Patent Application
20250020026
The present invention is directed to a downhole tool for a drill string for drilling oil, gas and water wells, namely a one-piece multi-functional wellbore conditioning system where said system combines reaming while drilling, wellbore conditioning, providing a plastering effect, improved stabilization and cleaning cuttings from a drilled hole.
As technology has advanced in the directional drilling industry, it has facilitated the drilling of deeper, and more complex well trajectories, faster than ever before.
Wellbore quality issues, whether related to either geometry, hole cleaning or formations could lead to the wellbore drift diameter being smaller, leading to increased friction, tight spots, higher upper rotary torque, leading to reduced actual weight and torque on bit, elevated levels of drilling vibrations and even unnecessary and premature bottom hole assembly (BHA) component wear.
In general, enlarging a borehole may be done as a separate operation to enlarge an existing borehole or be done in the same operation as drilling the borehole. The initial or pilot hole is drilled with the drill bit; a reamer can be positioned a distance above the bit to enlarge and/or condition the borehole. If a reamer has a fixed outer diameter, the cutting elements action starts at the wellbore surface and ends with a diameter equal to or greater in diameter than the drill bit. Alternatively, a reamer constructed with expandable cutters could be used. If the borehole requires slight enlargement and/or straightening due to the formation of doglegs, a reamer can be constructed to be eccentric; a reamer with this feature set is used to enlarge and or straighten the borehole by a fraction of an inch.
With increasing measured depths and horizontal displacements in extended-reach wells, cuttings transportation and good hole cleaning remains a major challenge. Hole cleaning is the ability of the drilling fluid, also referred as mud, to transport the cuttings produced during drilling operations up to the surface and suspend the cuttings. It has been recognized for many years that removal of the cuttings from the wellbore during drilling of horizontal wells poses special problems.
As the cuttings produced during drilling process are being transported to the surface, it has been found that some of the cuttings fall out of the drilling mud in inclined to horizontal wellbore sections, then they settle on the low side of the wellbore due to gravity and an accumulation of solids is formed along the lower side of the borehole. This and the fact that the drill string also lies on the wellbore's low side reduces the efficiency of the drilling process. Failure to achieve sufficient hole cleaning can cause severe drilling problems including excessive energy and time required when tripping out of the hole, high rotary torque, stuck pipe, hole pack-off, excessive equivalent circulating density, formation break down, slow rates of penetration and difficulty running casing and logs. These cuttings bed accumulations can result in the drill string getting stuck inside the hole, which in turn results in a major drilling cost. Although prevention of stuck string is far more economical, the drilling professional often opts for freeing procedures such as “washing and reaming,” wherein the drilling fluid is circulated and the drill string is rotated as the bit is introduced into the wellbore, and “back reaming,” wherein the drilling fluid is circulated, and the drill string is rotated as the bit is withdrawn from the wellbore. Other operations such as “wiper trips” or “pumping out of the hole” are often performed to attempt to control the amount of cuttings accumulated in the wellbore. All these operations require time and can significantly add to the cost of drilling a directional well. Therefore, there is a need to overcome those problems.
The object of the present invention in accordance with claim 1 is achieved by a one-piece construction multi-functional wellbore conditioning system having a tubular body extending along a longitudinal axis X, said system comprising a trailing eccentric reamer stage, a leading eccentric reamer stage, and
The multi-functional wellbore conditioning system of the present invention is designed to improve the drilling efficiency by removing sections of parallel misalignment, key seats, micro doglegs, and sours up cutting beds that can lead to swabbing and pack-off issues. This is achieved by optimizing the placement of the eccentric reamer stages along the length of the tubular body which eccentric reamer stages have a low-torque helical hybrid cutting structure, combined with a flow accelerator and drilling cuttings agitator.
Said multifunctional wellbore conditioning system marginally increases the wellbore drift diameter through unique customizable eccentric reamer stages, a drilling fluid accelerator, a cutting bed agitator and a stabilizer, all combined within a single-piece design.
