- Industri: Oil & gas
- Number of terms: 8814
- Number of blossaries: 0
- Company Profile:
A monetary incentive given by the lessee (either an individual or company) to the lessor (mineral owner) for executing or ratifying an oil, gas and mineral lease.
Industry:Oil & gas
A multiphase flow regime in near-vertical pipes in which large slugs of gas move up the center of the pipe, usually carrying small droplets of oil or water with them. Most of the remaining oil or water flows up along the pipe walls. The flow is relatively chaotic, producing a frothy mixture containing some large, elongated bubbles. Neither phase is continuous. Froth flow occurs at relatively high gas velocity and is similar to churn flow. As the gas velocity increases, it changes into annular flow.
Industry:Oil & gas
A multiphase flow regime in pipes in which most of the gas moves as large bubbles dispersed within a continuous liquid. The bubbles may span much of the pipe. There are also small bubbles within the liquid, but many of these have coalesced to form the larger bubbles, or plugs. In near-horizontal wells, the plugs are also known as elongated bubbles. Plug flow is similar to slug flow, but the bubbles are generally smaller and move more slowly.
Industry:Oil & gas
A multiphase flow regime in which the lighter fluid flows in the center of the pipe, and the heavier fluid is contained in a thin film on the pipe wall. The lighter fluid may be a mist or an emulsion. Annular flow occurs at high velocities of the lighter fluid, and is observed in both vertical and horizontal wells. As the velocity increases, the film may disappear, leading to mist flow or emulsion flow. When the interface between the fluids is irregular, the term wavy annular flow may be used.
Industry:Oil & gas
A model, or set of equations, for the resistivity response of formations with conductive minerals, such as shaly sands. The model is used to analyze core data and to calculate water saturation from resistivity and other logs. The conductive rock matrix model (CRMM) was proposed by W. Givens. The model treats the rock as two components in parallel: a conductive pore network with fluid that is free to move, and the remainder of the rock, which may have conductive minerals or immobile but conductive water. The model is not concerned with the origin of this conductivity, but gives it a resistivity, R<sub>m</sub>. The two components are in parallel as follows:<br><br><br> 1 / R<sub>t</sub> = 1 / R<sub>p</sub> + 1 / R<sub>m</sub><br><br><br>where R<sub>p</sub> is the resistance of the free-fluid pore network and can be expressed in terms of the porosity and formation water resistivity by the Archie equation. The model was developed from core data, and can explain the observed variations of the porosity exponent with porosity and the saturation exponent with water saturation in shaly sands. For log analysis R<sub>m</sub> needs to be related to parameters that can be measured by logs. <br><br>Reference:<br><br>Givens WW: Formation Factor, Resistivity Index and Related Equations Based upon a Conductive rock Matrix Model (CRMM), Transactions of the SPWLA 27<sup>th</sup> Annual Logging Symposium, Houston, Texas, USA, June 9-13, 1986, paper P.
Industry:Oil & gas
A multiphase fluid incorporating a liquid base and gaseous nitrogen. Nitrified fluids are frequently used in stimulation treatments to enhance the performance of the treatment fluid and improve the cleanup process following the treatment.
Industry:Oil & gas
A multiphase fluid flow regime characterized by the gas phase being distributed as bubbles through the liquid phase. In a producing wellbore where the bubbles are uniformly distributed, there is little relative motion between the phases. Where the bubbles congregate and combine to form a less uniform distribution of the gas phase, some slippage will occur between the phases with the gas tending to cut through the liquid phase.
Industry:Oil & gas
A model of shaly formations that considers there to be two waters in the pore space: far water, which is the normal formation water; and near water (or clay-bound water) in the electrical double layer near the clay surface. The clay-bound water consists of clay counter-ions and the associated water of hydration. The volume of this layer is determined by its thickness, which is constant at high salinities, and its area, which is proportional to the counter-ion concentration per unit pore volume (Q<sub>v</sub>). The volume of clay-bound water per unit pore volume, S<sub>wb</sub>, can therefore be written as:<br><br><br><br> S<sub>wb</sub> = alpha * v<sub>q</sub> * Q<sub>v</sub><br><br><br><br>where v<sub>q</sub> = 0. 28 cm<sup>3</sup>/meq at 25<sup>o</sup>C is the factor relating volume to counter-ion concentration at high salinity and is a function only of temperature, and alpha = 1 above a certain salinity, below which it increases with temperature and with decreasing salinity. The fractional volume of the far water is then (1 ? alpha?* v<sub>q</sub> * Q<sub>v</sub>). <br><br>The dual-water concept was developed for the interpretation of resistivity in shaly sands, but is also useful in the interpretation of nuclear and nuclear magnetic resonance logs. In these cases, the parameter most used is the total volume of clay-bound water in the rock, equal to S<sub>wb</sub> multiplied by the total porosity.
Industry:Oil & gas
A model of a specific volume of the subsurface that incorporates all the geologic characteristics of the reservoir. Such models are used to quantify characteristics within the subsurface volume that are relatively stable over long periods of time and can, therefore, be considered static. These attributes include the structural shape and thicknesses of the formations within the subsurface volume being modeled, their lithologies, and the porosity and permeability distributions. These last two characteristics often vary significantly from location to location within the volume, resulting in heterogeneity. However, porosity and permeability are stable in the near-geologic timeframe and do not change due to the movement of fluids or gases through any of the formations鈥?pore spaces. The result of reservoir characterization is a reservoir characterization model (also known as a 鈥渟tatic model鈥?and sometimes referred to as a 鈥済eologic model鈥?. <br><br>Shale gas reservoir rocks require the analysis of high-quality seismic data, core, and log measurements and engineering data to produce an accurate reservoir characterization model. This model is then used as input into reservoir simulation, during which reservoir engineers add other reservoir characteristics, such as pressures, temperatures, and fluid and gas compositions. These features can change due to the movement of fluids or gases through any of the formations鈥?pore spaces. Since these are dynamic in their nature over short timeframes, once production is initiated these models are referred to as 鈥渄ynamic models. 鈥?Thorough reservoir simulations (dynamic models) that are based on accurately developed reservoir characterizations (static models) can be of significant value in optimizing well placement and field-development planning. <br>
Industry:Oil & gas
A model of a reservoir in which the steady-state flow and the advective transport are described in two or three dimensions by a computer program. A flow model is an essential component of a reservoir simulator. Flow models are often derived from the petrophysical characteristics of a reservoir (especially porosities and permeabilities) and then the model is adjusted and refined until it correctly predicts the reservoir's past behavior and can match the historical pressure and production data.
Industry:Oil & gas
