WO2009020827A2 - Method for altering the stress state of a formation and/or a tubular - Google Patents

Abstract

A method for altering the stress state of a subterranean formation, comprises a) drilling a borehole into the formation, b) installing a tubular element (200) having a top end and a bottom end in the borehole, c) anchoring the tubular element to the formation at at least two points (201,202) along the length of the tubular element, and d) expanding (205) the tubular element, thereby inducing compression (300) between the two points. At least one anchoring point (504) may be selected such that a pair of adjacent anchoring points spans an unstable portion of the formation, anchoring means may be used, and the position of at least one anchor point (504) may be selected such that the distance (Sl) between that anchor point and an adjacent anchor point is less than the maximum length (E) of pipe that could be expanded between two anchor points without failing.

Description

METHOD FOR ALTERING THE STRESS STATE OF A FORMATION

AND/OR A TUBULAR

This application is a continuation in part of U.S. Application Serial No. 60/953,776, filed on August 3, 2007 and entitled "Method For Altering The Stress State Of A Formation," which is incorporated herein by reference. Field of Invention

The present inventions include method for altering the stress state of a subterranean formation having an unstable portion using a tubular element expanded into or against the unstable portion. Background

[0001] Damage to weakly cemented, unconsolidated sands or soft rocks during the production and drilling of reservoirs is a costly problem for the oil and gas industry. Many of the reservoirs that are easy to drill and produce have already have been depleted during past oil and gas production operations leaving much of the existing reserves in more expensive, problematic reservoirs. Many of these remaining reservoirs are mechanically unstable and generate costly drilling and production problems such as compaction, depletion, water production, and formation movement. [0002] Reservoir compaction occurs when large volumes of gas, oil, and formation water are extracted from subsurface reservoirs causing a reduction in the original pressure in the reservoir. The phenomenon is described in detail in article entitled An Introduction To Reservoir Geomechanics by Colin Sayers and Peter M. T. M. Schutjens published in The Leading Edge, Volume 26, Issue 5, pp. 597-601 (May 2007). [0003] Reservoir compaction occurs because the weight of sediments above the oil and gas formation is supported by the rock matrix and the pressurized oil and gas within the rock pore space. When a reservoir is depleted, the reduction in pressure transfers the load to the depleted formation, causing it to compact and thereby reducing the ability of the formation to produce. If subsurface compaction is significant or if the formation is relatively shallow, it can result measurable surface subsidence which interferes with existing drilling and production infrastructure. Where multiple fields are producing from the same reservoir or stratigraphic interval, depressurization can occur on a regional scale, resulting in subsidence and land loss in areas between and adjacent to the fields. Additionally, formation compaction can also induce compression and buckling damage within the producing interval.

[0004] Wellbores are typically formed in two phases. In the first phase, a drill string (or drill pipe) with a drill bit attached to the lower end is rotated by a kelly, top drive system, rotary table, or coiled tubing system located at the surface. As the drill bit creates a hole in the earth, drilling mud is circulated through the annular space between the drill string and the wellbore wall to cool the bit and transport cuttings (rock chips from drilling) to the surface. The hydrostatic pressure exerted by the column of mud in the hole prevents blowouts that may result when the bit penetrates a high-pressure oil or gas zone. If the mud pressure becomes too low, the formation can force the mud from the hole resulting in a blowout. Conversely if the mud pressure becomes too high, the differential pressure becomes great enough that mud flows into the formation resulting in lost circulation. [0005] Lost circulation may also occur when the bit encounters natural fissures, caverns, or depleted zones, which provide a newly available space into which the mud can flow. The loss of drilling mud and cuttings into the formation results in slower drilling rates and plugging of productive formations. In a severe situation, it can cause a catastrophic loss of well control. Additionally the loss of fluid to the formation represents a financial loss that must be dealt with, and the impact of which is directly tied to the per barrel cost of the drilling fluid and the loss rate over time. [0006] In the next phase of drilling, the drill string and bit are removed and the wellbore is lined with a string of pipe known as casing. The casing serves to stabilize the newly formed wellbore and facilitate the isolation of certain areas of the wellbore adjacent to the hydrocarbon bearing formations. Once the casing is cemented in the wellbore, a smaller bit is inserted through the casing and used to drill deeper into the earth. This process is then repeated and numerous sections of casing are installed until the desired depth is reached. When the well is complete, the entire string of casing resembles an extended, inverted telescope in which casings of decreasing diameter are arranged in a nested configuration. [0007] As a consequence of this procedure, the casing in the lower interval of the wellbore has a significantly smaller diameter than the casing in the upper interval of the wellbore. Operators are often required to begin the drilling procedure with a relatively large initial borehole to reach planned depths. A larger initial borehole results in increased costs due to timing delays, rig time, and handling of equipment. In some cases, the ultimate depth of a well is limited by the initial borehole requirement and certain projects fail to be recognized as economical for this reason.