Said multi-functional wellbore conditioning system combines hole enlargement while drilling, also known as reaming while drilling, and hole cleaning in vertical, deviated, horizontal and extended reach wells.
Further improvements include smoothing the wellbore by removing dog legs, reducing drag values, improved tripping performance, improved hole cleaning and enhancing casing and cement installation processes.
Advantageously, the multi-functional wellbore conditioning system is of a one-piece construction, that is milled, molded, or machined from a single piece of material, having a tubular body with radius “r” and length I, defining a long axis “X” extending in a longitudinal direction.
Advantageously, the wellbore conditioning system has an eccentric reamer design, where the leading eccentric reamer stage and the trailing eccentric reamer stage are radially offset from the longitudinal axis “X” of the tubular body.
Advantageously, the leading and trailing eccentric reamer stages each have a set of cutting blades having a cutting structure i.e., polycrystalline diamond compact (PDC) cutter inserts and/or tungsten carbide inserts (TCIs) adapted to do most of the borehole enlarging and/or conditioning, and a set of drift blades adapted to dynamically stabilize the wellbore conditioning system during rotational reaming by minimizing the vibrations and provide a plastering effect on the wellbore.
Advantageously, the wellbore conditioning system has a drill cuttings agitator being positioned between the two eccentric reamer stages, where said drill cuttings agitator comprises a plurality of stabilizing blades and hydrodynamic flutes. The stabilizing blades are adapted to increase the velocity of the drilling fluid where the special geometry of said stabilizing blades creates pressure and turbulence at the low side of a horizontal well which pressure and turbulence is directed at the segmented concentration of cuttings, and as the wellbore conditioning system rotates this creates a scouring effect in the cutting beds. Said stabilizing blades also stabilize the wellbore conditioning system in the borehole. As the multi-functional wellbore conditioning system translates in a counter rotation downhole, the stabilizing blades agitate the cutting beds on the lower side of the wellbore pushing the cuttings up into the circulating drilling fluid where they are transported downstream. The agitation of the cutting beds leads to cleaner and more uniform flow conditions. The additional bearing pressure created against the wall of the wellbore and the increase in annular velocity combined with the stabilizing blades geometry leads to a smoother filter cake whilst minimizing the risk of pack off during drilling operation.
In general, in drilling applications, based on the blade shape, the blades can be helical blades or straight blades. All blades i.e., cutting, drift and stabilizing blades in the present invention are straight and parallel to the longitudinal axis X of the tubular body. The surface area of the straight blades is smaller than a helical one and therefore, straight blades have the advantage of lower friction resistance, diminishing the possibility of the drill string being stuck, and also improving the cuttings transport, backflow, and bit balling.
All these features of the present invention work in synergy to achieve all of the above-mentioned technical effects.
As embodied and broadly described, the disclosures herein provide detailed embodiments of the invention. However, the disclosed embodiments are merely exemplary of the invention that may be embodied in various and alternative forms. Therefore, there is no intent that specific structural and functional details should be limiting, but rather the intention is that they provide a basis for the claims and as a representative basis for teaching one skilled in the art to variously employ the present invention.
A one-piece multi-functional wellbore conditioning system 1 according to the invention is shown in
Between any two consecutive sections in the longitudinal direction of the tubular body there is a frustoconical element 13 with an inclination of 15-20 degrees with respect to the longitudinal axis X. The frustoconical element narrows from section I towards section II, and from section V towards section IV, and from section III towards section II and IV respectively. This provides more efficient passage of the fluid over the blade lengths.
The multi-functional wellbore conditioning system 1, also referred to herein as “tool”, comprises a first leading eccentric reamer stage, also referred to as “leading eccentric reamer stage” or “first eccentric reamer stage”, and a second trailing eccentric reamer stage, also referred to as “trailing eccentric reamer stage” or “second eccentric reamer stage”, and a drill cuttings agitator positioned between said first and second eccentric reamer stages, where said agitator comprises a plurality of stabilizing blades which have a curved surface along the longitudinal axis X of the multi-functional wellbore conditioning system. Said stabilizing blades increase the velocity of the drill cuttings from leading to trailing cutting blade set.
