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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.
The drilling-fluid system--commonly known as the "mud system"--is the single component of the well-construction process that remains in contact with the wellbore throughout the entire drilling operation. Drilling-fluid systems are designed and formulated to perform efficiently under expected wellbore conditions. Advances in drilling-fluid technology have made it possible to implement a cost-effective, fit-for-purpose system for each interval in the well-construction process. The active drilling-fluid system comprises a volume of fluid that is pumped with specially designed mud pumps from the surface pits, through the drillstring exiting at the bit, up the annular space in the wellbore, and back to the surface for solids removal and maintenance treatments as needed. The capacity of the surface system usually is determined by the rig size, and rig selection is determined by the well design.
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.
Energy is the rate of doing work. A practical aspect of energy is that it can be transmitted or transformed from one form to another (e.g., from an electrical form to a mechanical form by a motor). A loss of energy always occurs during transformation or transmission. In drilling fluids, energy is called hydraulic energy or commonly hydraulic horsepower. Rig pumps are the source of hydraulic energy carried by drilling fluids.
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.
Drilling operations in water depths of between 5,000 and 10,000 ft take place all over the world, and their success underscores the adaptability of oilfield technology and the industry's capacity to overcome significant technical challenges. The seafloor temperature in deepwater locations is approximately 40 F, but it can approach 32 F. The temperature downhole can exceed 300 F. The drilling fluid should exhibit the appropriate rheological properties throughout this wide range. In the riser near the mudline, the fluid is apt to thicken excessively from exposure to the cold seafloor temperature. Downhole, the fluid might become too thin as it heats up, and problems with hole cleaning and barite sag might develop. SBFs that contain little or no commercial clay appear to remain the most stable under these conditions.