EP2251524A1

EP2251524A1 - Wellbore treatment

Info

Publication number: EP2251524A1
Application number: EP09251306A
Authority: EP
Inventors: Mark Shelton Aston
Original assignee: BP Exploration Operating Co Ltd
Current assignee: BP Exploration Operating Co Ltd
Priority date: 2009-05-13
Filing date: 2009-05-13
Publication date: 2010-11-17

Abstract

1. A method of strengthening a wellbore wall in a zone of a wellbore that penetrates through a formation that is susceptible to formation breakdown ("weak formation") comprising:
(a) delivering a settable composition into the zone of the wellbore wherein the settable composition gradually increases in viscosity at the temperature encountered in the zone of the wellbore over a period of time of at least 1 hour, preferably, at least 2 hours, for example, 1 to 20 hours;
(b) increasing the pressure in the zone of the wellbore to at or above the initial fracture pressure of the formation by subsequently pumping a displacement fluid into the wellbore such that fractures are induced in the wall of the wellbore;
(c) continuing to pump the displacement fluid into the wellbore until the pressure in the zone of the wellbore remains substantially constant at an initial fracture propagating pressure;
(d) interrupting the pumping of the displacement fluid into the wellbore for a sufficient period of time for the settable composition to increase in viscosity;
(e) increasing the pressure in the zone of the wellbore by recommencing pumping of the displacement fluid into the wellbore until the pressure in the zone of the wellbore remains substantially constant at an increased fracture propagating pressure;
(f) optionally repeating steps (d) and (e) one or more times over the setting period of the settable composition until the pressure in the zone of the wellbore is at least 100 psi above, preferably, at least 500 psi above, in particular, at least 750 psi above the initial fracture pressure of step (b);
(g) maintaining the pumping pressure of the displacement fluid until the settable composition has completely set in the fractures and in the zone of the wellbore; and
(h) drilling out the set composition from the zone of the wellbore