The wellbore conditioning system is manufactured from a single piece of steel, such as chromium-molybdenum high tensile steel, where said steel has mechanical characteristics which may correspond with other drill string components which connect onto said system. The leading and trailing eccentric reamer stages and the agitator are milled, molded, or machined from a single piece of material as an integral component of the tubular body of the wellbore conditioning system, forming a unitary piece, also referred to as one-piece construction.
Each eccentric reamer stage comprises a set of cutting blades and a set of drift blades. The cutting and the drift blades extend radially outwardly from the outer surface of the tubular body. Although the tool geometry of the present invention is designed for reaming, there is also the possibility of using this tool geometry as a stabilizer.
The trailing eccentric reamer stage 3A is positioned between the trailing section 2A and the drill cuttings agitator 4 along the longitudinal axis X of the tubular body as shown in
The first cutting blade of the trailing and leading eccentric reamer stages extends radially outwardly from the outer surface of the tubular body and defines with its outermost surface an ideal cylinder having a diameter d4. The second cutting blade of the trailing and leading eccentric reamer stages extends radially outwardly from the outer surface of the tubular body and defines with its outermost surface an ideal cylinder having a diameter d5, where d5 is smaller than d4 (d5<d4). The drift blades 6A, 6B extend radially outwardly from the outer surface of the tubular body and define with their outermost surface an ideal cylinder having a diameter d3, referred to as drift diameter, or plastering diameter, where d3 is smaller than d5 (d3<d5).
The cutting and the drift blades of the trailing and leading eccentric reamer stages are designed to perform one of the following actions: i) cutting of the wellbore; ii) conditioning of the wellbore, i.e. improving of the geometric condition of the wellbore by removing any imperfections or rough areas of the borehole; iii) providing a plastering effect which is generated in the form of the drilled solids and bridging materials plastered against the borehole and packed into the filter cake, providing this way a better filter cake quality and improving the borehole strength.
Each cutting blade 5A, 5B of the trailing and leading eccentric reamer stages is straight and parallel to the longitudinal axis X of the tubular body. Each cutting blade 5A, 5B has on its surface deep helical grooves, said helical grooves running up the cutting blade defining in such a way a plurality of crowns 31 (see
The plurality of cutting elements, also referred to herein as “cutting structure”, i.e., polycrystalline diamond compact (PDC) cutter inserts and/or tungsten carbide inserts (TCI), are disposed on each of the cutting blades and are arranged in straight longitudinal rows. Each cutting element (PDC or TCI) has a predetermined height (h) measured from the outer surface of the cutting blade. The PDC cutting inserts are referred to as active cutting elements, in the sense that they actively cut and do not simply rub the wall of the borehole, whereas the TCI inserts are referred to as passive cutting elements. The set of cutting blades of the leading eccentric reamer stage does most of the borehole enlarging also referred to as reaming, the set of the cutting blades of the trailing eccentric reamer stage does conditioning of the borehole and the set of drift blades are stabilizing blades positioned circumferentially at 180° from the first cutting blades at the drift side of the tubular body, and act to dynamically stabilize the tool during rotational reaming, and in this way minimizing the vibrations of the tool and also provide plastering effect.
The cutting elements inserted in the first cutting blade of the trailing and leading eccentric reamer stages define with their outermost surface an ideal cylinder having a diameter d1, where d1 is greater than d4 (d1>d4). The cutting elements inserted in the second cutting blade of the trailing and leading eccentric reamer stages define with their outermost surface an ideal cylinder having a diameter d2, where d2 is smaller than d1 (d2<d1), d2 is greater than d3 (d2>d3), and d2 is greater than d5 (d2>d5).
The first cutting blade in the rotational direction of the leading eccentric reamer stage 3B has on top of its surface a combination of PDC and TCI inserts, and does the initial cutting action of the borehole, shown in
Finally, the drift blades of the leading eccentric reamer stage 3B (
The cutting blades of the trailing eccentric reamer stage 3A have only TCI inserts on top of their surface, and therefore the first and the second cutting blades of the trailing eccentric reamer stage 3A perform only conditioning of the borehole.
