Fracture pressures

In steam stimulation, heat and drive energy are suppHed in the form of steam injected through weUs into the tar sand formation. In most instances, the injection pressure must exceed the formation fracture pressure in order to force the steam into the tar sands and into contact with the oil. When sufficient heating has been achieved, the injection weUs are closed for a soak period of variable length and then allowed to produce, first applying the pressure created by the injection and then using pumps as the weUs cool and production declines. 

To date (ca 1997), steam methods have been appHed almost exclusively in relatively thick reservoirs containing viscous cmde oils. In the case of heavy oil fields and tar sand deposits, the cycHc steam injection technique has been employed with some success. The technique involves the injection of steam at greater than fracturing pressure, usually in the 10.3—11.0 MPa (1500—1600 psi) range, foUowed by a soak period, after which production is commenced (15). 

Subsurface Rock Fracture Pressure (Fracture Pressure Gradient). The subsurface rock fracture pressure can be approximated by utilizing the known pore pressure at the same depth. The relationship between rock fracture pressure p (psi) and pore pressure p (psi) is [34]... 

The rock fracture pressure gradient at depth can be approximated by using Equation 2-174 and the variable Poisson s ratios versus depth data (Figure 2-58) and the variable total overburden stress gradients versus depth data (Figure 2-59). 

In Figure 2-57 the pore pressure gradient has been given as a function of depth for a typical Gulf Coast well. Determine the approximate fracture pressure gradient for a depth of 10,000 ft. From Figure 2-57, the pore pressure gradient at 10,000 ft is... 

This value of 0.90 psi/ft falls on the dashed line of Figure 2-57. The entire dashed line (fracture pressure gradient) in Figure 2-57 has been determined by using Equation 2-174. 

In general. Equation 2-174 can be used to approximate fracture pressure gradients. To obtain an adequate approximation for fracture pressure gradients, the pore pressure gradient must be determined from well log data. ALso, the overburden stress gradient and Poisson s ratio versus depth must be known for the region. 

There is a field operation method by which the fracture pressure gradient can be experimentally verified. Such tests are known as leak-off tests. The leak-off test will be discussed in Chapter 4. 

When controlling a well, be careful not to exceed the fracture pressure anywhere in the open-hole section. An intermediate casing may have to be set to avoid the fracture condition. 

Compute the fracturation pressure gradient and fracturation pressure at 8,460 ft assuming a Poisson ratio of 0.4. 

Solving the above equation yields p, = 5,561 psi. Since the maximum expected pressure in an open hole is less than the formation fracture pressure, the kick can be safely circulated out of the hole. 

Currently, a graphical method of casing setting depth determination is used. The method is based on the principle according to which the borehole pressure should always be greater than pore pressure and less than fracture pressure. 

Suppose that in some area the expected formation pressure gradient is 0.65 psi/ft and formation fracture pressure gradient is 0.85 psi/ft. A gas-bearing... 

Hesitation continues until no pressure leak-off is observed. A further test of about 500 psi over the final injection pressure will indicate the end of the injection process. Usually, well-cementing perforations will tolerate pressures above the formation fracture pressure, but the risk of fracturing is increased. 

In the third type of acidizing, fracture acidizing, acid is injected above the parting or fracture pressure of the formation. The acid reacts with the minerals on the exposed fracture face in a process called etching. With sufficient etching, the fracture does not reseal when normal well production or injection operations are resumed. 

Nolte, K.G. and Smith, M.B. "Interpretation of Fracturing Pressures," SPE paper 8297, 1979 SPE Annual Technical Conference and Exhibition, Las Vegas, September 23 26. 

Nolte, K.G. "Determination of Proppant and Fluid Schedules from Fracturing-Pressure Decline," SPE Prod. Eng.. July 1986, 255-265. 

Vandanme, L., Jeffrey, R.G. and Curran, J.H. "Effects of Three-Dimensionalization on a Hydraulic Fracture Pressure Profile," 1986 Proc. U.S. Sumposium on Rock Mechanics Key to Energy Production 580-590, Tuscaloosa, Alabama, June 23-25. 

Disposal of brine in subsurface wells is probably the most widely used control method, especially in the western and southern oil and gas producing states [23]. For this to be an effective disposal option, two conditions must be met the natural aquifer must be naturally saline and must not leak to freshwater aquifers, and the reinjection pressure must not exceed the fracture pressure of the formation [9]. Produced water is usually pretreated to prevent equipment from being corroded and to prevent plugging of the sand at the base of the well. Pretreatment may include the removal of oils and floating material, suspended solids, biological growth, dissolved gases, precipitable ions, acidity, or alkalinity [27]. A typical system is shown in Fig. 12. 

Comparison of Observeu anu Theoretical (Kinetic Approach) Limiting Fracture Pressures (B12, B13, B15)... 

All these fracture pressures are large negative pressures, the liquid being under great tension. The values show that the kinetic approach can be used to predict limiting values for this condition. If a substance were... 

Stimulation fluid is a treatment fluid prepared for stimulation purposes, although the term most commonly is applied to matrix stimulation fluids. Most matrix stimulation fluids are acid or solvent-based, with hydrochloric acid being the most common base due to its reaction characteristics and its relative ease of control. Matrix stimulation is a process of injecting a fluid into the formation, either an acid or solvent at pressures below the fracturing pressure, to improve the production or injection flow capacity of a well. 

Integrating over the time r which represents the interval from the time of application of the fracturing pressures to the time of fracture, we get... 

Wood J. R. (1981) Fracture pressure solution experiment and theory. Geological Association of Canada, Mineralogical Association of Canada Meeting, Abstracts of papers, A63. 

Fracture pressures are estimated from leak-off tests (LOT), where mud is pumped into the formation until the first evidence of fractures is detected. Leak-off pressure is the pressure at which the formation develops very thin fractures prior to rock failure. A great advantage of this kind of test is that it is an in situ test, thus we do not have to deal with relaxation or unloading problems. Fracture pressures estimated from LOT is in the range of 0.6-0.8 times the litho-static pressure, which is within the fracture pressure domain (0.7-0.9 lithostatic pressure) given by DuRouchet (1981). The overpressures do not reach fracture pressure (LOT) in any of the wells investigated. However, the pore pressure reaches 80% of... 

Fig. 14 relates the pore-pressure data from all the wells to the minimum fracture pressure gradient of... 

Fig. 14. Relationships between pore-pressures, the hydrostatic gradient, the fracture pressure gradient (approximation to the minimal horizontal stress, Sf,) and the lithostatic pressure gradient (approximation to the vertical stress, S ). Pore-pressures from sea floor to base Pliocene equals hydrostatic. The yellow, dark blue and red pore-pressure trend-lines represent the pore-pressure versus depth gradients for the Paleocene-Eocene, Mid-late Cretaceous and Upper Jurassic-lowermost Cretaceous, respectively. The portion of the red trend-line below approximately 2550 m MSL equals the maximum reservoir pore-pressure trend-line of Fig. 13 and reflects the counter-pressure of the topseal controlling the pore-pressure distribution of hydraulic compartments II, III and (probably) IV.

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