Description

The present invention relates to strengthening the wall of a wellbore, and more particularly to a method of increasing the resistance of the wellbore wall to fracturing.
Conventionally, the drilling of a well into the earth by rotary drilling techniques, involves the circulation of a drilling fluid from the surface of the earth down a drill string having a drill bit on the lower end thereof and through ports provided in the drill bit to the well bottom and thence back to the surface through the annulus formed about the drill string. Commonly, drilling fluids are employed that are either oil or water based. These fluids are treated to provide desired rheological properties which make the fluids particularly useful in the drilling of wells.
A problem often encountered in the drilling of a well is the loss of unacceptably large amounts of drilling fluid into subterranean formations penetrated by the well. This problem is often referred to generally as "lost circulation", and the formations into which the drilling fluid is lost are often referred to as "lost circulation zones" or "thief zones". Various causes may be responsible for the lost circulation encountered in the drilling of a well. For example, a formation penetrated by the well may exhibit unusually high permeability or may contain fractures or crevices therein. In addition, a formation may simply not be sufficiently competent to support the pressure applied by the drilling fluid and may break down under this pressure and allow the drilling fluid to flow thereinto.
It is this latter situation where the formation is broken down by the pressure of the drilling fluid to which the present invention is addressed. One of the limiting factors in drilling a particular portion of a well is the mud weight (density of the drilling fluid) that can be used. If too high a mud weight is used, fractures are created in the wall of the borehole with resulting loss of drilling fluid and other operating problems. On the other hand, if too low a mud weight is used, encroachment of formation fluids can occur, borehole collapse may occur due to insufficient support from the fluid pressure in the wellbore, and in extreme cases safety can be compromised due to the possibility of a well blowout. In many cases, wells are drilled through weak or lost-circulation-prone zones prior to reaching a potential producing zone, requiring use of a low mud weight and installation of sequential casing strings to protect weaker zones above a potential producing zone. If a higher weight mud could be used in drilling through weaker or depleted zones, then there is a potential for eliminating one or more casing strings in the well. Elimination of even one casing string from a well provides important savings in time, material and costs of drilling the well. Thus, there is a need for a method of drilling boreholes using a higher mud weight than could normally be used without encountering formation breakdown problems.
International patent publication number WO 2005/012687 relates to controlling formation breakdown during drilling by using an ultra-low fluid loss mud with the pressure of the drilling mud maintained at above the initial fracture pressure of the formation wherein the fractures that are induced in the wellbore wall are bridged at or near the mouth thereof by a solid particulate material that is added to the drilling mud and the bridge is sealed by the accumulation of fluid loss additives in the voids between the bridging particles and/or the precipitation of fluid loss additives onto the bridging particles. The presence of the fluid impermeable bridge at or near the mouth of the fracture strengthens the near wellbore region of the formation by generating a stress cage. Thereafter, the drilling of the wellbore is continued with the pressure of the drilling mud maintained at below the breakdown pressure of the strengthened formation.
Although the use of bridging particles to prop open and seal fractures has been successful in permeable formations such as sandstone formations, it has now been found that the effect can be temporary in certain formations, such as shale formations. Without wishing to be bound by any theory, it is believed that the induced fractures in shale formations may not open sufficiently when pressure is applied to allow the solid particulate material to enter and become trapped within the fractures. In addition, owing to the impermeable nature of shale formations, fluid does not leak off from the fractures into the formation once a bridge has been formed at the mouths of the fractures. Accordingly, the pressure within the fractures is substantially the same as the pressure that is being applied to the bridging particles at the fracture mouth such that the bridging particles are readily removed from the mouths of the fractures as a result of small pressure changes in the wellbore. Also, if a settable fluid such as a resin, gel or cement composition is used in an attempt to retain the bridging particulate solids in place within the fractures of the wellbore, the bridging particulate solids may still not penetrate into the fracture and would also impede the flow of the settable fluid into the fractures.
It has now been found that a settable fluid such as a resin, cement or crosslinkable polymeric gel composition may be squeezed into the fractures that are induced in the wall of the wellbore, in the absence of particulate bridging solids. It has also been found that by using a composition that has a prolonged setting time, the width of the induced fractures may be increased during setting of the composition such that further settable composition may be squeezed into the fractures thereby increasing the hoop stress in the near wellbore region of the wellbore. In particular, it has been found that the hoop stress may be increased by performing a hesitation squeeze, in which the pressure in the wellbore is increased stepwise during the setting period for the composition thereby widening the fracture and ensuring the fracture is ultimately filled and sealed by the set composition.
Thus, according to a first aspect of the present invention there is provided a method of strengthening a wellbore wall in a zone of a wellbore that penetrates through a formation that is susceptible to formation breakdown comprising:

(a) delivering a settable composition into the zone of the wellbore wherein the settable composition gradually increases in viscosity at the temperature encountered in the zone of the wellbore over a period of time of at least 1 hour, preferably, at least 2 hours, for example, 1 to 20 hours;
(b) increasing the pressure in the zone of the wellbore to at or above the initial fracture pressure of the formation by subsequently pumping a displacement fluid into the wellbore such that fractures are induced in the wall of the wellbore;
(c) continuing to pump the displacement fluid into the wellbore until the pressure in the zone of the wellbore remains substantially constant at an initial fracture propagating pressure;
(d) interrupting the pumping of the displacement fluid into the wellbore for a sufficient period of time for the settable composition to increase in viscosity;
(e) increasing the pressure in the zone of the wellbore by recommencing pumping of the displacement fluid into the wellbore until the pressure in the zone of the wellbore remains substantially constant at an increased fracture propagating pressure;
(f) optionally repeating steps (d) and (e) one or more times over the setting period of the settable composition until the pressure in the zone of the wellbore is at least 100 psi above, preferably, at least 500 psi above, in particular, at least 750 psi above the initial fracture pressure of step (b);
(g) maintaining the pumping pressure of the displacement fluid until the settable composition has completely set in the fractures and in the zone of the wellbore; and
(h) drilling out the set composition from the zone of the wellbore.