The aggressiveness of the PDC elements can be adjusted by altering two-dimensional parameters prior to tool manufacture, namely by altering the back rake angle and the maximum gauge radius from the tool's longitudinal cutting diameter axis. The following limits shall be applied when finalizing the back rake angle for the PDC elements: soft formation: 18-21°; medium-hard formation: 15-18°; and hard formation: 13-15°, and a side rake angle of 0°.
The PDC cutter type and geometry can be adjusted to ensure that the reamer can be optimally dressed for the formation being drilled and for the specific drilling application.
Between the cutting blades of the leading and trailing eccentric reamer stages there are flow-by pass channels defined by the outer surface of the tubular body and the longitudinal walls of two consecutive blades. The bottoms of the helical grooves stand proud of the surface of the flow-by pass channels between the cutting blades.
The deep helical grooves between the crowns of the cutting blades are designed to allow the removed cuttings to be pushed out into the oncoming mudflow between the blades of the tool. The helical grooves also increase the flexibility of the blade while cutting. The cutting structure cuts into the doglegs, and cuttings are pulled up the groove by the rotation of the tool and into the longitudinal flow by-pass channel also referred herein as “flow-by channel” formed between the blades (see
When the tool is in operational mode (i.e., in use), two degrees of freedom provide the cutting motion: axial movement down the wellbore, and rotational movement. Using this and the optimized positioning of the PDC/TCI cutters on the blades, the positioning of the helical groove between the crowns produces a better finish by redirecting and/or redistributing the cutting forces and stresses, not necessarily reducing them.
The cutting blades sets of the leading and trailing eccentric reamer stages are angularly displaced about the longitudinal tool axis by 180°, circumferentially opposing these in each blade set are dual drift blades which are hard branded and are positioned to dynamically stabilize the cutting structure whilst reaming. This off-set arrangement of the cutting blades will marginally enlarge the wellbore diameter and ensure that the bit will be able to pass through the wellbore without the need for back reaming. Due to this arrangement, the two sets of cutting structures are angularly placed on the cutting blades by approximately 180 degrees on the drill string.
It is essential that the tool maintains a stable cutting behavior and remains centered on the drill center axis of the wellbore being drilled, despite having a significant mass above and/or below its positioning in the bottom hole assembly. This is achieved by having a set of drift blades positioned 180 degrees circumferentially to the set of cutting blades. The drift blades are designed to dynamically stabilize the cutting action by helping the cutting blades remain centered on the drill center axis during rotation.
Each drift blade 6A, 6B of the trailing and leading eccentric reamer stages is straight and parallel to the longitudinal axis X of the tubular body. Each drift blade 6A, 6B has a dome shaped surface, that defines the surface contact area with the wellbore, and extends radially outwardly from the outer surface of the tubular body 2. The set of straight drift blades of the leading eccentric reamer stage are positioned circumferentially 180 degrees from the set of drift blades on the trailing eccentric reamer stage, and both sets of drift blades function as stabilizing blades. The center of the circle on which said drift blades are positioned is offset by a predetermined distance by the center of the tubular body part. Said drift blades are shaped wide in the middle and tapering towards the ends, but not to a point. To minimize or eliminate overpull required to trip out of the wellbore, hangup and overcome the static friction on the body, the first and second stabilizing blades 8, 10, the cutting blades 5A, 5B and the drift blades 6A, 6B are formed with unique 3-stage toe and heel angles which ensures a gradual cutting action and minimizing torque and vibration. The drift blades have angled faces at the toe and heel designated as a first angled face “T1”, a second angled face “T2”, and a third angled face “T3” as shown in
Each drift blade has a leading and a trailing edge, both having different radii of curvature. The leading edge and trailing edge are shown in
The wellbore contact geometry and contact area of the drift blades 6A, 6B are different to that of the cutting blades, which helps minimize friction with the formations, dampens oscillations.
