reserves can be produced in a shorter period of time. This has favorable implications in both high permeability and low permeability formations.
Understandably, fracturing is frequently used to increase production rate in low permeability wells. The areal contact of the high permeability fracture system deep into the reservoir creates a marked improvement on the flow rate from the low permeability formation and on the amount of reserves that can be economically produced.
Benefits are also seen in fracturing high permeability sandstone reservoirs using high concentrations of proppant and relatively small volume treatments called frac pack treatments. Also, acid fracturing is being used to help provide sustained high production rates in high flow rate gas wells producing from moderate permeability carbonates. In high deliverability wells, fracturing not only provides an initial production uplift due to the presence of the high flow capacity fracture, but the fracture also allows more efficient reservoir drainage with the inducement of linear flow, producing with less pressure drop (ΔP).
The productivity index, or PI, provides an indication of the effectiveness of hydraulic fracturing. Since the native permeability (k) is an unchangeable reservoir characteristic, reservoir permeability has a high degree of influence on the production rate of the well. For a given formation, the lower the pressure drop (ΔP) required for production, the more effective the well stimulation. The equation for Productivity Index (J) is:
There are many important relationships in fracture mechanics that influence fracture growth behavior under field conditions. An understanding of these relationships is important prior to a discussion concerning fracture modeling and computerized fracture design.
Fracture Orientation and Azimuth
In the early applications of hydraulic fracturing in the 1940’s and 1950’s, it was assumed that the plane of all created fractures was horizontal (with respect to the wellbore) since it was believed that most fracture initiation would occur between laminated bedding planes. Early wellbore diagnostics (impression packers and temperature surveys, primarily) conducted in the early 1960’s coupled with laboratory experimentation using stressed blocks of rock, showed that most fractures are vertical (with respect to the wellbore) and not horizontal as previously assumed. Rock stresses dictate the orientation of the created fracture plane (i.e. whether the fracture is vertical or horizontal), and also influence the azimuth, or projected compass direction, of the created fracture plane.
For analysis of the influence of stresses on fracturing, stress acting on formation rock can be resolved into three primary components: two horizontal stresses (σx and σy) and one vertical stress (σz), as shown in Figure 3. The total stress on a formation is the sum of the three components of stress plus the fluid pore pressure (or reservoir pressure, pr). The pore pressure inside the formation helps to support the stress. Pore pressure is present because of the confined fluid (primarily oil and gas, in hydrocarbon reservoirs) and the weight of the overburden strata. The pore pressure is exerted unilaterally along the primary axes of each of the components of rock stress.
Figure 3. Principal Rock Stresses
When a hydraulic fracturing treatment is pumped into a formation, the creation of the fracture requires tensile rock failure at the wellbore. The direction and orientation of the generated fracture is dictated by the in-situ rock stresses. The induced fracture will always occur perpendicular to the least principal rock stress. For example, if σx is the least principal stress, the created fracture will be generated in the orientation and direction represented by the plan view shown in Figure 4 below.
Figure 4. Plan View of Vertical Fracture Created Perpendicular to σx
If the vertical stress, σz, is the least component of stress, then the created fracture will be in the horizontal plane perpendicular to the wellbore. Experience has shown that horizontal fractures are obtained in very shallow reservoirs, where the overburden stress (σz) is the least principal stress. However, vertical fractures have been measured using impression packers in wells as shallow as 1,100 ft. Of course, deviated fractures and other anomalies are possible in regions of abnormal rock stresses due to severe folding and faulting, but in most applications we typically deal with vertical fractures. Most industry efforts in developing models and in understanding fracture behavior and fracturing pressures have been based on vertical fracture systems.
In addition to the principal rock stresses dictating the vertical or horizontal orientation of the fracture, they also influence the fracture azimuth or the compass direction of the created vertical fracture. Knowledge of fracture azimuth is important on a field-wide basis for two reasons: 1) to help minimize interference between fractured wells and 2) to take advantage of the fracture azimuths during secondary and tertiary recovery efforts. Figure 5 illustrates a case where interference is likely between two fractured wells and Figure 5 illustrates how knowledge of fracture azimuth can be used in field application.
