Earth boring – well treating – and oil field chemistry – Well treating – Contains inorganic component other than water or clay
Reexamination Certificate
2000-06-06
2003-12-16
Tucker, Philip (Department: 1712)
Earth boring, well treating, and oil field chemistry
Well treating
Contains inorganic component other than water or clay
C166S293000, C106S685000, C507S904000
Reexamination Certificate
active
06664215
ABSTRACT:
FIELD OF THE INVENTION
This invention is related generally to compositions and methods for use in drilling operations and, more specifically, to compositions for use in sealing wellbores and methods of using such compositions.
BACKGROUND OF THE INVENTION
People and businesses in the oil and gas industry and, potentially, any industry involved in drilling into earthen formations, confront a number of important problems with respect to extraction of hydrocarbon fluids, gases, and other materials from underground reservoirs. These problems include, among others, the need to prevent the escape and loss of underground fluids and gases which are driven under pressure from the earthen formations and into the wellbore, the need to avoid contamination of, and damage to, the earthen formations and subterranean fluids and gases surrounding the wellbore, the need to seal wellbores in a manner which is noninvasive to the surrounding earthen formations upon completion of the drilling operation and the need to control the drilling apparatus so as to properly position the wellbore.
Control of the movement of underground fluids and gases into the wellbore during a drilling operation represents a particularly significant problem, both with respect to economic and safety-related issues. Underground fluids and gases are typically under extreme pressure, referred to as “formation pressure.” This formation pressure causes surrounding fluids and gases to be driven from the underground production formations and reservoirs and into the wellbore positioned in the earthen formations surrounding the formations and reservoirs. If uncontrolled, these formation pressures cause oil, gas, water, brine and other subterranean materials to be forced into the wellbore and out onto surrounding ground surfaces or into the atmosphere.
As can be readily understood, the loss of these materials and the potential damage and contamination which can be caused by the uncontrolled flow of these materials is economically undesirable. Moreover, uncontrolled loss of flammable hydrocarbon materials from the pressurized production zone, can result in a condition known as a “wellbore blowout.” A wellbore blowout is highly undesirable because of the potential fire and explosion hazard created by the uncontrolled flow of flammable fluids and gases from the wellbore.
It is common industry practice to use drilling fluids and cement systems to attempt to control the potential loss of underground fluids and gases from the wellbore. These drilling fluids and cement systems are pumped directly into the wellbore where, it is anticipated, they will be deposited against the wellbore walls, thereby sealing those walls and limiting unwanted fluid and gas outflow. For example, prior art drilling fluids use a mechanism, known as filtration, to “screen out” or deposit wellbore cuttings and additives present in the drilling fluid against the wellbore walls. This layer, also called a “filter cake,” is deposited along the wellbore walls as the drilling fluid is forced by hydrostatic fluid column pressure, into the permeable earthen formations surrounding the wellbore. The additives may include polymers and viscosity modifiers which enable the fluid to support, or carry, the wellbore cuttings and other particulates prior to their screen out or deposition onto the wellbore face. A wide range of additives, including organic additives such as coconut husks and carbohydrate materials, have been used in combination with drilling fluids to seal the wellbores.
However, these drilling fluid systems are not complete solutions to the problem of unwanted fluid and gas loss from the wellbore. These drilling fluid systems are disadvantageous because they limit, but do not fully prevent, hydrocarbon loss. Drilling fluids are ineffective in forming a complete seal along the wellbore walls because the filter cake is permeable and is subject to dynamic erosion by the continuous circulation of the drilling fluid. Dynamic erosion is a continuous process of deposition and erosion which occurs during the drilling operation. In highly permeable earthen formations, this erosion can remove any filter cake and erode the surrounding earthen formation resulting in very poor seal formation during casing operations due to “wash-out,” or enlargement, of the wellbore.
Various cements, including Portland-type cements and cements including magnesium oxysulphate materials such as MAGNAPLUS brand cements available from B. J. Hughes, have also been used for sealing wellbore walls and for limiting the unwanted loss of fluids and gases from the earthen formations. These cement systems can be used in combination with the drilling fluid systems previously described. Such cements have been used for, among other things, grouting well casings, plugging abandoned wells and, occasionally, for sealing off permeable structures from adjacent fluids. As with the drilling fluids, the cement is typically pumped directly into the wellbore and into contact with the wellbore walls.
However, these cement systems have important disadvantages with respect to their use in wellbore operations. These limitations are due to the inherent physical properties of such materials and, importantly, their slow phase transition from a flowable to a solid state. Specifically, Portland-type cements and magnesium oxysulphate cements are thixotropic cements which form a gel structure during the transition between their slurry (i.e., flowable) and solid states. During this transition, and as the gel is formed, the cement slurry acquires a slight supportive strength. The increase in supportive strength reduces the hydrostatic pressure exerted by the cement fluid column on the geologically-exposed formations in the wellbore. The hydrostatic pressure created by the cement fluid column in the open wellbore is important because it is the only control factor to contain formation pressures. In the case of a pressurized zone, such as the production zone, the reduction in hydrostatic pressure of the cement fluid column can allow an influx of gases or fluids into the wellbore further reducing hydrostatic pressure. The cumulative loss in hydrostatic pressure can allow a sufficient influx of gases or fluids into the wellbore to cause an undesirable wellbore blow-out.
Another adverse consequence of the hydrostatic pressure reduction is referred to as “channeling.” Channeling occurs when fluids or gases transit through the gelled cement and form channels. These channels become part of the cement structure when the cement has set. The channels are highly disadvantageous because they allow leakage of gases and fluids through the channels even after the wellbore casing has been set and cemented. Such channeling often requires the use of expensive remedial clean up, fracturing or squeezing operations.
Not only are these prior art drilling fluid and cement systems incomplete solutions to the problem of preventing unwanted fluid and gas loss but they may also contribute to contamination and damage of earthen formations surrounding the wellbore and the fluid and gas reservoirs themselves. Contamination caused by drilling fluids and cements is referred to in industry as “invasiveness.” This type of contamination can occur because the use of drilling fluids is a dynamic process which can cause continuous fluid invasion of the permeable earthen formations surrounding the wellbore as the fluids are circulated within the wellbore. Once in the formations, the drilling fluid can then invasively interact with that formation to cause swelling, or dispersion, of reactive shales, or washout of unconsolidated sands, all of which can lead to wellbore instability and contamination of the surrounding hydrocarbon reservoirs.
Cement systems can also cause invasive contamination of the surrounding earthen formations, particularly as the cements are forced back into the formations by the hydrostatic pressure of the wellbore fluid column. Such contamination typically occurs during the time that the cement is in the gel, or flowable, phase. The cement filtrate, i
Jansson & Shupe & Munger Ltd.
Tucker Philip
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