- Industry: Oil & gas
- Number of terms: 8814
- Number of blossaries: 0
- Company Profile:
The process of removing colloidal materials from water. A chemical coagulant (for example, alum) or a chemical flocculant (for example, polymer) or both are added to the water. Colloidal particles attach to each other and to the additives and clumps grow to sufficient size that they can be separated from the water by gravity settling, centrifuging, hydrocycloning or filtration. Clarification is a final step in a closed mud system when a clear effluent is needed.
Industry:Oil & gas
The process of pulling the drillstring out of the wellbore for the purpose of changing a worn or underperforming drill bit. Upon reaching the surface, the bit is usually inspected and graded on the basis of how worn the teeth are, whether it is still in gauge and whether its components are still intact. On drilling reports, this trip may be abbreviated as TFNB (trip for new bit).
Industry:Oil & gas
The process of droplet growth as small drops merge together when they come in contact. If this occurs repeatedly, a continuous liquid phase forms. Through this phenomenon, emulsions break and form two distinct liquid phases that tend to separate. In oil-base mud, the water phase is dispersed as small droplets, with oil as the continuous (external) phase. A stable oil mud will remain dispersed under normal drilling conditions because when droplets contact each other, they do not coalesce due to the strong emulsifier film around each droplet. However, when the emulsion film around each droplet becomes weakened, droplets will begin to coalesce. If not corrected, this can lead to total emulsion breakdown with solids becoming water-wetted.
Industry:Oil & gas
The process of adding fresh mud (or liquid phase) in order to reduce the solids content and maintain the properties of the drilling fluid in the active system.
Industry:Oil & gas
The process by which complex molecules are broken down by micro-organisms to produce simpler compounds. Biodegradation can be either aerobic (with oxygen) or anaerobic (without oxygen). The potential for biodegradation is commonly measured on drilling-fluid products to ensure that they do not persist in the environment. A variety of tests exist to assess biodegradation.
Industry:Oil & gas
The process of a mud becoming "gelled-up" or developing high gel strength.
Industry:Oil & gas
The primary and probably most important device on the rig for removing drilled solids from the mud. This vibrating sieve is simple in concept, but a bit more complicated to use efficiently. A wire-cloth screen vibrates while the drilling fluid flows on top of it. The liquid phase of the mud and solids smaller than the wire mesh pass through the screen, while larger solids are retained on the screen and eventually fall off the back of the device and are discarded. Obviously, smaller openings in the screen clean more solids from the whole mud, but there is a corresponding decrease in flow rate per unit area of wire cloth. Hence, the drilling crew should seek to run the screens (as the wire cloth is called), as fine as possible, without dumping whole mud off the back of the shaker. Where it was once common for drilling rigs to have only one or two shale shakers, modern high-efficiency rigs are often fitted with four or more shakers, thus giving more area of wire cloth to use, and giving the crew the flexibility to run increasingly fine screens.
Industry:Oil & gas
The pressure, usually measured in pounds per square inch (psi), at the bottom of the hole. This pressure may be calculated in a static, fluid-filled wellbore with the equation:<br><br>BHP = MW * Depth * 0. 052<br><br>where BHP is the bottomhole pressure in pounds per square inch, MW is the mud weight in pounds per gallon, Depth is the true vertical depth in feet, and 0. 052 is a conversion factor if these units of measure are used. For circulating wellbores, the BHP increases by the amount of fluid friction in the annulus. The BHP gradient should exceed the formation pressure gradient to avoid an influx of formation fluid into the wellbore. <br><br>On the other hand, if BHP (including the added fluid friction pressure of a flowing fluid) is too high, a weak formation may fracture and cause a loss of wellbore fluids. The loss of fluid to one formation may be followed by the influx of fluid from another formation.
Industry:Oil & gas
The pressure that must be applied to the low-salinity side of an osmotic system to prevent water movement into the high-salinity side by osmosis. Conversely, it is the suction pressure that a high-salinity system exerts on the low-salinity system across a semipermeable membrane in an osmotic system.
Industry:Oil & gas
The pressure of the subsurface formation fluids, commonly expressed as the density of fluid required in the wellbore to balance that pore pressure. A normal gradient might require 9 lbm/gal (1. 08 kg/m<sup>3</sup>), while an extremely high pressure gradient might be 18 lbm/gal (2. 16 kg/m<sup>3</sup>) or higher.
Industry:Oil & gas