[0008] To overcome this problem, the oil and gas industry has begun to experiment with drilling and casing techniques that involve radially expanding individual casing strings as they are installed in the well in order to maximize the available diameter.

[0009] Although the use of expandable tubular technology helps reduce the problem associating with the telescoping effects of drilling and completing wells, traditional problems such as compaction, depletion, water production, and formation movement still occur, making many wells into costly and time consuming projects. [0010] Typical drilling methods for dealing with situations involving compaction and depleted reservoirs include drilling with drill string to within a few meters of the unstable or depleted reservoir, tripping the drill string out of the hole, running casing to bottom and setting it in cement. The objective of this method is to isolate as much of the overburden as possible so as to minimize the negative effects of lost returns. Nevertheless, once the remainder of the overlying reservoir is drilled and the unstable or depleted reservoir is penetrated, the differential pressure will still cause the weighted mud system to flow into the low-pressure formation that plugs up the formation.

[0011] Another method is to drill until the bottom of the hole "falls out," remove the drill pipe from the hole, and seal off the losses with a sealing device such as a cement plug. After the plug is installed, casing may be run into run into the borehole to the top of the loss zone where the reservoir is drilled with a reduced mud weight to prevent further losses. Neither of these methods is satisfactory, however, due to the time required for pulling the drill pipe and the losses of the weighted mud and cement to the production zone. [0012] US Patent 5,957,225 discloses a method of drilling into a reservoir formation that is unstable or depleted relative to adjacent formations comprising drilling into an area above the unstable or depleted formation to form a wellbore in that area and running an elongate liner assembly having a portion formed of a drillable material and cutters disposed adjacent to the bottom of the liner assembly into the wellbore. The liner assembly is then rotated to drill through the area above the unstable or depleted formation into the unstable or depleted formation to extend the wellbore. The liner assembly is then set in the wellbore and a drill bit is run into the wellbore and rotated to cut through the liner portion of drillable material. Although this method can minimize well control problems associated with unstable or depleted reservoirs, it does not address the telescoping effect of nesting casing drilled in the traditional manner. Additionally, the method requires specialized tools that are costly to make and may have uncertainties associated with operation.

[0013] Hence, there remains a need for a technique for drilling through unstable formations and avoiding the nested casings that are typically required. Summary of the Invention

[0014] The present inventions include a method for altering the stress state of a subterranean formation having an unstable portion comprising drilling a borehole in the formation into the unstable portion of the formation, installing a tubular element having a top end and a bottom end across the unstable portion of the formation, anchoring the top end and the bottom end of the tubular element to the formation and expanding the tubular element thereby inducing compression between the top end and the bottom end. The present method also provides a technique for altering the stress state within the tubular itself. [0015] The present methods can be used in a wellbore that traverses a formation with an unstable portion. The present methods comprise anchoring a tubular element above and below at least a section of the unstable portion of the formation; and expanding a tubular element. In some embodiments, a compressive force is applied to the unstable portion between the top end and the bottom end of the expanded tubular. [0016] In other embodiments, three or more anchor points are provided at predetermined distances along a tubular and the tubular is expanded between the points. By providing at least one anchor point that is located between the lowermost and uppermost anchor points, tensile stress that would otherwise accumulate during expansion of the entire length of the tubular instead accumulates only along the distance between adjacent anchor points. This in turn reduces the maximum tensile strength to which the tubular is subjected during expansion. In some embodiments, a compressive force is applied to the formation between each pair of anchor points. Brief Description of the Drawings [0017] The present invention is better understood by reading the following description of non-limitative embodiments with reference to the attached drawings, wherein like parts of each of the figures are identified by the same reference characters, and which are briefly described as follows: Figure 1 is a schematic view of a wellbore traversing a formation with an unstable portion.

Figure 2 is a schematic view of the wellbore lined with a tubular element.

Figure 3 is a schematic view of the tubular element expanded into or against the formation.

