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In situations in which predrill analysis reveals high risk but has a large uncertainty, it is possible to mitigate that risk by carrying out geomechanical analysis in real time. Performing real time assessment requires acquisition of a variety of data while drilling. The measurement can also be used to show where transient pressure events such as surging and breaking the gel strength of the mud exceed fracture pressure, or where swabbing reduces the pressure below the pore or collapse pressure of the wellbore. Direct pore-pressure measurements while drilling can provide critical data to calibrate pore-pressure predictions in permeable formations. Extended leakoff tests are strongly recommended.
The first fracture treatments were pumped just to see if a fracture could be created and if sand could be pumped into the fracture. In 1955, Howard and Fast published the first mathematical model that an engineer could use to design a fracture treatment. The Howard and Fast model assumed the fracture width was constant everywhere, allowing the engineer to compute fracture area on the basis of fracture fluid leakoff characteristics of the formation and the fracturing fluid. Modeling of fracture propagation has improved significantly with computing technology and a greater understanding of subsurface data. The Howard and Fast model was a 2D model.
Since the most common use of matrix acidizing is the removal of formation damage, it is important to understand the nature of the damage that exists so that an appropriate treatment can be designed. Well testing and well test analysis generate a skin factor and well completion efficiency. This is insufficient alone for formation damage diagnosis. Well performance analysis has provided a beneficial tool to identify the location and thickness of damage at flow points in the near wellbore area. Models of flow into perforations and gravel-packed tunnels provide a way to relate the location and severity of damage to the completion procedure that preceded it.
When completion or workover operations are conducted on a well (perforating, gravel packing, etc.), the fluid present in the wellbore must minimize the impact on the near-wellbore permeability. Several decades ago, engineers realized that the use of drilling fluids during completions was inappropriate because fluids caused severe damage to the productive zone. A wide variety of fluids are now available as completion or workover fluids. This page focuses on formation damage issues related to these different types of completion and workover fluids. A list of fluids used for completion or workover is provided in Table 1.
The complete paper describes the test procedures adopted for evaluating various filter cake breaker formulations and the work conducted to develop the systems to be ready for use in two North Sea fields (Field A and Field B). Water injection wells were planned to provide pressure support to oil producers in the two fields, and water-based drilling fluids were selected to drill the reservoir sections for both. The average permeability is 1000 md for Field A and 50–100 md for Field B. A laboratory study was commissioned to evaluate and optimize filter cake breaker systems for use in water injectors to efficiently remove external and internal filter cake to attain matrix injection without the need for backflow to clean the sandface. Field A was commissioned to drill 18 producers and seven water injectors from a semisubmersible drilling rig. Most of the injector wells are high-inclination, long openhole sections.
Formation damage has received significant attention over many decades, but what about completion damage? Before we discuss this question, we first need to define these terms. Formation damage could be considered as damage to the near-wellbore (e.g., mud solids invasion, plugging). In contrast, completion damage is damage to the lower completion (e.g., plugging of screens). The combined effect of formation and completion damage is the observed well productivity development with associated skin and productivity index.
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.