Boring or penetrating the earth – Bit or bit element – Impact or percussion type
Reexamination Certificate
1998-08-10
2001-07-03
Mai, Lanna (Department: 3619)
Boring or penetrating the earth
Bit or bit element
Impact or percussion type
C175S414000, C175S418000, C175S429000
Reexamination Certificate
active
06253864
ABSTRACT:
BACKGROUND
This invention relates to the field of drilling wells for oil, natural gas, water, utilities, or geothermal energy. Specifically, the invention is a new type of drill bit that transmits both rotational torque and axial impacts to the formations to be penetrated. In the most preferred embodiment, this bit may be further enhanced by medium to high-pressure fluid jets; the jets may be steady or pulsed that cause zones of high and low pressure near the cutters on the contact surface of the formation being drilled. A vast majority of drill bits currently on the market for subterranean applications fall into three categories: shear or drag bits, percussive bits, and roller cone or tri-cone bits. Shear bits are typically rounded at the penetrating end with cutters mounted in an orientation nearly normal to the wall of the borehole. Typically, these bits are threaded into the bottom of a drill string, and are rotated against the rock formation from either the top of the hole or down-hole by rotary motors. Such bits have fluid channels extending along the length of the bit body to carry drilling fluid past the cutters and further up the drill string. See U.S. Pat. No. 4,554,986, U.S. Pat. No. 5,284,215, U.S. Pat. No. 4,696,354, U.S. Pat. No. 4,744,427, and U.S. Pat. No. 4,655,303 for examples of this type of bit. Percussive bits are usually flat on the penetrating surface with rounded cutters protruding outwards to concentrate compressive stresses in the rocks upon impact. A unitary body (absence of threaded connections, moving parts, etc) helps transmit an impact stress from the top of the bit (where impacts are imparted) to the bottom contact surface (where it meets the rock) without significant attenuation. Such a bit is usually slidably mounted to the bottom of a drill string, and is keyed to allow rotation of the bit during drilling. The drill string rotates primarily to index the cutters of the percussive bit to a fresh cutting surface between impacts, thereby preventing regrinding of previously crushed material. Roller cone bits normally have three smaller conical bits oriented outwards; each conical bit rotates about its own axis to produce eccentric cutter motion in addition to the overall rotation of the bit. See U.S. Pat. No. 5,624,002 for an example of a roller cone bit.
Drilling induces two types of stress on the rocks. Rotational drilling causes a buildup of shear stresses in the rock; the stresses concentrate to cause a thin layer of rock to shear and break into chips. Percussive drilling, on the other hand, causes compressive stresses where the rounded cutter strikes the rock. Cracks propagate from the point of impact, once again chipping the rock. Roller cone bits induce stresses similar to those of a rotational bit with the addition of a slight percussive element as the cutters rotate on each individual cone. For fairly shallow applications, or in applications where air is used as the drilling fluid, percussive drills have a much faster drilling rate than shear or roller cone bits. Percussive bits also tend to drill straighter than their rotary counterparts. However, in deeper holes, the higher pressure of the drilling fluid will tend to hold the rock chips in place in the absence of significant shear forces; thus, percussive bits lose some of their advantage in deeper holes. In addition, percussive bits lose some of their advantage in softer, less friable formations. Many such formations are typically found interbedded with harder formations while drilling a well. Hence, drilling by percussive means alone may not be optimal for all portions of a well.
The amount of weight allowed to press on the bit is also a factor in determining the penetration rate. Flathead percussive bits are currently operated with only about 5,000 pounds of weight on bit. At higher weight on bit, large shear loads are generated, against which this type of bit is not well adapted. As a result of high shear forces, the rounded cutting elements, or even the head of the bit will typically break. Roller cone bits, on the other hand, are typically used at weights on bit of 20,000 to 50,000 pounds. Drag bits are typically used at somewhat lower weights on bit, on the order of 10,000 to 25,000 pounds. The shape and orientation of the cutters in these bits is conducive to a rotary cutting motion so that the shear stresses do not break the body of the bit or the cutters.
A further difference between the bit classifications mentioned above can be noted by considering the mode of wearing of the cutters. For percussion and roller-cone bits, the cutters ideally do not wear appreciably during operation. If such wear occurs, penetration rate drops dramatically. To enable improved life of these bits, a thin layer of polycrystalline diamond is often applied to the entire exposed surface of the cutters, preventing substantial wear over the life of the bit. Shear bits are likewise enhanced with a thin layer of polycrystalline diamond on the cutter surface. However, the region of the cutter directly behind the polycrystalline diamond layer is typically left unprotected and exposed to abrasion by the rock formation being penetrated. As drilling progresses, the region directly behind the polycrystalline diamond layer wears, exposing a sharp lip of polycrystalline diamond. This feature is known in the industry as “selfsharpening” of the cutters. Hence, percussion and roller-cone bit cutters are designed to operate in a non-wearing mode; shear bit cutters are typically designed to operate in a wearing mode. In spite of the benefits claimed by self-sharpening cutters, it would be advantageous for a shear bit to operate in non-wearing mode, if it were possible to provide a polycrystalline diamond layer robust enough to avoid appreciable wear. Such a bit would drill faster than current art shear bits because it would pose an overall sharper cutter profile to the rock. To induce even faster cutting, a third cutting medium can be utilized in combination with rotation and percussion: medium- or high-pressure fluid jets. Testing indicates that such jets may enhance rotary and percussive drilling rates by acting cooperatively with the mechanical rock-breaking action of such bits. When jets are directed to impinge upon the rock formation near the point of penetration, or just in front of the cutters, they remove the crushed rock underneath the advancing cutters causing more rapid and deeper penetration into the formation.
Another phenomena associated with the high-pressure fluid jets occurs in their identity with underbalanced drilling.
Underbalanced drilling (UBD) is a complex technique that has gained popularity over the past 10 years because of its advantages to reduce formation damage, avoid lost circulation, minimize differential sticking, and increase the penetration rate and bit life. The objective of the technique is to cause a hydrostatic pressure differential between the formation being drilled and the wellbore.
The mechanics of a UBD operation consist of drilling fluids (liquid, gasified liquid or foam) pumped down inside the drillstring, through the downhole drilling motor and bit, and then up the annulus. In the annulus, the drilling fluid may be mixed with drilled cuttings, production gas, formation oil, or water, and gases injected into the annulus. The fluid mixture then flows out of the well through a choke.
In UBD the hydrostatic pressure throughout the drilling operation is maintained at a lower level than that in the formation being drilled. This is achieved through the medium of the drilling fluid with such complex drilling restrictions taken into account as: mud density, densities of lift gases, densities of produced gases, free gas transport, cuttings velocity, injection gas rates, production from the reservoirs, drilling fluids rheology, frictional pressure losses, and localized pressure losses.
Additionally, a UBD operation is dynamic by nature. Factors that cause dynamic effects include: changes in the pumping rate of drilling fluid; changes in gas injection rate; changes in production rat
Gort Elaine
Mai Lanna
LandOfFree
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