During drilling the flow rate of the drilling fluid over a cross-section of the wellbore is not uniform; nearer to the low side, the flowrate is at a minimum and as a result, reduces the capacity of the drilling fluid to move the cuttings effectively. This problem can be overcome with the drill cuttings agitator having a plurality of stabilizing blades 8, 9, 10 and hydrodynamic flutes 7 in accordance with the present invention.
The drill cuttings agitator 4 that is positioned between the trailing and the leading eccentric reamer stages, comprises a plurality of stabilizing blades 8, 9, 10 and a plurality of hydrodynamic flutes 7, said hydrodynamic flutes being located circumferentially between the center stabilizing blades 9.
Said stabilizing blades 8, 9, and 10 have a curved surface along on the longitudinal axis “X” of the tool and are straight and parallel to the longitudinal axis X of the tubular body. These stabilizing blades 8, 9, 10 are formed e.g., milled, machined, as an integral component of the body of the drill cuttings agitator 4 and positioned between the leading eccentric reamer stage 3B and the trailing eccentric reamer stage 3A of the wellbore conditioning system. Each stabilizing blade's outer radial face shall be covered 100% by a replaceable wear element, e.g., hard facing.
The plurality of stabilizing blades 8, 9, 10, are defined as: a plurality of first stabilizing blades 8, also referred to as first stabilizing blades 8; a plurality of center stabilizing blades 9, also referred to as center stabilizing blades 9; a plurality of second stabilizing blades 10, also referred to as second stabilizing blades 10. Each stabilizing blade of said plurality of first, second and center stabilizing blades has an elongated shape parallel to the longitudinal axis X of the tubular body 2. Said plurality of stabilizing blades 8, 9, 10 form three groups: a first group comprising the first stabilizing blades 8, a second group comprising the second stabilizing blades 10; a center group comprising the center stabilizing blades 9, where each group of said three groups has four stabilizing blades.
Said three groups of stabilizing blades are disposed on the surface of the tubular body at a predetermined interval parallel to the longitudinal axis X. Said plurality of stabilizing blades extend outwardly from the outer surface of the tubular body, and with their most outwardly radially extended surface define an ideal cylinder that is coaxial with sections III of the tubular body. The first group of stabilizing blades 8 is positioned at one end of the drill cutting agitator immediately after the plurality of leading cutting blades 5B of the leading eccentric reamer stage 3B. The second group of stabilizing blades 10, similar to the first group is positioned at the other end of the drill cutting agitator, immediately before the plurality of trailing cutting blades 5A of the trailing eccentric reamer stage 3A. Between these two groups of stabilizing blades 8, 10, there is the group of center stabilizing blades 9. Each stabilizing blade of the described groups is disposed at a predetermined interval i.e., 90 degrees apart from each other, along a circumference coaxial with the tubular body.
A hydrodynamic flute 7 is disposed between each two consecutive center stabilizing blades 9. Also, a flow by-pass channel is defined between each two consecutive first and second groups of stabilizing blades 8, 10.
Furthermore, the group of center stabilizing blades 9 is offset by 45 degrees from the preceding first stabilizing blades 8 and the following group of second stabilizing blades 10.
