Content of PetroWiki is intended for personal use only and to supplement, not replace, engineering judgment. SPE disclaims any and all liability for your use of such content. A well into which fluids such as produced water and some liquid wastes can be injected. It is in a non hydrocarbon, non-fresh water sand and is not connected to the hydrocarbon bearing formation.
Content of PetroWiki is intended for personal use only and to supplement, not replace, engineering judgment. SPE disclaims any and all liability for your use of such content. A well where produced water is injected back into a deep, usually depleted zone but one that is not connected to the producing pay zones.
Produced or fresh water being treated may have suspended solids, such as formation sand, rust from piping and vessels, and scale particles, or dissolved solids (various chemical ions). For most uses or disposal methods, these solids may need to be removed. It may be necessary to remove these solids to prevent wear in high-velocity areas, prevent solids from filling up vessels and piping and interfering with instruments, and comply with discharge restrictions on oil-coated solids. This page discusses appropriate removal technologies and handling of the removed material. Solid particles, because of their heavier density (compared to water) and net negative buoyant force, will settle to the bottom with a terminal velocity that can be derived from Stokes' law, as shown in Eq. 1. This equation applies strictly to creeping flow regimes in which the Reynolds number is less than unity; this is mainly concerned with spheres of very small diameter surrounded by a liquid. For very small particles, the inertial forces are much less than the viscous forces because of the low particle mass, and the particle does not enter into a turbulent settling regime. Most sedimentation basins are rectangular flumes with length-to-width ratios of 4:1 or greater to limit crossflow.
Compressibility is the volume change of a material when pressure is applied. When water is produced, the pressure changes from reservoir pressure, affecting the volume of produced water. Understanding the compressibility of formation water is also important to the understanding of volumes of oil, gas, and water in the reservoir rock. The compressibility of formation water at pressures above the bubblepoint is defined as the change in water volume per unit water volume per psi change in pressure. Water compressibility also depends on the salinity.
The formation water density is defined as the mass of the formation water per unit volume of the formation water. Density is determined most accurately in the laboratory on a representative sample of formation water. . Electronic densiometers can quickly determine the density with accuracy of / 0.00001 g/cm3 over a wide range of temperatures, although most oilfield data are reported at a 60 F reference temperature. In the past, density in metric units (g/cm3) was considered equal to specific gravity; therefore, for most engineering calculations, density and specific gravity were interchangeable in most of the older designs. However, process simulation software used in modern facility design uses the true density or specific gravity of the water to avoid significant cumulative errors, especially when working with low-gravity heavy oils or concentrated brines.
This article gives an overview of a pump's effect on the shearing of production fluids in the oil industry. Most of the world's oil reservoirs produce oil together with water. The liquids are subjected to shear forces through the pumps and are sheared as they pass through pressure-reducing devices in the production line. A common oil field emulsion is a dispersion of water droplets in oil. Formation of emulsions in the main separation process is a big concern for the operators.
Ordinary carbon steel is by far the most important alloy in the oil and gas industry because it accounts for more than 98% of the construction materials used in produced-water systems. As a general rule, every attempt should be made to use steel, such as modifying the process with corrosion inhibitors in the fluid or coating the steel. Proper material selection is critical for long operation life and minimal maintenance. A small increase in capital expenditure for an optimum material selection can greatly reduce the mean time to maintenance or failure, thus greatly saving on operating expenses. As a general rule, every attempt should be made to use steel, such as modifying the process with corrosion inhibitors in the fluid or coating the steel.
Produced water typically enters the water-treatment system from either a two or three phase separator, a free water knockout, a gun barrel, a heater treater, or other primary separation unit process. It probably includes small amounts of free or dissolved hydrocarbons and solids that must be removed before the water can be re-used, injected or discharged. The level of removal (particularly for hydrocarbons) and disposal options are typically specified by state, province, or national regulations. This article discusses techniques for the removal of free and dissolved hydrocarbons. See Removing solids from water for information on solids removal. Produced water contains small concentrations (100 to 2000 mg/L) of dispersed hydrocarbons in the form of oil droplets. In applying these concepts, one must keep in mind the dispersion of large oil droplets to smaller ones and the coalescence of small droplets into larger ones, which takes place if energy is added to the system. The amount of energy added per unit time and the way in which it is added will determine whether dispersion or coalescence will take place. Stokes' law, shown in Eq. 1, is valid for the buoyant rise velocity of an oil droplet in a water-continuous phase. Several immediate conclusions can be drawn from this equation.
In situations in which two different waters are being mixed, it is desirable to measure the amounts of each in the mixed stream. If the capability exists, it is desirable to look at each constituent to see if it undergoes any phenomenon other than simple mixing. This can be a powerful technique for detecting water/rock reactions that can lead to formation damage. The fundamental concept is that mixing two waters should result in the volume-weighted average of each constituent of the two original waters, unless some chemical or biological reaction occurred. This is essentially similar in appearance to a binary phase diagram, with the endpoints of the line defined by the concentrations of the constituent in each of the water streams being mixed.