This invention relates to drilling methods for drilling well bores such as may be used for oil or gas production. The invention finds a particular application in providing apparatus and methodology for reducing frictional forces on drilling apparatus, as it progresses and retracts a within the well bore.
There are various limitations upon the depth of well bores using known drilling practices. For example, the geological structure may limit the depth of a well, as where the formation is unconsolidated or otherwise physically unstable, the well may not be able to support the various forces and loads imposed upon it by the drilling equipment. Additionally, location of the production reservoir relative to the drilling rig influences the depth and reach of any new well. Yet further, rheology, i.e., the relevant fluid pressures and types of fluid in the vicinity of the well also bear upon the ability and desirability of the well depth.
However, regardless of these external or environmental conditions, there is nevertheless physical limitations to maximum reach or depth of a well which are imposed simply because of the equipment or apparatus used. Specifically, the load capacities of known drilling operation components and equipment are inevitably limited.
In one object of the present invention, it is desired to provide apparatus and methodology for enabling increased depth or reach of a well bore. This is achieved by providing apparatus and methodology for reducing frictional interface between a drill string and the surrounding geological formation.
Typically, a drill string assembly consists of a bottom hole assembly and the drill string pipe. The bottom hole assembly comprises a drill bit incorporating a cutting structure, a motor for driving the drill bit and further telemetry equipment. The drill string pipe is usually made up of individual lengths of pipe (typically 30 ft in length), called “singles”. For handling purposes during the drilling operation, three singles are conventionally joined together to form a “stand”.
Co-ordinating with the drill string is a drilling assembly. A drilling assembly is made up to the blocks or top drive which is suspended from the drilling derrick on a drilling rig. The top drive is controlled via the draw works by the driller and enable the drill string assembly to be moved up and down, as well as acting as the point where the drill string is made up to the flow lines. Such flow lines come from mud pumps and return lines that typically run to the mud containment vessels, i.e., mud pits.
During drilling operations, the well bore is drilled by a combination of the rotation of the drill bit and a directional or longitudinal force. This directional force results from the weight on top of the drill bit imparted by the drill string. It will be appreciated that the deeper the hole, the greater the weight that is available of drill string suspended from the blocks. This weight is utilised efficiently in situations where the well bore is vertical, as the drill string is suspended free of the well bore wall and bears directly upon the drill bit. However, in situations where the well that is being drilled is deviated from the vertical, the force imparted by the drill string is significantly reduced, since the drill string is not suspended freely in the middle of the well bore, but lays on the wall of the drilled well bore. This is particularly so where a deviated well is horizontal or near horizontal. The longer the horizontal or deviated well that is to be drilled, the greater the surface area of drill string that is in contact with the well bore wall. This in turn increases the frictional drag imposed by the wall on the drill string. Depending upon the type of formation through which the drill string is roving, this frictional drag may be further exacerbated.
Turning now to the requirement of retrieving the drill string from the well bore, such frictional drag continues to be a consideration. Yet further, the frictional drag must be added to the weight of the string being retrieved, and this is one of the limiting factors in the maximum depth achievable, since the load capacity of the draw works must be taken into consideration, as well as the strength of the joints or connections upon each of the singles of drill pipe. If any of the load capacities of these or other areas are exceeded, then failure of such components will occur with catastrophic consequences.
It is therefore desirable in the art to provide apparatus or methods of reducing the frictional drag of drill pipe on the walls of the well bore. In the past, such apparatus and methods have been developed to some extent and these have been offered as both chemical and mechanical solutions. Chemical mixes are employed to stabilise well bore walls and reduce the frictional drag. These chemical mixes are typically added to the drilling fluid, and in some operations silica beads may further be added to enhance the friction reducing properties of the chemicals used.
However, chemical mixes tend to provide only a limited use solution, as they degrade over a period of time. The chemicals are of course diluted by the other well fluids and absorbed by the well formation. They also may be chemically degraded by their inter-action or reaction with well fluids and the geology downhill.