Each stabilizing blade of the drill cutting agitator 4 is straight and is aligned along the longitudinal X axis. Each stabilizing blade of the drill cutting agitator 4 has an elongated shape, a front section, a back section, and a central section, and an upper surface having the shape of a dome defining the contact area, and side walls. The back section of the stabilizing blades 8, 10 belonging to the first and second groups tapers from said central section towards a back end. The front section of the stabilizing blades belonging to the first and second groups tapers towards a front end that has substantially the shape of a semicircle, said front section being substantially greater than the average width of the back section. The upper surface of the stabilizing blades 8, 10 belonging to the first and second groups slopes downwards near and towards the end of the front section and also near and towards the end of the back section till it meets the surface of said cylindrical body part forming this way a toe and heel having a unique 3-stage angled faces with different angles measured from the surface of the tubular body in the longitudinal direction X, namely a first angled face T1, a second angled face T2, and a third angled face T3, where the angle of the first angled face T1 is greater than the one of the second angled face T2, and the angle of the second angled face T2 is greater than the one of the third angled face T3, as shown in
Each blade of the first group of stabilizing blades 8 has a shape that is wide in the middle and tapers downstream towards a back end that is straight the cutting blade 5B and in the upstream direction tapers to a substantially semicircular back end towards the center stabilizing blades 9. As the flow of drilling fluid exits the leading eccentric reamer stage 3B, that corresponds to section IV of the tubular body 2 of
Said stabilizing blades 8, 9, 10 increase the velocity of the cuttings from the leading eccentric reamer stage 3B to the trailing eccentric reamer stage 3A, alter the direction of the drilling mud along the exterior of the tool and stabilize the tool in the borehole. As the tool rotates, it works two-fold: initially, by increasing the flow of the cuttings from the cutting blade structure over the section III length of the tool, secondly the stabilizing blades disturb the settled cuttings and move them up into the flow path of the drilling mud in the upper side of the wellbore this way providing an improved cuttings transportation and hole cleaning. At the low side of a horizontal wellbore the pressure and turbulence created by these stabilizing blades is directed at the segmented concentration of cuttings, and as the tool rotates this creates a scouring effect in the cuttings bed. Thus, the drill cuttings agitator accelerates the drilling fluid and cuttings over the length of the tool, and it picks-up/agitates cuttings bed accumulation on the low side of the horizontal wellbores.
Further, the agitator's stabilizing blades 8, 9, 10 stabilize the tool in the BHA. The wellbore conditioning system, thus, enhances the cutting transportation by having hydrodynamically positioned stabilizing blades 8, 9, 10 designed to stir a low side cuttings bed in horizontal well sections. As the reamer translates in a counter rotation downhole, and as drilling fluid and suspended cuttings and cavings flow past the stabilizing blades of the drill cuttings agitator located between the trailing and the leading eccentric reamer stage blade sets i.e., the cutting and the drift blades 5A, 5B, 6A, 6B, the geometry of the stabilizing blade elements increases the velocity of the drilling fluid, thus creating a turbulence in the mid-tool annulus, and producing a cleaning effect on the wellbore wall due to bearing pressure against the wall of the wellbore.
More in detail, a filter cake (or mud cake) is formed when the insoluble solid portion of the drilling fluid becomes deposited on a permeable material i.e, formation or porous rocks, as the drilling fluid makes contact with that material under pressure, so that permeation of the native formation is reduced or eliminated, and the wellbore fluids are isolated from the insoluble solid portion of the drilling fluids that occupy pore spaces in the formation at the wellbore wall. This is important in terms of wellbore stability and to prevent differential sticking. According to the present invention, a good filter cake is achieved by the additional bearing pressure against the wall of the wellbore and by the increase in annular velocity of the drilling fluid combined with geometry of the stabilizing blades 8, 9, and 10 which leads to a more compact and steadier filter cake whilst minimizing the risk of pack off during drilling operations.
All elements of the drill cuttings agitator work in synergy as the tool translates in a counter rotation, agitating the cuttings beds on the lower side of the wellbore up into the circulating drilling fluid where they are transported upstream. This way improving the hole cleaning, which is achieved through more effective transportation of cuttings across the tool thusly eliminating the need for dedicated wiper trips.
Drilling of the well occurs as the tool rotates counterclockwise. It is possible to have the cutting and drift diameter offset from the drill center by a fraction of an inch.
All blades of the leading eccentric reamer stage, all blades of the drill cuttings agitator and all blades of the trailing eccentric reamer stage are offset at 45 degrees in respect of the preceding or the following blades along the longitudinal axis X of the tubular body forming this way oblique flow-by channels in respect to the longitudinal axis X of the tubular body.
Oblique channels of 45 degrees in respect to the longitudinal axis X of the tubular body are formed between the back end of the leading cutting blade set 5B and front section of the first stabilizing blades 8 of each neighboring pair of blades to allow the flow of drilling fluid and cuttings during operations, this way defining the flow-by area between the blades.