By "fracture pressure" is meant the minimum fluid pressure in the zone of the wellbore at which a fracture is created in the wellbore wall.
The pressure that is applied in the zone of the wellbore when the settable composition is flowing into the fractures is referred to herein as "squeeze pressure".
The sequence of pumping and interrupting the pumping of the displacement fluid into the wellbore is referred to herein as a "hesitation squeeze".
The formation that is susceptible to formation breakdown is referred to herein as "weak formation".
If desired, where the displacement fluid is not compatible with the settable composition, a spacer fluid may be pumped into the wellbore before the displacement fluid. For example, the spacer fluid may be a solids free fluid (for example, base oil or water) while the displacement fluid may be a drilling fluid. If necessary, the space fluid may be viscosified (thickened) to prevent fingering of the settable composition through the spacer fluid.
The settable composition is initially a pumpable fluid, that may be delivered to the wellbore zone by being pumped down the wellbore from the surface. Preferably, the settable fluid has an initial viscosity (prior to being delivered to the zone of the wellbore) in the range of 1 to 1000 centipoise (cP).
The setting time of the settable composition is at least 1 hour, preferably, at least 2 hours, for example, at least 5 hours. Preferably, the setting period for the settable composition is in the range of 1 to 20 hours. The rate of increase in viscosity of the settable composition over the setting period may be linear or non-linear. Typically, the viscosity against time profile follows a curve with the rate of increase in viscosity increasing over the setting period. Accordingly, the period of time during which pumping is interrupted may be reduced in later stages of the hestitation squeeze process. Thus, towards the end of the setting period of the settable composition, the pumping may be interrupted for less than 5 minutes, for example, 1 to 2 minutes while towards the beginning of the setting period the pumping may be interrupted for up to 1 hour, for example, 15 to 30 minutes.
Without wishing to be bound by any theory, it is believed that thickening of the settable composition allows progressively higher squeeze pressures to be applied during the hestitation squeeze treatment of the present invention. Typically, the squeeze pressure may be increased by between 25-500 psi, preferably, 50 to 250 psi, in particular, 50 to 100 psi for each successive pumping stage of the hesitation squeeze treatment.
In step (b) of the present invention, once fractures have started to form in the wellbore wall in the zone of the wellbore that penetrates through a formation that is susceptible to formation breakdown (hereinafter "weak formation"), there will be a deviation in the downhole pressure (or pumped volume) against time curve. Thus, there is a decrease in the downhole pressure in the zone of the wellbore where the wellbore wall is to be strengthened. After this deviation has been observed, pumping is continued to allow the settable fluid to enter the fracture(s) until the downhole pressure is substantially constant. This is referred to as the fracture propagating pressure. Typically, 0.01 to 1 barrels, preferably 0.1 to 1 barrels of the settable composition enters the fractures. Pumping is then interrupted (stopped) for a sufficient period of time for there to be a significant increase in viscosity of the settable composition. Typically, pumping is initially interrupted for at least 15 minutes, preferably, at least 0.5 hour, for example, 0.5 to 1 hour. During this time, the settable composition may flow back out of the fracture into the wellbore as the fracture closes. Pumping of the displacement fluid is then resumed until the pressure in the zone in the wellbore remains substantially constant at a higher fracture propagating pressure as determined by the downhole pressure (or pumped volume) against time curve. Again, the amount of settable composition that enters the fractures is typically 0.01 to 1 barrels, preferably 0.1 to 1 barrels. This sequence of pumping and interrupting pumping is repeated one or more times until the settable composition has increased in viscosity (thickened) to such as extent that a desired target wellbore pressure can be applied to the open fractures without propagation of the fractures. By "target" wellbore pressure is meant the increased pressure of step (f). This desired target wellbore pressure is then maintained until the settable composition has completely set in the zone of the wellbore (within the fractures and within the wellbore). Typically, the displacement fluid is pumped into the wellbore during the pumping steps of the hesitation squeeze process of the present invention at a rate of 0.25 to 0.5 bbls/minute.
