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Publication numberUS20020157871 A1
Publication typeApplication
Application numberUS 10/018,747
PCT numberPCT/GB2001/001791
Publication dateOct 31, 2002
Filing dateApr 23, 2001
Priority dateApr 25, 2000
Also published asWO2001081707A1
Publication number018747, 10018747, PCT/2001/1791, PCT/GB/1/001791, PCT/GB/1/01791, PCT/GB/2001/001791, PCT/GB/2001/01791, PCT/GB1/001791, PCT/GB1/01791, PCT/GB1001791, PCT/GB101791, PCT/GB2001/001791, PCT/GB2001/01791, PCT/GB2001001791, PCT/GB200101791, US 2002/0157871 A1, US 2002/157871 A1, US 20020157871 A1, US 20020157871A1, US 2002157871 A1, US 2002157871A1, US-A1-20020157871, US-A1-2002157871, US2002/0157871A1, US2002/157871A1, US20020157871 A1, US20020157871A1, US2002157871 A1, US2002157871A1
InventorsDavid Tulloch
Original AssigneeTulloch David William
Export CitationBiBTeX, EndNote, RefMan
External Links: USPTO, USPTO Assignment, Espacenet
Apparatus and method of oscillating a drill string
US 20020157871 A1
Abstract
Apparatus and methodology for reducing frictional forces on drilling apparatus when being progressed or retracted within a well bore. This is achieved through mechanical or hydraulic action on the drilling fluid to create a fluid pressure differential which is transmitted on to the drill string via pumps, causing the drill string to oscillate. The oscillation reduces the frictional interface between the drill string and the well bore, thus enabling increased depth or reach of the well bore.
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Claims(17)
1. 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.
2. Apparatus as claimed in claim 1, wherein the modifying means is mechanically operated.
3. Apparatus as claimed in claim 1, wherein the modifying means is hydraulically operated.
4. Apparatus as claimed in any preceding claim, wherein the one or more pumps communicate with at least one fluid containment vessel.
5. Apparatus as claimed in claim 4, wherein said fluid containment vessels are mud pits.
6. Apparatus as claimed in any preceding claim, wherein the one or more pumps are connected to the drill string by flow lines.
7. Apparatus as claimed in any preceding claim, wherein the modifying means provides an oscillating mechanism.
8. Apparatus as claimed in claim 7, wherein the oscillating mechanism is provided by periodical expulsion of a predetermined volume of fluid from the pump.
9. Apparatus as claimed in claim 8, wherein the volume of fluid is expelled from the pump by a choking means.
10. Apparatus as claimed in claim 7, wherein the oscillating mechanism is provided by a turbine.
11. Apparatus as claimed in claim 10, wherein the turbine is accentrically positioned.
12. Apparatus as claimed in claim 7, wherein the oscillating mechanism is provided by an acentric helix.
13. Apparatus as claimed in claim 7, wherein the oscillating mechanism is provided by one or more motors.
14. Apparatus as claimed in claim 13, wherein the one or more motors are connected to a piston.
15. Apparatus as claimed in claim 1, wherein the modifying means is provided on the drill string, or on the pumps.
16. Apparatus as claimed in claim 6, wherein the modifying means is provided on the flow lines.
17. 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.
Description
  • [0001]
    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.
  • [0002]
    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.
  • [0003]
    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.
  • [0004]
    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.
  • [0005]
    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”.
  • [0006]
    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.
  • [0007]
    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.
  • [0008]
    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.
  • [0009]
    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.
  • [0010]
    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.
  • [0011]
    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.
  • [0012]
    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.
  • [0013]
    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.
  • [0014]
    An object of the present invention therefore is to enable drill pipe to move cleanly through geological formations by reducing frictional drag.
  • [0015]
    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.
  • [0016]
    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.
  • [0017]
    Optionally the modifying means is mechanically operated.
  • [0018]
    Alternatively the modifying means to hydraulically operated.
  • [0019]
    Preferably the one or more pumps communicate with at least one fluid containment vessel.
  • [0020]
    Most preferably said fluid containment vessels are mud pits.
  • [0021]
    Preferably the one or more pumps are connected to the drill string by flow lines.
  • [0022]
    Typically the one or more pumps transfer fluid from the fluid containment vessels to the drill string via the flow lines.
  • [0023]
    Preferably the modifying means provides an oscillating mechanism.