Mechanical friction reducing devices are most conventionally provided as “centralisers”, which are well known in the art. The function of a centraliser is to physically keep the drill pipe away from well bore wall. However, centralisers also are not entirely satisfactory, as while they may help to mitigate frictional drag, they can similarly induce other disadvantages. For example, with the weight of the drill string bearing upon the centraliser, the centraliser only provides a localised surface area, and in consequence at times tend to dig into the well bore as the drill string moves. Attempts have been made to mitigate this problem by reducing more expensive and sophisticated centralisers, with a friction reducing surface. While such additional friction reducing coatings or surfaces (including those which incorporate rollers) are effective to some extent in a well bore, which as walls that are stable, this does not solve the herein before mentioned problem where the bore wall is unstable or unconsolidated. In such situations, the centralisers will tend to dig in to the well bore and any advantage imparted by the friction reducing surface is compromised.
Three rotating collars are also used to reduce rotational resistance caused by the drilling string bearing against the bore wall. However, while such collars may be effective in reducing rotational resistance, they do not reduce vecta or directional resistance, and therefore encounter the same problems or disadvantages as that which are associated with centralisers. Similarly, the aforesaid silica beads, while reducing surface friction in all directions, nevertheless suffer the problem of being able to be used only once, as a percentage are lost to the well formation and at present no cost effective means of extracting or separating the beads is available. Thus, the beads cannot be efficiently returned to surface in the drill fluid, at least in a manner which separates then from the cuttings. Typically therefore, any retrieved silica beads are disposed of in conjunction with the well cuttings.
It will be appreciated that the movement of the drill string in the situation of non-vertical drilling, particularly through unstable formations, can act to destabilise the well bore wall by its physical contact with the wall. By this, the bore wall in certain circumstances may collapse around the drill string. This causes the drill string to become fixed in place or, as is commonly known in the trade, “stuck in hole”. Drilling can therefore not progress, nor can the drill string be retrieved. In this catastrophic situation, the string may either be physically pulled out, circulated out by increasing the circulation of drilling fluids, retrieved by a combination of physically pulling out and increasing drilling fluid circulation or, alternatively, jarred out. If none of these techniques succeed, it is necessary to abandon the drill string in the well. In all cases, the costs are extremely high in terns of rig time and in the case of abandonment, equipment cost.
An object of the present invention therefore is to enable drill pipe to move cleanly through geological formations by reducing frictional drag.
A further object of the present invention is to allow for drilling operations with significantly reduced occurrence of the drilling string getting “stuck in hole”, and increasing achievable drill depths beyond current limits, in the region of 20,000 ft to 30,000 ft. Accordingly, by meeting these objects, there is provided a reduction in the costs associated with drilling operations and a increased ability to reach reservoirs are that are not able to be reached due to current constraints, as described herein before.
According to a first aspect of the present invention, there is provided apparatus for oscillating a drill string within a well bore, comprising one or more pumps for introducing fluid into a drill string and a modifying means, wherein the modifying means induces a fluid pressure differential which is transmitted to the drill string via the pumps, and wherein the fluid pressure differential causes said drill string to oscillate.
Optionally the modifying means is mechanically operated.
Alternatively the modifying means to hydraulically operated.
Preferably the one or more pumps communicate with at least one fluid containment vessel.
Most preferably said fluid containment vessels are mud pits.
Preferably the one or more pumps are connected to the drill string by flow lines.
Typically the one or more pumps transfer fluid from the fluid containment vessels to the drill string via the flow lines.
Preferably the modifying means provides an oscillating mechanism.
In one embodiment the oscillating mechanism is provided by periodical expulsion of a predetermined volume of fluid from the pump.
Preferably the volume of fluid is expelled from the pump by a choking means.
In one embodiment the oscillating mechanism is provided by a turbine.
Preferably the turbine is accentrically positioned.
In one embodiment the oscillating mechanism is provided by an acentric helix.
Typically the helix rotates under the influence of fluid and thereby provides a centrifugal force.
In one embodiment the oscillating mechanism is provided by one or more motors.
Preferably the one or more motors are connected to a piston.
The modifying means can be provided on the drill string, flow line or on the pumps.
According to a second aspect of the present invention, there is provided a method for running a drill string into a well bore comprising creating a fluid pressure differential by mechanical or hydraulic means, and transmitting the fluid pressure differential to the drill string, the fluid pressure differential thereby causing the drill string to oscillate.