Bentonite is not typically used as the primary fluid-loss agent in normal-density slurries. In low-density slurries, where higher concentrations can be used, it may provide sufficient fluid-loss control (400 to 700 cm 3 /30 min) for safe placement in noncritical well applications. Fluid-loss control, obtained through the use of bentonite, is achieved by the reduction of filter-cake permeability by pore-throat bridging. Microsilica imparts a degree of fluid-loss control to cement slurries because of its small particle size of less than 5 microns. The small particles reduce the pore-throat volume within the cement matrix through a tighter packing arrangement, resulting in a reduction of filter-cake permeability.

A number of cementitious materials used for cementing wells do not fall into any specific API or ASTM classification.These materials include: Pozzolanic materials include any natural or industrial siliceous or silico-aluminous material, which will combine with lime in the presence of water at ordinary temperatures to produce strength-developing insoluble compounds similar to those formed from hydration of Portland cement. Typically, pozzolanic material is categorized as natural or artificial, and can be either processed or unprocessed. The most common sources of natural pozzolanic materials are volcanic materials and diatomaceous earth (DE). Artificial pozzolanic materials are produced by partially calcining natural materials such as clays, shales, and certain siliceous rocks, or are more usually obtained as an industrial byproduct. Pozzolanic oilwell cements are typically used to produce lightweight slurries.

Weighting agents or heavyweight additives are used to increase slurry density for control of highly pressured wells. Weighting agents are normally required at densities greater than 17 lbm/gal where dispersants or silica is no longer effective. This is the most commonly used weighting agent. Hematite is a brick-red, naturally occurring mineral with a dull metallic luster. It contains approximately 70% iron.

Fluid-Loss-Control Additives (FLAs) are used to maintain a consistent fluid volume within a cement slurry to ensure that the slurry performance properties remain within an acceptable range. The variability of each of these parameters (slurry performance properties) is dependent upon the water content of the slurry. If the water content is less than intended, the opposite will normally occur. The magnitude of change is directly related to the amount of fluid lost from the slurry. Because predictability of performance is typically the most important parameter in a cementing operation, considerable attention has been paid to mechanical control of slurry density during the mixing of the slurry to assure reproducibility.

Accelerators speed up or shorten the reaction time required for a cement slurry to become a hardened mass. In the case of oilfield cement slurries, this indicates a reduction in thickening time and/or an increase in the rate of compressive-strength development of the slurry. Acceleration is particularly beneficial in cases where a low-density (e.g., high-water-content) cement slurry is required or where low-temperature formations are encountered. Of the chloride salts, CaCl2 is the most widely used, and in most applications, it is also the most economical. The exception is when water-soluble polymers such as fluid-loss-control agents are used.

Spacers and flushes are effective displacement aids, because they separate incompatible fluids such as cement and drilling fluid. A spacer is a fluid used to separate drilling fluids and cementing slurries. A spacer can be designed for use with either water-based or oil-based drilling fluids, and prepares both pipe and formation for the cementing operation. Spacers are typically densified with insoluble-solid weighting agents. For example, a spacer is a volume of fluid injected ahead of the cement, but behind the drilling fluid.

Remedial cementing is undertaken to correct issues with the primary cement job of a well. Remedial cementing requires as much technical, engineering, and operational experience, as primary cementing but is often done when wellbore conditions are unknown or out of control, and when wasted rig time and escalating costs have the potential to force poor decisions and high risk. Good planning and risk assessment is the key to successful remedial cementing. Squeeze cementing is a "correction" process that is usually only necessary to correct a problem in the wellbore. Most squeeze applications are unnecessary because they result from poor primary-cement-job evaluations or job diagnostics.

Remedial cementing requires as much technical, engineering, and operational experience, as primary cementing but is often done when wellbore conditions are unknown or out of control, and when wasted rig time and escalating costs force poor decisions and high risk. Squeeze cementing is a "correction" process that is usually only necessary to correct a problem in the wellbore. Before using a squeeze application, a series of decisions must be made to determine (1) if a problem exists, (2) the magnitude of the problem, (3) if squeeze cementing will correct it, (4) the risk factors present, and (5) if economics will support it. Most squeeze applications are unnecessary because they result from poor primary-cement-job evaluations or job diagnostics. Squeeze cementing is a dehydration process.

This article discusses several techniques used for hydrocarbon analysis during mud logging. These tools characterize the reservoir fluids that have become entrained in the drilling fluid as it is returned to the surface. The total gas analyzer (TGA), also referred to as the total hydrocarbon analyzer (THA), measures the total amount of gas, typically the total amount of combustible gas. The usual unit of TGA measurement is total methane equivalents (TME), which is essentially the BTU content of the gas extracted from the drilling fluid, expressed as that which would be obtained from an equivalent concentration of pure methane in air. The TGA, while giving an undifferentiated indication of gas entrained in the drilling fluid, has the advantage of operating in a continuous mode.

Introduction The three primary functions of a drilling fluid--the transport of cuttings out of the wellbore, prevention of fluid influx, and the maintenance of wellbore stability--depend on the flow of drilling fluids and the pressures associated with that flow. For example, if the wellbore pressure exceeds the fracture pressure, fluids will be lost to the formation. If the wellbore pressure falls below the pore pressure, fluids will flow into the wellbore, perhaps causing a blowout. It is clear that accurate wellbore pressure prediction is necessary. To properly engineer a drilling fluid system, it is necessary to be able to predict pressures and flows of fluids in the wellbore. The purpose of this chapter is to describe in detail the calculations necessary to predict the flow performance of various drilling fluids for the variety of operations used in drilling and completing a well. Overview Drilling fluids range from relatively incompressible fluids, such as water and brines, to ...