The Total Flow by Area (TFA) i.e., the total volumetric flow (opening) between the exterior surface of the eccentric reamer stage and the circumference of the wellbore, is reduced at the blades locations, and to maintain adequate contact points with the wellbore and optimum flow rates it's important to ensure there is a percentile balance. To provide an effective hole cleaning on a Hole Size up to an outside diameter of 10-⅝″, the recommended Total Flow by Area should be >25% of the hole size. Hole Sizes of a greater diameter than 10-⅝″, should have a Total Flow by Area of >35% of the hole size.
In hole sizes of 8½″ (inches), the total flow area (TFA) ratio between tool outside diameter in smaller hole sizes is a quite different and parasitic pressure drop in the annulus can be significant in certain formations. The incorporated recessed flow-by pass channels, therefore, partially compensates for the annular area occupied by the blades. This, combined with optimized hydrodynamics, e.g., blades that are wide in the middle and tapering towards the ends but not to a point, facilitates increased transportation of cuttings around the blades 5A, 5B, 6A, 6B.
The front and back sections of the center stabilizing blades 9 of the drill cuttings agitator are substantially smaller than the central section of said center stabilizing blades 9. The reason behind this is to channel the mud flow from the first stabilizing blades 8 to the second stabilizing blades 10. The positioning of the first stabilizing blades 8 is such that they can efficiently displace the drilling fluid and cuttings around the blades of the wellbore conditioning system and increase the velocity of fluid exiting the leading reamer stage 3B, this increase in velocity combined with the stirring action created by the rotational side wall also known as the leading edge of the first stabilizing blade 8, stirs cuttings from the low side up to the high side of the wellbore.
The shape of the stabilizing blades 8, 9, 10 of the drill cuttings agitator is such that they effectively generate a venturi effect, which efficiently displaces the drilling mud or drilling fluid and suspended cuttings as it exits the cutting blade structures 5B and then enters around the first stabilizing blades 8. The stabilizing blades and the cutting blades are placed in such a way along the cylindrical surface of the tubular body in order to agitate any cuttings. This mechanical dual-acting blade placement removes cuttings beds inside the casing or in an open hole. The flow-by pass channels formed e.g. milled into the outer surface of the tubular body between the cutting blades 5A and 5B, are designed to create a self-cleaning and jetting-effect, accelerating the transportation of the cuttings dislodged during reaming over the center of the tool.
When drilling horizontal wellbore sections, the higher density of cuttings in the low side of the wellbore causes increased drag on the drill string when sliding through the cuttings beds. The first, second and center stabilizer blades 8, 9 and 10 are designed to stir up the cuttings beds into the fluid with a lower density on the high side of the wellbore, and then transport them over the tool and upstream for processing, and also to stabilize the tool in the borehole.
Located between the center stabilizing blades 9, there are a plurality of hydrodynamic flutes 7. Said hydrodynamic flutes are formed e.g., milled as an integral component of section III of the tubular body and said flutes extend radially inwardly from the outer surface of said tubular body. Further, the hydrodynamic flutes are designed to create a self-cleaning action by maintaining and further increasing the velocity of the drilling fluid along the tubular body. The hydrodynamic flutes 7 help support and further enhance the advantageous flow pattern created by the drilling cuttings agitator formed between leading reamer stage 3B and first stabilizing blade 8.
Further, the hydrodynamic flutes 7 are aligned with the X-axis of the section III of the tubular body and are parallel to one another. The flutes are elongated indents in the outer surface of the tubular body, having a longitudinal axis running from a downstream end to an upstream end that is parallel to the X-axis of the cylindrical body. The flutes are shaped advantageously, with two mirrored diverging indented paths 16 (see
The term “uphole” refers to the direction along the longitudinal axis of the wellbore that leads back to the surface, and the term “downhole” refers to equipment or processes that are used inside the well, more specifically in terms of direction refers to the direction toward the bottom-hole assembly.