Figure 4 is a side view of one embodiment of an anchoring assembly connectable the tubular element.

Figure 5 is a cross-sectional view of the anchoring assembly of Figure 4 in a retracted mode. Figure 6 is a cross-sectional view of the anchoring assembly of Figure 4 in an expanded mode.

Figure 7 is a schematic view of an expandable tubular element anchored at multiple points.

[0018] It will be understood that the Figures are not to scale and are not intended to convey dimensions, relative size of components, or other quantitative aspects of the invention. Detailed Description

[0019] In this specification, the term tubular element is meant to include any tubular to be expanded. A casing, open hole liner, or other wellbore tubular may be expanded by the methods and apparatuses described and claimed herein. [0020] Referring to Figure 1, a wellbore 100 is shown drilled through a formation 101. Formation 101 has an unstable portion 102, which is traversed by wellbore 100. Unstable portion 102 may be any type of formation that could pose drilling and production challenges. For example, unstable portion 102 may be a portion of the formation subject to compaction, depletion, water production, or formation movement. [0021] Wellbore 100 may be drilled using coiled tubing, expandable drilling casing, or any other known method. In this exemplary embodiment, wellbore 100 has been drilled with a tubular 103 attached to a drill bit 104. Tubular 103 may be for example, expandable casing, expandable liner, conventional casing, or any other known type of drilling pipe. Optionally, the portion of the wellbore above unstable portion 102 may be lined with a tubular 105.

[0022] Once wellbore 100 is drilled through unstable portion 102, a tubular element 200 may be installed across unstable portion 102 as shown in Figure 2. Tubular element 200 may be, for example, a joint of expandable casing, expandable liner, or any other type of drilling tubular. Typically these joints are about 30 to 40 feet (about 9 to 12 meters) in length; however tubular elements made according to custom specifications may be used to suit the application. Alternatively more than one length of tubular element may be used to line unstable portion 102. [0023] Tubular element 200 has a top end 201 and a bottom end 202 that are anchored to formation 101. Anchoring to the formation may be any suitable means, including expansion against the formation. Expansion assembly 203 is run into the hole with tubular element 200 or alternatively installed after tubular element 200 is installed. In alternative embodiments, expansion assembly 203 and drill bit 104 can be integrated into a single tool. In the embodiment shown, expansion assembly 203 comprises an expansion cone 204; however, many alternative expansion systems, such as are known in the art, could be employed.

[0024] Referring to Figure 3, tubular element 200 is expanded against or into the formation as shown at 205, using any of the traditional methods of expansion. In one embodiment, tubular element 200 may be expanded using the solid expandable tubular (or SET) method of expansion. At the bottom of the SET system is a canister, known as the launcher (not shown), that contains the expansion cone. The launcher is constructed of thin wall, high strength steel that has a thinner wall thickness than the expandable casing. In this method, expansion cone 204 may be moved through tubular element 200 by applying a differential hydraulic pressure across the cone itself. The differential pressure may be pumped through an inner string connected to the cone.