  • [0024]
    In one embodiment the oscillating mechanism is provided by periodical expulsion of a predetermined volume of fluid from the pump.
  • [0025]
    Preferably the volume of fluid is expelled from the pump by a choking means.
  • [0026]
    In one embodiment the oscillating mechanism is provided by a turbine.
  • [0027]
    Preferably the turbine is accentrically positioned.
  • [0028]
    In one embodiment the oscillating mechanism is provided by an acentric helix.
  • [0029]
    Typically the helix rotates under the influence of fluid and thereby provides a centrifugal force.
  • [0030]
    In one embodiment the oscillating mechanism is provided by one or more motors.
  • [0031]
    Preferably the one or more motors are connected to a piston.
  • [0032]
    The modifying means can be provided on the drill string, flow line or on the pumps.
  • [0033]
    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.
  • [0034]
    In order to provide a better understanding of the invention, various embodiments will now be described by way of example only, and with reference to the accompanying drawings, in which:
  • [0035]
    [0035]FIG. 1 shows a schematic of a typical drilling package;
  • [0036]
    [0036]FIGS. 2A, 2B and 2C show schematically a description of the drill pipe oscillation theory, in accordance with the present invention;
  • [0037]
    [0037]FIG. 3 provides a schematic of a triplex pump as used on drilling rigs;
  • [0038]
    [0038]FIGS. 4A and 4B show a modification to mud pumps that would induce oscillation in accordance with a method of the present invention;
  • [0039]
    [0039]FIGS. 5A and 5B demonstrate pictorially mechanical methods of inducing oscillation in accordance with the present invention;
  • [0040]
    [0040]FIGS. 6A and 6B illustrate a hydraulic mechanism fitted onto a flow line between mud pipes and the drill string for inducing oscillation.
  • [0041]
    A typical drilling package is represented in FIG. 1, from which the relationship between the various components discussed in this specification may be determined. Specifically, drilling fluid may be mixed and stored in holding tanks, namely the mud pits (2). The fluid is pumped by the mud pumps (3) from the mud pits (2) and pumped along the flow Lines (8). These flow lines (8) join up with the drilling string (5) via the top drive (10). The drilling fluid or mud, as it is more commonly known, has a -multiple function of lubricating and cooling the drill bit which is carried at the end of the drill string (5), carrying away the cuttings and acting as a power source for the motor that drives the drill bit through the well bore (9). The drilling mud is a mixture of various chemicals, which aid in its functions, as well as helping to stabilise the formation that is being drilled through.
  • [0042]
    During drilling, the mud returns up the annular space between the drilled bore a wall and drill string (5). The mud containing the cuttings returns to the mud pits (2) via the surface return lines; the drill cuttings being separated from the mud-on the shakers(1). The cuttings are disposed of via the OB line (6) and the mud is returned to the mud pits and treated by the return lines (7). The process may then be repeated for as long as the drilling phase of the operation continues.
  • [0043]
    Under normal conditions, the mud pumps inject the drilling fluid through the flow lines and drill pipe in a smooth rhythmic pattern as graphically depicted in FIG. 2a. However, in the present invention, it is recognised that by acting on this fluid flow/pressure, it is possible to induce a fluid pulse.
  • [0044]
    The mud pump (3) may operate as a reciprocating pump with multiple cylinders. As the pump operates, pistons draw fluid into the chamber on the up-stroke via intake valves. The drilling fluid is then directed into the flow line (8) to the drill string (5) on the downstroke through outlet valves. Each of the cylinders are operated progressively out of phase with each other, providing a smooth and continuing flow of drilling fluid.
  • [0045]
    Noting that the axis Y relates to pressure and the axis X relates to time, the peaks in the graph shown in FIG. 2a illustrate the action of the pump cylinders as they operate out of phase with each other.
  • [0046]
    In FIG. 2B, it may be seen that by periodically reducing this fluid flow/pressure, a fluid pulse may be induced. This slow pressure cell of drilling fluid is transmitted through the drill string by the action of the mud pumps. Again axis Y relates to pressure and axis X relates to time.
  • [0047]
    In reducing the drilling fluid pressure, e.g., as the pistons operate, a pressure differential is created and this is illustrated in the graph by the drop in the peak value at 11. This pressure differential causes the drill string to oscillate by creating an uneven flow of fluid. The oscillation agitates the formation particles that surround and adhere to the drill pipe assembly, creating the friction boundary, causing lamina movement. This movement reduces surface resistance between the drilling assembly and formation.