Figure 5. Schematic of Fractured Wells Where Interference is Likely
Although general fracture azimuth trends are known in geologic regions, fracture azimuths for specific wells in a field should be locally determined. Several techniques are available for measuring or forecasting fracture azimuths. Some of the methods used to accurately determine fracture azimuth include:
Fracture Height, Width, and Length
The ability of the fracture to improve well production is dependent upon three primary characteristics of the fracture geometry: fracture height, fracture width, and effective fracture length. These parameters are interdependent and are greatly influenced by the rock stresses. A schematic of a propped fracture is shown in Figure 6.
Figure 6. Schematic of Fracture Geometry Depicting wf, hf, and Lf
The drawing in Figure 6 is a theoretical representation of one-half the total fracture geometry. In this case, the Fracture Length (Lf) is actually a “half-length”, since it is assumed there is always a mirror image of the fracture on the left hand side of the wellbore, with identical dimensions as to fracture width, height, and length, 180o opposed to the schematic shown. One must keep this point in mind as one considers the relationship of the fracture to well productivity and as we continue our discussion concerning fracture geometry.
With respect to fracture geometry, fracture width (wf) is important because the width and the permeability of the fracture (kf) determines the fracture conductivity (wfkf), or the ability of the fracture to transport hydrocarbons. Fracture height(hf) is important with respect to the net pay or formation thickness. Excessive fracture height will also limit the amount of fracture length that can be achieved with a given treatment volume. Fracture length (Lf) is the amount of lateral fracture extension into the pay interval. Fracture length is important because it determines the extent of the pay zone to be drained by the fracture.
Factors that Influence Fracture Geometry
The following reservoir characteristics influence fracture geometry:
Formation permeability (ko) - The amount of fracturing fluid lost to the formation along the fracture, during the fracturing process, will be dependent upon the properties of the fracturing fluid and on the formation permeability. When fluid leak off of the fracturing fluid is high, then the fracture length is shorter and the fracture width is narrower.
In situ rock stresses - The width of the fracture will also be influenced by in situ rock stress (minimum principal stress). Fracture height is also controlled by the boundary layers (above and below the pay zone) and the magnitudes of the principal stresses existing in those intervals.
Rock properties – The width of the fracture is inversely proportional to the magnitude of Young’s Modulus of Elasticity. For example, the higher the Young’s Modulus, the narrower the fracture tends to be. Other rock properties such as Poisson’s Ratio and compressibility also influence fracture geometry but to a lesser extent.
Reservoir pressure – The fracture gradient (used to determine the amount of pressure required to fracture the formation) is related to the pore pressure of the reservoir. Generally, the higher the fracture gradient, the higher the treating pressures observed during the fracturing treatment. If treating pressures approach the maximum allowable treating pressures (for the wellhead and tubing), an unplanned “screen-out” can occur during proppant fracturing. A screen-out occurs when maximum allowable working pressures have been reached and when pumping of proppant-laden fluid cannot be safely continued. Obviously, stopping a fracturing treatment prematurely, with only a portion of the designed volume pumped, may drastically limit the fracture geometry (height, width, and length) obtained with the treatment.
Hydraulic fracturing is an important topic in our industry for many reasons, but most importantly, for its ability to greatly improve the flow of a producing well. Additionally, it has shown to produce favorable economics and improved reservoir drainage. Understandably, hydraulic fracturing is frequently used to increase production rate in low permeability wells but, it is also used in high permeability wells for different reasons such as, to control formation sand production. To learn more about hydraulic fracturing we recommend enrolling in Hydraulic Fracturing Applications (HFU), Advanced Hydraulic Fracturing (AHF) or one of our other Production and Completions courses!
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