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One role of the petrophysicist is to characterize the fluids encountered in the reservoir. Detection of a change in fluid type in the rocks while drilling is usually straightforward with the use of gas and chromatographic measurements. Gas shows and oil shows while drilling are time-honored indicators of zones that need further investigation through logs, testers, and cores. In the rare case of gas-bearing, high-permeability rock drilled with high overbalance, gas will be flushed from the rock ahead of the bit, will not be circulated to the surface in the mud, and will not produce a gas show. Because hydrocarbons are not always part of a water-based-mud formulation, sophisticated analytical chemical techniques can be used on the oil and gas samples circulated to the surface and captured to determine the properties of hydrocarbons in a given zone penetrated by the drill bit.
Drilling fluids serve to balance formation pressures while drilling to ensure wellbore stability. They also carry cuttings to the surface and cool the bit. These primary considerations do not include well productivity concerns. A growing recognition of the importance of drilling-induced formation damage has led to the use of drill-in fluids (fluids used to drill through the pay zone) that minimize formation damage. This page discusses the formation damage that may be associated with various types of drilling fluids.
High pressure/high temperature (HP/HT) wells are those where the undisturbed bottom hole temp at prospective reservoir depth or total depth is greater than 300 F or 150 C, and either the maximum anticipated pore pressure of any porous formation to be drilled through exceeds a hydrostatic gradient of 0.8 psi/ft, or a well requiring pressure control equipment with a rated working pressure in excess of 10000 psi. Drilling wells with these characteristics pose special challenges. Where possible, high temperature wells are drilled with oil-based fluids (OBFs) or synthetic-based fluids (SBFs), because of the thermal limitations of most water-based fluids (WBFs). Historically, WBFs have relied on bentonite clay for both rheology and filtration control. When tested at temperatures 300 F under laboratory conditions, bentonite slurries begin to thermally flocculate.
Drilling fluid tests are performed to evaluate the properties and characteristics of the fluid, and to determine its performance limitations. The drilling-fluids specialist in the field conducts a number of tests to determine the properties of the drilling-fluid system and evaluate treatment needs. Although drilling-fluid companies might use some tests that are designed for evaluating a proprietary product, the vast majority of field tests are standardized according to American Petroleum Institute Recommended Practices (API RP) 13B-1 and 13B-2, for water-based fluids (WBFs) and oil-based fluids (OBFs), respectively. Table 1 shows typical API-recommended field tests for WBFs. Table 2 shows typical API-recommended field tests for OBFs and synthetic-based fluids (SBFs).
A prime objective in all drilling operations is to minimize safety and environmental risks, while maintaining drilling performance. Operators and service companies alike take a proactive stance to reduce the potential for hazardous incidents, and to minimize the impact of any single incident. The health, safety, and environmental (HSE) policies of many companies are more stringent than those required by national governments and the various agencies charged with overseeing drilling operations. All personnel who take part in the well-construction process must comply with these standards to ensure their own safety and that of others. On most locations, a "zero-tolerance" policy is in effect concerning behaviors that might endanger workers, the environment, or the safe progress of the operation.
Differential-pressure pipe sticking occurs when a portion of the drillstring becomes embedded in a mudcake (an impermeable film of fine solids) that forms on the wall of a permeable formation during drilling. If the mud pressure, pm, which acts on the outside wall of the pipe, is greater than the formation-fluid pressure, pff, which generally is the case (with the exception of underbalanced drilling), then the pipe is said to be differentially stuck (see Figure 1). The pull force, Fp, required to free the stuck pipe is a function of the differential pressure, Δp; the coefficient of friction, f; and the area of contact, Ac, between the pipe and mudcake surfaces. In this formula, Lep is the length of the permeable zone, Dop is the outside diameter of the pipe, Dh is the diameter of the hole, and hmc is the mudcake thickness. The dimensionless coefficient of friction, f, can vary from less than 0.04 for oil-based mud to as much as 0.35 for weighted water-based mud with no added lubricants.
The commonly used cements in well applications are API Class A, C, G, and H. These cements, as produced in accordance with API Spec. To extend the thickening time beyond that obtained with a neat (cement and water without additives or minerals) API-class cement slurry, additives known as retarders are required. Of the chemical compounds that have been identified as retarders, lignosulfonates are the most widely used. A lignosulfonate is a metallic sulfonate salt derived from the lignin recovered from processing wood waste.
Barite or weight material sag is a problem of drilling mud and it occurs when weighting material (barite, calcium carbonate, etc) separate from liquid phase and settle down. The method is based in part on continuously measuring fluid density during the first circulation after the fluid has been static after some time. However it can occur in a dynamic condition with low annular velocity. The barite sag can result in big variations in mud density in well bore. The light density is on top and heavy density at the bottom.