  • [0048]
    The oscillating action of the drill string which reduces the surface resistance between the drilling assembly and formation, is analogous to one attempting to progress one's finger into a bucket of fine sand, whereby the progress is improved by moving one's finger. The oscillation of the drill string (5) renders it much easier to overcome surface resistance and to allow more efficient progress of the drill string (5) in the formation.
  • [0049]
    [0049]FIG. 2C shows, simply, how this oscillation affects the drill pipe In the well bore. Under normal conditions while drilling a deviated well, the drill string (12) will sit on the bottom (13) of the well bore (9) being drilled, as shown at (i). As has been described above, the oscillation of the drill string (5) will cause the surrounding particles in the well bore (9) to vibrate. The lamina movement of the particles will create a gap (14) of movement around the drill string and reduce frictional resistance, as shown at (ii).
  • [0050]
    [0050]FIG. 3 shows the basic functioning of a triplex mud pump, as to commonly used in the art. The mud pump is a reciprocating pump with multiple cylinders (15). As the pump operates, the pistons (16) in the cylinder (15) draw fluid into the chamber (17) on the upstroke, via the intake (13). Drilling fluid is then directed in to the flow line to the drill string on the downstroke through the discharge valve (18). Each of the cylinders (15) are operated progressively out of phase with each other, providing a smooth and continuous flow of drilling fluid.
  • [0051]
    In FIG. 4A, it is shown that a modifying mechanism (19) has been located on the mud pump (20) that allows a controlled volume of fluid to be evacuated from the mud pump chamber (17), via a choke manifold (21) and expelled via a through bore during the mud pump's (20) cycle. As described above, under normal conditions the mud pump (20) operates as a reciprocating pump with multiple cylinders (15). As the pump operates, the pistons (16) draw fluid into the chamber (17) on the upstroke via the intake (13) and this is controlled by valve (22). The drilling fluid is then directed-into the flow line to the drill string on the downstroke through the outlet (23), controlled by valve (24). Each of the cylinders are operated progressively out of phase with each other, providing a smooth continuous flow of drilling fluid. The modifying device (19) acts as a periodic bleed, the volume of fluid being controlled by a choking device (21). The expelled fluid is returned to the mud containing vessels. The loss of the small volume of fluid creates a pressure differential or a pulse of fluid. This pulse oscillates the fluid line and drill string by creating an uneven flow.
  • [0052]
    In FIG. 4B, the location of the pump modification (19) and the return line (25) may be determined. The return line (25) carries the excess volume back to the mud pits. The modification may be located at one or all of the mud pumps.
  • [0053]
    Turning now to FIG. 5, in FIG. 5A there is illustrated a mechanical oscillator. The oscillator consists of a body (26) that is designed to be connected to and part of the drill strings by means of connections (27) and (28). The body defines a through bore between the inlet and outlet (29), (30), wherein the through bore is of a diameter appropriate for corresponding with the through bore of the drill pipe in the drill string. Located within the through bore is provided an ascentric turbine, incorporating an impeller (31). In use, the drilling fluid passes through the ascentric turbine (32) via the through bore (29), (30), causing the device and drill pipe and device attached to it to oscillate.
  • [0054]
    An alternative oscillator is shown in FIG. 5B. Specifically, a mechanical oscillator consists of a body (31) that is designed to be connected to and be part of the drill string by means of connections (32), (33). As before, a through bore of appropriate diameter to suit the through bore of the drill pipe in the drill string is provided through the body of the mechanical oscillator. However, in the embodiment illustrated in FIG. 5B, there is no ascentric turbine, rather drilling fluid passes through an ascentric helix (34) which, using the fluid's mass, causing the device in the drill pipe attached to it to oscillate. A section of the mechanical oscillator is shown as (35), from which the ascentricity of the helix may be noted.
  • [0055]
    As the drilling fluid passes through the helix section (39), it rotates causing a vortex. The speed of rotation creates a centrifugal force that starts to separate the fluid components according to their specific gravity. The lighter fluid will move along a higher velocity and will pass through the restrictions (36) and (37) with relative ease. The restriction (36) slows the heavy fluid even more as it passes into the chamber (38).