The stepwise increase in pressure at each successive stage of the hesitation squeeze process results in a stepwise increase in the width of the fractures that are induced in the wellbore wall. The increase in the fracture width results in additional settable composition being squeezed into the fractures before the fluid has completely set in the wellbore. Accordingly, the fractures become filled with a set composition which maintains the rock displacement caused by the fractures. The rock displacement caused by the fracture places the rock in the near wellbore region of the formation (for example, within a radial distance of up to 1 metre from the wellbore wall) in a state of compression, thereby increasing the "hoop stress" and generating a "stress cage". By "hoop stress" is meant the increased compressive stress in the near wellbore region of the weak formation that arises from the induced fractures being propped open by the set composition. This increased compressive stress in the near wellbore region of the weak formation results in the wall of the wellbore having a greater resistance to further fracturing. The method of the present invention therefore allows a drilling mud of higher density to be employed in drilling a further section of the wellbore than could be used in the absence of strengthening of the weak formation. The method also has a further beneficial effect of reducing loss of fluid from the drilling mud into the formation owing to the sealing of the fractures with the fluid impermeable settable composition.
An advantage of the present invention is that by accurately monitoring the pressure in the zone of the wellbore that penetrates the weak formation (or by accurately monitoring the surface pumping pressure), the amount of settable composition that enters the fractures can be controlled so as to limit fracture propagation. Thus, pumping of displacement fluid is either stopped or the amount of displacement fluid that is pumped into the wellbore is substantially reduced once the pressure in the wellbore is at or above the fracture propagation pressure for each stage of the hesitation squeeze treatment. Interruption of pumping reduces the propagation of the fractures and allows the viscosity of the settable composition to increase. This increase in viscosity of the settable composition results in an increase in the fracture propagating pressure.
A further advantage of the present invention is that the prolonged setting time of the settable composition avoids premature setting of the settable fluid in the wellbore before sufficient fracture width has developed to achieve the desired increase in "hoop stress". Typically, the fracture width increases with each successive stage of the hestitation squeeze process of the present invention owing to: (a) the progressive increase in viscosity of the settable composition that enters the fractures, and/or (b) the progressively higher squeeze pressure that is applied to the formation. Thus, the settable composition is designed to sustain sufficient applied pressure across the fracture width as the settable fluid sets in the fracture.
The mouth of a fracture that is induced in the wall of the wellbore will have a diameter (fracture width) substantially less than that of the wellbore, for example, in the range 0.1 to 5 mm, in particular, 1 to 2 mm. Accordingly, when the viscosity of the settable composition has increased to such an extent that it is no longer capable of flowing into the fractures, the composition remains flowable within the wider diameter wellbore. The settable composition is therefore capable of transmitting an applied pressure to the mouth of the fractures as the composition sets within the fractures. The wellbore wall is therefore strengthened owing to an increase in the hoop stress in the near wellbore region of the formation arising from the fractures being propped open by the set composition. The width of the fractures that are filled with the set composition and hence the increase in the hoop stress in the near wellbore region of the formation is dependent upon, amongst other factors, the strength (stiffness) of the formation rock, and the squeeze pressure that is achieved in the final stage of the hesitation squeeze.
The pressure applied to the zone of the wellbore that is susceptible to formation damage may be calculated using pressure sensors at the wellhead or at the surface and from the static head of the column of fluid in the wellbore above the zone of the wellbore that penetrates the weak formation (P_Appfied = P_surface + P_Head). Also, the volume of displacement fluid that is pumped from the surface during the pumping steps of the hesitation squeeze treatment of the present invention is accurately monitored using a flow meter at the surface so as to determine the volume of settable composition that enters the fractures induced in the weak formation. Interruption and recommencement of pumping of the displacement fluid may be automated using a negative feedback control system between the pressure sensors at the wellhead or at the surface and the pump that delivers the displacement fluid to the wellbore. A negative feedback control system is especially useful in the final stages of the hesitation squeeze process when the viscosity of the settable fluid may be rapidly increasing within the zone of the wellbore. Typically, after the fractures have been induced in the wall of the wellbore, pumping of the displacement fluid is continued as long as the pressure that is being monitored at the wellhead or at the surface continues to rise. Once