[0025] In another embodiment, tubular element 200 may be expanded using purely mechanical methods. In this embodiment, expansion assembly 203 may be moved through tubular element 200 by applying a direct mechanical pull or push force, such as is shown at arrow 206. The mechanical force may applied by either raising (in a "bottom up" expansion) or lowering (in a "top down" expansion) the inner string using a jack or other surface lifting tool. Alternatively, a downhole jack or gripping tool may be used to apply the requisite force. [0026] Still referring to Figure 3, regardless of which expansion mechanism is used, radial expansion of the tubular typically causes axial shorting of the tubular. Thus, as expansion assembly 203 moves along the length of tubular element 200, stresses within the pipe tend to draw top end 201 and bottom end 202 together. However, because ends 201, 202 are anchored to formation 101, these stresses result in a force being applied to the formation, which in turn alters the stress state in wellbore 101. Thus, expansion into or against the formation creates a compressive force on unstable portion 102 indicated by arrows 300. If enough compression is applied, the fracture gradient of the formation may be increased. [0027] In addition, if unstable portion 102 is a depleted region of formation 101, the expanded tubular and compressive force may serve to isolate the unstable portion from the rest of the formation. If a depleted region is not isolated, the operator may encounter lost circulation problems requiring drilling of another well or other remedial measures. If unstable portion 102 is a water producing zone, expanding against or into the formation can serve to produce a seal and isolate this zone from the rest of the formation. [0028] It will be understood the points at which the expandable tubular element are anchored need not be at its ends. Rather, the concepts disclosed herein are applicable for any portion of a tubular element that is anchored at more than one point along its length. [0029] If the tubular element 200 is to be deliberately anchored at one or more locations, the anchoring may be achieved via various known methods. In one embodiment, tubular element 200 may include one or more anchoring assemblies 400 located at the desired anchoring point(s), such as top end 201 and/or bottom end 202 or at one or more points therebetween. Figure 4 depicts one example of a type of anchoring assembly that could be used in this application. In the embodiment illustrated, anchoring assembly 400 is attached to the lower end 202 end of tubular 200. Anchoring assembly 400 comprises one or more splines 401, which are initially in a retracted mode shown in Figure 5. When tubular element 200 is radially expanded (e.g. by moving expansion cone 203 through tubular 200), the radially outward force exerted by expansion assembly 203 shifts splines 401 into an expanded mode, as shown in Figure 6. In this expanded position, splines 401 engage the formation, anchoring the tubular element to it. It will be understood that splines 401 can be any shape or configuration. Likewise, they may be replaced with any other engagement means, including fixed or moveable members extending outwardly from the surface of tubular 200, elastomers, teeth, ridges, packers, or the like. In some embodiments, achoring may be achieved merely by expansion of the tubular against the borehole wall, without additional engaging means. [0030] After tubular element 200 is expanded and anchored into formation 101, the operator may continue drilling the well, by drilling through unstable portion 102 and extending wellbore 100, or may conduct any other desired downhole operation. [0031] While the radial stresses caused by radial expansion stop increasing when tubular element 200 reaches the desired expanded diameter, the stresses caused by axial shorting may behave differently, particularly if the unexpanded casing is fixed at two (or more) points within the borehole, as at 201, 202. Situations in which an unexpanded casing is fixed at two or more points within the borehole will be referred to hereinafter as a "fixed- fixed" tubular. While an example of a deliberately fixed- fixed tubular is described above, a fixed-fixed tubular can occur even if tubular element (or portion thereof) is not deliberately fixed at both ends. [0032] For instance, if the casing becomes stuck to the hole wall before expansion and its lower end is deliberately anchored at the beginning of expansion (so that the expansion device can be pulled upward from the lower end), a fixed-fixed tubular will result. Similarly, if the borehole wall "grabs" the casing at two or more points along its length, a fixed-fixed tubular will result. It has been found that is it sometimes desirable to drill a hole having a diameter that is close to the expanded diameter of the casing, thereby increasing the likelihood that such a sticking contact will occur between the tubular and the borehole wall. In addition, there may be instances in which the borehole wall does not maintain its integrity and shifts or deforms so that the shape or diameter of the borehole changes. In such cases, there is an increased likelihood that the casing will become fixed at one or more points in the borehole between the time that is emplaced and the time that it is expanded. If there is a delay during this period, the likelihood of deformation of the borehole, and thus the likelihood of sticking, increases further. Curved boreholes and boreholes in which the wall is unstable and prone to slumping are also more likely to produce fixed-fixed situations. [0033] Similarly, due to varying conditions and properties of the formations, the wellbore wall often has ledges or other projections that jut out into the borehole. This is particularly common in deviated wells and can frequently cause a problem with tools becoming stuck or broken by the ledges or projections. Thus, in one embodiment, projections in the wellbore can be utilized to advantage by deliberatly anchoring the tubular element against the ledges or projections. In this embodiment, the location of the ledges can be determined by performing a conventional logging operation and altering the well design to align the anchoring assemblies with the ledges. [0034] Advantages of some embodiments of the expanding a fixed-fixed tubular include one or of the following:

^■ ability to isolate unstable portion of a formation without additional tripping in and out of the wellbore, ■ reduction of starting size of wellbore due to use of expandable casing or liner,

^■ ability to stimulate depleted formation,

^■ ability to isolate water producing formation,

^■ avoiding the requirement to drill another well to get around an unstable portion of the formation, ■ sealing mechanism created by anchoring mechanisms eliminates the need for cement, and

^■ reduced drilling costs and rig time.