  • [0056]
    As the chamber (38) fills up with this heavy fluid, a back pressure forms at the inflow side. Due to the movement of the lighter fluids, a lower pressure cells forms at the outflow side (37). When the chamber (38) fills with the heavy weight fluid, the pressure built up on the inflow side will force it through the restriction (37), creating a slug of fluid capping the low pressure cell, creating a pulse. This fluid pulse causes the device and the drill string connected to it to oscillate, as may be seen in FIG. 5B (iii).
  • [0057]
    The through bore of the device at the outflow side (40) is ascentric to the through of the drill string. This enhances the oscillating movement already being induced at the inflow side (41) of the device, by use of the fluid's mass as it passes through this section and back into the drill string.
  • [0058]
    [0058]FIG. 6A shows an alternative hydraulic oscillating mechanism that is made up to and/or included in the flow line that connects the mud pus to the drill string. The hydraulic oscillating mechanism may consist of a fixed or variable speed motor (42) or motors. The or each motor (42) may be connected to a piston (43) by a series of connecting rods (44) and (45) and/or drive wheels (46). The piston cylinders may be attached by any means deemed necessary to the flow line that runs between the mud pumps and the drill string.
  • [0059]
    [0059]FIG. 6B shows the location of the mechanism (13) in relation to the rest of the drilling package. As has already been described above, the mechanism (130 is located on the flow line (8) which runs between the mud pumps (3) and drill string (5).
  • [0060]
    During drilling operations the pistons operate by extraction and injection of a volume of the drilling fluid that is passing along the flow line (8). this causes pulses of high and low pressure drilling fluid to be transmitted down the flow line (8) and drill string (5). This fluid pulse causes the fLow line (8) and drill string (5) to oscillate.
  • [0061]
    The advantage of the present invention lies in the fact that drilling operations can be carried out to depths beyond those which are possible with conventional drilling procedures. It is therefore possible to reach reservoirs which previously could not be drilled to. The degree of frictional drag on the drill string is reduced, allowing deeper drilling to be carried out and facilitating retrieval of the apparatus from a well.
  • [0062]
    Further modifications and improvements may be incorporated without departing from the scope of the invention here intended, and is to be joined simply and inexpensively.
Referenced by
Citing PatentFiling datePublication dateApplicantTitle
US7198102Dec 9, 2005Apr 3, 2007Schlumberger Technology CorporationAutomatic downlink system
US7320370Sep 17, 2003Jan 22, 2008Schlumberger Technology CorporationAutomatic downlink system
US7380616Feb 23, 2007Jun 3, 2008Schlumberger Technology CorporationAutomatic downlink system
US7958952 *Dec 17, 2008Jun 14, 2011Teledrill Inc.Pulse rate of penetration enhancement device and method
US8939234Sep 21, 2010Jan 27, 2015National Oilwell Varco, L.P.Systems and methods for improving drilling efficiency
US9200494Sep 29, 2011Dec 1, 2015Gary James BAKKENVibration tool
US9212522 *May 18, 2011Dec 15, 2015Thru Tubing Solutions, Inc.Vortex controlled variable flow resistance device and related tools and methods
US9316065Aug 11, 2015Apr 19, 2016Thru Tubing Solutions, Inc.Vortex controlled variable flow resistance device and related tools and methods
US20060102340 *Dec 9, 2005May 18, 2006Virally Stephane JAutomatic downlink system
US20090107723 *Dec 17, 2008Apr 30, 2009David John KuskoPulse rate of penetration enhancement device and method
US20120292015 *Nov 22, 2012Thru Tubing Solutions, Inc.Vortex Controlled Variable Flow Resistance Device and Related Tools and Methods
WO2011035280A2 *Sep 21, 2010Mar 24, 2011National Oilwell Varco, L. P.Systems and methods for improving drilling efficiency
WO2011035280A3 *Sep 21, 2010Jul 14, 2011National Oilwell Varco, L. P.Systems and methods for improving drilling efficiency
Classifications
U.S. Classification175/56, 166/381
International ClassificationE21B47/16, E21B28/00, E21B7/24, E21B47/18
Cooperative ClassificationE21B47/185, E21B28/00, E21B47/16, E21B7/24
European ClassificationE21B47/18N, E21B7/24, E21B28/00, E21B47/16