Boring or penetrating the earth – Bit or bit element – Rolling cutter bit or rolling cutter bit element
Reexamination Certificate
2001-03-22
2004-07-20
Dang, Hoang (Department: 3672)
Boring or penetrating the earth
Bit or bit element
Rolling cutter bit or rolling cutter bit element
C175S424000
Reexamination Certificate
active
06763902
ABSTRACT:
BACKGROUND OF THE INVENTION
Roller cone bits, variously referred to as rock bits or drill bits, are used in earth drilling applications. Typically, these are used in petroleum or mining operations where the cost of drilling is significantly affected by the rate that the drill bits penetrate the various types of subterranean formations. There is a continual effort to optimize the design of drill bits to more rapidly drill specific formations so as to reduce these drilling costs.
One design element that significantly affects the drilling rate of the rock bit is the hydraulics. As they drill, the rock bits generate rock fragments known as drill cuttings. These rock fragments are carried uphole to the surface by a moving column of drilling fluid that travels to the interior of the drill bit through the center of an attached drill string, is ejected from the face of the drill bit through a series of jet nozzles, and is carried uphole through an annulus formed by the outside of the drill string and the borehole wall.
Bit hydraulics can be used to accomplish many different purposes on the hole bottom. Generally, a drill bit is configured with three cones at its bottom that are equidistantly spaced around the circumference of the bit. These cones are imbedded with inserts (otherwise known as teeth) that penetrate the formation as the drill bit rotates in the hole. Generally, between each pair of cones is a jet bore with an installed erosion resistant nozzle that directs the fluid from the face of the bit to the hole bottom to move the cuttings from the proximity of the bit and up the annulus to the surface. The placement and directionality of the nozzles as well as the nozzle sizing and nozzle extension significantly affect the ability of the fluid to remove cuttings from the bore hole.
The optimal placement, directionality and sizing of the nozzle can change depending on the bit size and formation type that is being drilled. For instance, in soft, sticky formations, drilling rates can be reduced as the formation begins to stick to the cones of the bit. As the inserts attempt to penetrate the formation, they are restrained by the formation stuck to the cones, reducing the amount of material removed by the insert and slowing the rate of penetration (ROP). In this instance, fluid directed toward the cones can help to clean the inserts and cones allowing them to penetrate to their maximum depth, maintaining the rate of penetration for the bit. Furthermore, as the inserts begin to wear down, the bit can drill longer since the cleaned inserts will continue to penetrate the formation even in their reduced state. Alternatively, in a harder, less sticky type of formation, cone cleaning is not a significant deterrent to the penetration rate. In fact, directing fluid toward the cone can reduce the bit life since the harder particles can erode the cone shell causing the loss of inserts. In this type of formation, removal of the cuttings from the proximity of the bit can be a more effective use of the hydraulic energy. This can be accomplished by directing two nozzles with small inclinations toward the center of the bit and blanking the third nozzle such that the fluid impinges on the hole bottom, sweeps across to the blanked side and moves up the hole wall away from the proximity of the bit. This technique is commonly referred to as a cross flow configuration and has shown significant penetration rate increases in the appropriate applications. In other applications, moving the nozzle exit point closer to the hole bottom can significantly affect drilling rates by increasing the impact pressures on the formation. The increased pressure at the impingement point of the jet stream and the hole bottom as well as the increased turbulent energy on the hole bottom can more effectively lift the cuttings so they can be removed from the proximity of the bit.
Unfortunately, modifications to bit hydraulics have generally been difficult to accomplish. Usually, bits are constructed using one to three legs that are machined from a forged component. This forged component, called a leg forging, has a predetermined internal fluid cavity (or internal plenum) that directs the drilling fluid from the center of the bit to the peripheral jet bores. A receptacle for an erosion resistant nozzle is machined into the leg forging, as well as a passageway that is in communication with the internal plenum of the bit. Typically, there is very little flexibility to move the nozzle receptacle location or to change the center line direction of the nozzle receptacle because of the geometrical constraints for the leg forging design. To change the hydraulics of the bit, it would be possible to modify the leg forging design to allow the nozzle receptacle to be machined in different locations depending on the desired flow pattern. However, due to the cost of making new forging dies and the expense of inventorying multiple forgings for a single size bit, it would not be cost effective to frequently change the forging to meet the changing needs of the hydraulic designer. In order to increase the ability of optimizing the hydraulics to specific applications, a more cost effective and positionally/vectorally flexible design methodology is needed to allow specific rock bit sizes and types to be optimize for local area applications.
Previous methods to improve borehole hydraulics include some means to move the nozzle exit closer to the hole bottom to increase the bottom hole energy. U.S. Pat. No. 3,363,706 teaches the use of an extended tube that extends between the cones and moves the nozzle exit point within 1″-2″ from the hole bottom. The extended nozzle tube is made of steel and welded to the bit and contains a receptacle for the installation of erosion resistant nozzles.
Another configuration following the same approach uses mini-extended nozzles. Mini-extended nozzles are made from erosion resistant materials such as tungsten carbide and are longer in length than the standard nozzle and thus protrude beyond the nozzle receptacle. While the mini-extended nozzles do not move the nozzle exit as close to the hole bottom as the extended nozzle tube, the additional 1.3″-2.5″ of extension significantly increases the bottom hole impact pressures. For instance, a standard nozzle and a mini-extended nozzle were tested in a chamber to measure the impact pressures for a given flow rate while installed in a 7⅞″ bit. Using 3{fraction (11/32)}″ nozzles, the standard nozzle impingement pressure was measured at 175 PSI. The mini-extended nozzle with 1.5″ additional extension to the hole bottom, had an impingement pressure of 360 PSI. Drilling tests in a down hole simulator have shown increases of up to 30% in drilling rates when using mini-extended nozzles in the place of standard nozzles.
The prior art also has several other examples of attachable bodies used to improve the bit hydraulics. U.S. Pat. Nos. 4,516,642; 4,546,837; 5,029,656; and 5,096,005 all teach the use of directed nozzles that incline the jets towards the cones to focus the energy on the inserts for the purpose of ensuring they are clean and will penetrate into the formation. Bits of this type have been shown to have an advantage in sticky formations and in applications where the energy expended across the bit is very low. The drawback of this type of configuration is that the impact pressures on the hole bottom are significantly reduced since the fluid strikes the formation at an inclined angle and because the distance the fluid must travel before it hits the hole bottom is increased. For example,
FIG. 11
is a graph showing a modeled set of relationships between impact pressure and flow rate for various configurations. In particular, in order of increasing slope,
FIG. 11
shows calculated impact pressure/flow rate relationships for 1) an angled fluid discharge column; 2) a vertical fluid discharge column with no cross flow; 3) a vertical discharge column with cross flow; and 4) a vertical fluid discharge column with extended nozzles
Larsen James L.
Terracina Dwayne P.
Conley & Rose, P.C.
Dang Hoang
Smith International Inc.
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