[0035] However, regardless of whether one or more of the anchor points is deliberate, it has been found that in cases where a fixed-fixed tubular occurs, axial stresses accumulate as the expansion device moves along the casing from one fixed point to the other. As axial stresses accumulate, they may exceed the maximum stress that can be withstood by the tubular, causing it to tear or break. Thus, there is a need for a way to prevent excessive stress build-up in expanding tubulars that are fixed at more than one point along their lengths. [0036] It has been found that by ensuring that the distance between any two anchor points is less than the distance required to accumulate a fatal stress during expansion, failures due to expansion can be avoided. This is true regardless of whether the anchor points are deliberately placed. Thus, one preferred technique is to determine the axial distance over which expansion in a fixed-fixed tubular can be tolerated and then to provide anchor points that are closer together than the predetermined distance. This concept is illustrated schematically in Figure 7.

[0037] In Figure 7, the lower end of an expandable tubular has been deliberately anchored to the formation at anchor point 500, so as to provide a fixed point against which the expansion cone (not shown, for simplicity) can be pulled. At some point above the lower end, such as at point 502, the tubular may become stuck to the formation, either deliberately, or as a result of the partial collapse of an unstable portion of the borehole wall. This would create a fixed-fixed tubular in which the distance between anchor points 500, 502 is indicated by L. [0038] Given certain information about the tubular and the expansion ratio, it is possible to calculate the maximum length of pipe that could be expanded between two anchor points without failing. This distance is indicated in Figure 7 by E. In cases where E is smaller than L, it may be desired to add at least one anchor point 504 between anchor points 500 and 502. In this way, two portions of expandable tubing are formed, having lengths Si and S₂, both of which are shorter than E. When the tubular of Figure 7 is expanded the axial stress accumulates during expansion of each section S₁ and S₂, but does not exceed L because it returns to zero, or near-zero, at each intermediate anchor point 504. [0039] In some embodiments, anchor points having a desired spacing may be provided as a preventive measure. In other embodiments, it may be decided to add anchor points after it has been determined that the expandable tubular has become stuck in the borehole, resulting in an undesired fixed- fixed tubular. The spacing of the anchor points may or may not be influenced by the presence, or not, of an unstable portion of the formation surrounding the borehole.. [0040] Those of skill in the art will appreciate that many modifications and variations are possible in terms of the disclosed embodiments, configurations, materials, and methods without departing from the scope of the invention. For example, the number, size, shape and/or mechanism of the anchor points can vary widely. Accordingly, the scope of the claims appended hereafter and their functional equivalents should not be limited by particular embodiments described and illustrated herein, as these are merely exemplary in nature and elements described separately may be optionally combined.

Claims

C L A I M S

1. A method for altering the stress state of a subterranean formation, comprising: a) drilling a borehole into the formation; b) installing a tubular element having a top end and a bottom end in the borehole; c) anchoring the tubular element to the formation at at least two points along the length of the tubular element; and d) expanding the tubular element, thereby inducing compression between the two points.

2. The method of claim 1 wherein step c) comprises expanding against or into the formation.

3. The method of claim 1 wherein step d) comprises pulling an expansion assembly through the tubular.

4. The method of claim 1 wherein step c) includes deploying an anchoring assembly comprising one or more formation engaging means.

5. The method of claim 5 wherein step c) further includes moving the formation engaging means from a retracted mode to an expanded mode.

6. The method of claim 1 wherein step c) comprises: cl) performing a logging operation; c2) locating ledges or projections in the wellbore; c3) anchoring the tubular element against at least one ledge or projection.

7. The method of claim 1 wherein step c) includes forming a seal between the tubular element and the formation.

8. The method of claim 1 wherein at least one anchoring point is selected such that a pair of adjacent anchoring points spans an unstable portion of the formation.

9. The method of claim 6 wherein the unstable portion is an interval producing water.

10. The method of claim 1 wherein the position of at least one anchor point is selected such that the distance between that anchor point and an adjacent anchor point is less than the maximum length of pipe that could be expanded between two anchor points without failing.

11. The method according to claim 1 where at least one anchor point is formed by expanding the tubular element.

12. The method according to claim 1 where at least one anchor point is not formed by expanding the tubular element.

13. A wellbore traversing a formation with an unstable portion comprising: a tubular element lining the unstable portion; wherein the tubular element includes at least two axially spaced-apart points that anchored against the formation; and wherein expanding the tubular element between the said points applies a compressive force against the unstable portion between said anchor points.

14. The wellbore of claim 13 wherein the compressive force is sufficient to increase the fracture gradient of the formation.

15. The wellbore of claim 13 wherein tubular element forms a seal around the unstable portion, thereby isolating the unstable portion from the rest of the formation.