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The most important data for designing a fracture treatment are the in-situ stress profile, formation permeability, fluid-loss characteristics, total fluid volume pumped,propping agent type and amount, pad volume, fracture-fluid viscosity, injection rate, and formation modulus. It is very important to quantify the in-situ stress profile and the permeability profile of the zone to be stimulated, plus the layers of rock above and below the target zone that will influence fracture height growth. There is a structured method that should be followed to design, optimize, execute, evaluate, and reoptimize the fracture treatments in any reservoir. The first step is always the construction of a complete and accurate data set.Table 1 lists the sources for the data required to run fracture propagation and reservoir models. The design engineer must be capable of analyzing logs, cores, production data, and well-test data and be capable of digging through well files to obtain all the information needed to design and evaluate the well that is to be hydraulically fracture treated.
- Well Completion > Hydraulic Fracturing > Fracturing materials (fluids, proppant) (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (0.92)
- Information Technology > Knowledge Management (0.40)
- Information Technology > Communications > Collaboration (0.40)
A Stoneley wave is always possible at solid-fluid interfaces and under very restricted conditions at solid-solid interfaces. See Sheriff and Geldart (1995, 53–54, 133, 489). Stoneley-wave attenuation is sensitive to formation permeability. Named for Robert Stoneley (1894-1976), English seismologist.
- Geophysics > Seismic Surveying (1.00)
- Geophysics > Borehole Geophysics (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (0.81)
- Information Technology > Knowledge Management (0.40)
- Information Technology > Communications > Collaboration (0.40)
Measured in millidarcy (1/1000 darcy) units. The permeability constant k is expressed by Darcy's law as μq/(d'p'/dx), where μ is fluid viscosity, q is linear rate of flow, and d'p'/dx is the hydraulic pressure gradient. The presence of one fluid can change the effective permeability to another fluid, so that in multiphase flow the effective permeabilities of the component fluids may not add to the total permeability.
- Information Technology > Knowledge Management (0.40)
- Information Technology > Communications > Collaboration (0.40)
Patrick W. M. Corbett started in the industry in 1978 at Unocal and worked in various positions in international (United Kingdom, the Netherlands, and Indonesia) exploration and development geoscience. Since coming to Heriot-Watt University in 1989, his research focus has been on the integration of geoscience and engineering through geologic analysis, petrophysical measurement, permeability anisotropy modeling, well test interpretation, dynamic upscaling, and genetic petrophysics. Corbett graduated with a degree in geology (Exeter University, 1977), followed by an MSc in micropalaeontology (University College London, 1978), a postgraduate diploma in geological statistics (Kingston University, 1982), and a PhD and DSc in petroleum engineering and petroleum geoengineering (both from Heriot-Watt University, 1993 and 2006, respectively). Soc., IAS, PESGB, SCA, SEPM, SPE, and SPWLA, and is a Chartered Geologist, and a Chartered Scientist. He has coauthored the books Statistics for Petroleum Engineers and Geoscientists and Cores from the Northwest European Hydrocarbon Province.
- Asia (0.91)
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- Europe > Netherlands (0.49)
- Personal (0.70)
- Instructional Material > Course Syllabus & Notes (0.48)
- Europe > Netherlands (0.89)
- Asia > Indonesia (0.89)
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (0.70)
- Reservoir Description and Dynamics > Reservoir Simulation > Scaling methods (0.55)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (0.55)
- Information Technology > Communications > Collaboration (0.50)
- Information Technology > Knowledge Management (0.40)
Developed in the late 1940s, fracture stimulation, also known as hydraulic fracturing, is the practice of injecting a well with large amounts of frac fluids under high pressure in order to break the rocks. HOW DOES WELL FRACTURING WORK TO STIMULATE PRODUCTION? Stimulation techniques are used to encourage production to flow from the reservoir rocks. Hydrocarbons are located in the spaces between pores of reservoir rock. Production is achieved when these pore spaces are connected and permeability, or the ability to transmit fluids, is such that the hydrocarbons flow out of the rock and into the well.