The number of hydrodynamic flutes 7 located on the perfect circle may be four but may be depending on the diameter of the tool, and the number of the center stabilizing blades 9 formed, e.g., milled, in the tubular body. The diverging paths at each end of the flutes are designed to create as such at the downhole end of the hydrodynamic flutes 7 an inlet for the drilling fluid entering from between first stabilizing blades 8 and center stabilizing blades 9, respectively and an outlet for the drilling fluid at the uphole end.
Additionally, the advantageous positioning of the four or more center stabilizing blades 9 and four or more first stabilizing blades 8 and four or more second stabilizing blades 10, optimizes the stabilization of the tool and hydrodynamics of the cuttings bed agitator function. The flow acceleration over the center section of the drill cuttings agitator 4 may not cause or contribute to the borehole wall's penetration, which can lead to borehole instability and ultimate sectional collapse. The center section of the agitator shall provide stability when weight is applied, or when buffering occurs from vibration and shock loads being transmitted through the drill string. Furthermore, the specific configuration of the agitator's stabilizing blade set 8, 9,10 including the specific assortment and shape of the stabilizer blades and hydrodynamic flutes 7 arranged between them, creates a selfcleaning action, i.e., venturi effect, which has shown to minimize mud build-up, to provide homogeneous drilling fluid flow, and to minimize balling up.
The leading eccentric reamer stage 3B is placed at a minimum of distance apart from the trailing eccentric reamer stage 3A to provide the optimum cyclic cutting motion for the reaming functionality. The maximum radially outward extension of the external surface of the stabilizing blades 8, 9 and 10 is equal to or less than the maximum radially outward extension of the drift blades 6A and 6B. The radially outward extension of the drift blade 6A is equal to the radially outward extension of drift blade 6B.
The outer circumference of the drift blades 6B, 6A and stabilizing blades 8, 9, 10 makes contact with the wellbore and therefore is coated with a replaceable wear element, e.g., hard facing.
The plurality of stabilizing blades 8, 9, 10 increase the velocity of the cuttings from the leading to the trailing eccentric reamer stage and alter the direction of the drilling mud along the exterior of the tool. As the tool rotates, it works two-fold: initially, by increasing the speed of the flow of the cuttings from the cutting blade structure over the mid-section length of the tool, and secondly, the blades disturb the settled cuttings and moves them up into the flow path of the mud in the upper side of the wellbore.
The drift blades 6A, 6B, the cutting blades 5A, 5B, and the agitator's stabilizing blades 8, 9, 10 have a leading and trailing rotational edge with respect to the rotation of the tool.
In a preferred embodiment, each of the cutting blades 5B of the leading eccentric reamer stage 3B (shown in
The large TCI defines the diameter d1. There could be situations in which the use of the large TCIs is not necessary, then the diameter d1 is defined by the smaller TCIs.
Each of the cutting blades 5A of the trailing eccentric reamer stage 3A (shown in
The two large TCI's on the first cutting blade of the leading and trailing eccentric reamer stages extend radially outward more than the two large TCI's on the second cutting blade of the leading and trailing eccentric reamer stages.
The PDC elements are limited to the leading cutting blade 5B only; this may enhance the stability during cutting by minimizing the risk of a cutter snagging on the formation and then causing the tool to twist around the cutter or a number of aligned cutters radial extremities. The trailing cutting blade 5A is dressed with TCI's, which are intended to steadily caress the formation, reaming off any imperfections remaining from the initial cutting action of the leading blade structure, this way performing conditioning of the wellbore.
For optimum performance, the wellbore conditioning system should be run in tension and let the natural cyclic motion of the bottom hole assembly utilize the cutting structures to sheer off the imperfections while rotating without compromising weight and energy transfer to the drill bit.
It is to be understood that the above description is intended to be illustrative, and not restrictive and that various changes in the design details may be made without departing from the concept layout as presented or affecting the advantageous positioning of the features.
| Number | Date | Country | Kind |
|---|---|---|---|
| 21212615.5 | Dec 2021 | EP | regional |
| Filing Document | Filing Date | Country | Kind |
|---|---|---|---|
| PCT/EP2022/083245 | 11/25/2022 | WO |
