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The first hydraulic fracturing treatment was pumped in 1947 on a gas well operated by Pan American Petroleum Corp. in the Hugoton field. Kelpper Well No. 1, located in Grant County, Kansas, was a low-productivity well, even though it had been acidized. The well was chosen for the first hydraulic fracture stimulation treatment so that hydraulic fracturing could be compared directly with acidizing. Since that first treatment in 1947, hydraulic fracturing has become a common treatment for stimulating the productivity of oil and gas wells. Hydraulic fracturing is the process of pumping fluid into a wellbore at an injection rate that is too high for the formation to accept without breaking.
Dealing with and exploiting fracturing of rock has been part of mining engineering for hundreds of years, but the analysis of fracture of rock or other materials has only developed into an engineering discipline since the mid 1940s . In petroleum engineering, fracture mechanics theories have been used for more than 50 years. Rock fracture mechanics is about understanding what will happen to the rocks in the subsurface when subjected to fracture stress. Much of what is used in hydraulic fracturing theory and design was developed by other engineering disciplines many years ago. However, rock formatons cannot often be treated as isotropic and homogeneous.
Geological effects can impact the design and successful completion of oil, gas, and geothermal wells. Understanding the stresses and pore pressures within the subsurface are important to development of a geomechanical model that can guide well design as part of an integrated process to minimize cost and maximize safety. Forces in the Earth are quantified by means of a stress tensor, in which the individual components are tractions (with dimensions of force per unit area) acting perpendicular or parallel to three planes that are in turn orthogonal to each other. The normals to the three orthogonal planes define a Cartesian coordinate system (x1, x2, and x3). The stress tensor has nine components, each of which has an orientation and a magnitude (see Figure 1.a).
Introduction The first hydraulic fracturing treatment was pumped in 1947 on a gas well operated by Pan American Petroleum Corp. in the Hugoton field. Kelpper Well No. 1, located in Grant County, Kansas, was a low-productivity well, even though it had been acidized. The well was chosen for the first hydraulic fracture stimulation treatment so that hydraulic fracturing could be compared directly with acidizing. Since that first treatment in 1947, hydraulic fracturing has become a common treatment for stimulating the productivity of oil and gas wells. Hydraulic fracturing is the process of pumping a fluid into a wellbore at an injection rate that is too great for the formation to accept in a radial flow pattern. As the resistance to flow in the formation increases, the pressure in the wellbore increases to a value that exceeds the breakdown pressure of the formation open to the wellbore. Once the formation "breaks down," a fracture is formed, and the injected fluid begins moving down the fracture. In most formations, a single, vertical fracture is created that propagates in two directions from the wellbore. These fracture "wings" are 180 apart and normally are assumed to be identical in shape and size at any point in time; however, in actual cases, the fracture wing dimensions may not be identical. In naturally fractured or cleated formations, it is possible that multiple fractures can be created and propagated during a hydraulic fracture treatment. Fluid that does not contain any propping agent (called the "pad") is injected to create a fracture that grows up, out, and down, and creates a fracture that is wide enough to accept a propping agent. The purpose of the propping agent is to prop open the fracture once the pumping operation ceases, the pressure in the fracture decreases, and the fracture closes.
Understanding rock properties and how they react under various types of stress is important to development of a geomechanical model before drilling. Some major geomechanical rock properties are described below. To first order, most rocks obey the laws of linear elasticity. In other words, the stress required to cause a given strain, or normalized length change (Δlk /ll), is linearly related to the magnitude of the deformation and proportional to the stiffnesses (or moduli), Mijkl. Furthermore, the strain response occurs instantaneously as soon as the stress is applied, and it is reversible--that is, after removal of a load, the material will be in the same state as it was before the load was applied.
An understanding of rock strength is important for designing recovery plans for a reservoir and for developing an appropriate reservoir simulation. A detailed discussion of rock failure can be found in Rock failure relationships and Compressive strength of rocks. But the data needed for these methods may not be readily available, so there is a desire to use data available from well logs that are available. Several techniques have been proposed for deriving rock strength from well log parameters. Coates and Denoo calculated stresses induced around a borehole and estimated failure from assumed linear envelopes with strength parameters derived from shear and compressional velocities.
This page provides an introduction to stress-strain relationships. They form the foundation for several rock properties such as elastic moduli (incompressibility), effective media theory, elastic wave velocity, and rock strength. Stress is the force per unit area. The metric units of stress or pressure are N/m2 or Pascals (Pa). Other units that are commonly used are bars, megapascals (MPa), and lbm/in.2 These are illustrated in Figure 1.
The primary fluids encountered are brines and hydrocarbon oils and gases. Drilling, completion, and fracturing fluids can also be present, and their effects are typically studied to prevent formation damage. This page will concentrate on the role of water and, in particular, how water saturation can influence rock strengths measured in the laboratory or derived from well logs. Pore fluid pressures will reduce the effective stress supported by the rock mineral frame. For an elementary volume of rock the effective stress can be defined as the stress, depending on the applied tension σ and pore pressure p, which controls the strain or strength behaviour of soil and rock (or a generic porous body) for whatever pore pressure value or, in other terms, the stress which applied over a dry porous body (i.e. at p 0) provides the same strain or strength behaviour which is observed at p 0. This effect has been well known since the publication of Karl Terzaghi (e.g.
Understanding rock failure relationships is important because under reservoir pressure and stress conditions, production can induce rock failure, sometime with catastrophic effects. By applying strength criteria, within reservoir simulators we can predict when problems might occur. Stress strain relationships in rocks examined the elastic behavior of rocks, which was largely reversible. Here we deal with permanent deformation. By rock failure, we mean the formation of faults and fracture planes, crushing, and relative motion of individual mineral grains and cements.