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (0.40)
- Well Drilling > Wellbore Design > Wellbore integrity (0.32)
- Information Technology > Knowledge Management (0.40)
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Serge A. Shapiro, Elmar Rothert, Volker Rath, and Jan Rindschwentner received the 2002 SEG Best Paper in Geophysics Award for their paper Characterization of fluid transport properties of reservoirs using induced anisotropy.[1] Elmar Rothert received an MS (1999) in geophysics from the University of Goettingen. Since 2000 he has worked on his PhD thesis at the Freie Universitat Berlin. His Research interests include wave propagation in heterogeneous media and seismicity based reservoir characterization. Currently he focuses on the reconstruction of the three dimensional permeability distribution in heterogeneous anisotropic, fluid saturated media to characterize geothermal reservoirs, and aquifers using fluid-induced microseismicity.
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (0.71)
- Information Technology > Knowledge Management (0.40)
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The capacity to flow fluids is one of the most important properties of reservoir rocks. As a result, extensive research has been applied to describe and understand the permeability of rocks tofluid flow. In this page and its associated topics, only single-phase or absolute permeability will be considered. Permeability (k) is a rock property relating the flow per unit area to the hydraulic gradient by Darcy's law, The ratio q/A has the units of velocity and is sometimes referred to as the "Darcy velocity" to distinguish it from the localized velocity of flow within pore channels. The natural unit ofk is length squared; however, petroleum usage castsEq. 1 in mixed units, so that the unit of k is the darcy, which is defined as the permeability of a porous medium filled with a single-phase fluid of 1-cp viscosity flowing at a rate of 1 cm3/s per cross-sectional area of 1 cm2 under a gradient of 1 atm pressure per 1 cm.[1]
- Information Technology > Knowledge Management (0.41)
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Natural petroleum gases contain varying amounts of different (primarily alkane) hydrocarbon compounds and one or more inorganic compounds, such as hydrogen sulfide, carbon dioxide, nitrogen (N2), and water. Characterizing, measuring, and correlating the physical properties of natural gases must take into account this variety of constituents. A dry-gas reservoir is defined as producing a single composition of gas that is constant in the reservoir, wellbore, and lease-separation equipment throughout the life of a field. Some liquids may be recovered by processing in a gas plant. A wet-gas reservoir is defined as producing a single gas composition to the producing well perforations throughout its life.
- Information Technology > Knowledge Management (0.40)
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Relative permeability and capillary pressure defined capillary pressure as the difference in pressure across the interface between two phases, Such as capillary pressure in a soap bubble system. For immiscible fluids distribution in a porous medium, capillary pressure has been defined as the pressure differential between two immiscible fluid phases occupying the same pores caused by interfacial tension between the two phases that must be overcome to initiate flow. With Laplace's equation, the capillary pressure Pcow between adjacent oil and water phases can be related to the principal radii of curvatureR1 and R2 of the shared interface and the interfacial tensionσow for the oil/water interface: The relationship between capillary pressure and fluid saturation could be computed in principle, but this is rarely attempted except for very idealized models of porous media. Methods for measuring the relationship are discussed in Measurement of capillary pressure and relative permeability. Figure 1 shows a sketch of a typical capillary pressure relationship for gas invading a porous medium that is initially saturated with water; the gas/water capillary pressure is defined asPcgw pg-pw.
- North America > United States > South Dakota > Williston Basin (0.99)
- North America > United States > North Dakota > Williston Basin (0.99)
- North America > United States > Montana > Williston Basin (0.99)
- North America > United States > Alaska > North Slope Basin > Prudhoe Bay Field (0.99)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Information Technology > Knowledge Management (0.40)
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Relative permeability and capillary pressure defines relative permeabilities as dimensionless functions of saturation with values generally ranging between 0 and 1. Relative permeability is important for estimating the flow of reservoir fluids. The semilog scale of Figure 1 is convenient for reading the relative permeabilities less than 0.05. Although the curves are labeled "gas" and "oil" in these figures, the phase identity of a curve can be deduced without the labels. For example, the relative permeability that increases in the direction of increasing oil saturation must be the oil relative permeability. The endpoints of the relative permeabilities inFigs. 1 and 2 are defined by the critical gas saturation Sgc and the residual oil saturationSor.
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