the pressure is substantially constant, pumping is interrupted. It is envisaged that the pressure may be continuously monitored or may be intermittently monitored, for example, every 1 to 2 minutes. Where there is intermittent monitoring of the pressure, pumping is preferably interrupted when successive pressure readings, for example, two or three successive pressure readings, are the same. Where there is continuous pressure monitoring, pumping is preferably interrupted when the pressure is substantially constant for a period of 1 to 2 minutes. Pumping may then be restarted after a predetermined time period. As discussed above, this time period may decrease during the setting period of the composition. If the pressure measured at the wellhead or at the surface does not increase (after recommencing pumping of the displacement fluid), pumping is again interrupted for a period of time during which there is a further increase in the viscosity of the settable fluid. If the pressure at the wellhead or at the surface increases after recommencing pumping of the displacement fluid, pumping of the displacement fluid is continued until a higher fracture propagation pressure is reached (the pressure is no longer rising) at which point the automated control system interrupts pumping of the settable composition by turning off the surface pump that delivers the displacement fluid to the wellbore. Pumping is then restarted using the same procedure described above.
Typically, a pill of settable composition (a controlled amount of the settable composition) is injected into the wellbore wherein the amount of the pill is at least sufficient to fill the zone of the wellbore that is to be strengthened and to fill the fractures that are induced in the wellbore wall in the zone of the wellbore that penetrates the weak formation. A displacement fluid is then injected into the wellbore behind the pill of settable composition. Preferably, the amount of settable composition that is injected into the wellbore is minimized such that displacement fluid is present in the wellbore above the zone of the wellbore that penetrates the weak formation. An advantage of using a minimum volume pill of settable composition is that it will only be necessary to drill out the wellbore in the zone that penetrates the weak formation. Thus, the displacement fluid is a non-settable fluid, for example, an aqueous fluid or an organic fluid, for example, a drilling fluid.
The settable composition may contain a particulate material provided that the average particle size of the particulate material is less than 100 microns, preferably, less than 50 microns. The use of a particulate material of limited particle size mitigates the risk that the particulate material may bridge the fractures at or near the mouths thereof as this may prevent the settable composition from flowing into the fractures.
Suitably, the particulate material that may be optionally included in the settable composition as a filler. Preferred particulate materials for adding to the settable composition as a filler include graphite, calcium carbonate (preferably, marble), dolomite (MgCO₃.CaCO₃), celluloses, micas, proppant materials such as sands or ceramic particles and combinations thereof. These materials are very inert and are environmentally acceptable. Suitably, the concentration of particulate material in the settable composition is in the range of 0 to 200 pounds per barrel, preferably, 1 to 100 pounds per barrel.
Typically, the settable composition for use in the method of the present invention is selected from the group consisting of (a) cement compositions, (b) thermosetting resin compositions selected from epoxy resin compositions, furan resin compositions, and polyester resin compositions, and (c) cross-linkable polymeric compositions.
The cement composition may be any slurry of a cement in a carrier fluid, preferably, an aqueous carrier fluid, wherein the average particle size of the cement is less than 100 microns, such as 0.1-50 microns, preferably 0.5-10 microns, especially 1-5 microns. Typically, the cement is a Portland cement, and may be made by methods well known to the person skilled in the art. The cement composition may contain 10-80% cement, in particular 20-70% cement.
The cement composition for use in the present invention is designed to have a gradual set time under the conditions of temperature and pressure prevailing in the zone of the wellbore that spans the weak formation that is to be consolidated. Accordingly, the viscosity of the cement composition increases gradually in a controlled manner as it sets. In particular, the cement should not have a so-called "right-angle" set, which makes it distinctive from commonly used oil field cement compositions. As is well known to the person skilled in the art, the setting time for the cement and the rate at which the viscosity of the cement composition increases during the setting period may be controlled by using additives such as accelerators or retarders that are added to the aqueous carrier fluid. Suitable setting accelerators include calcium chloride, for example, in an amount of 0.1-10% by weight based on the weight of the aqueous medium. Suitable setting retarders include sugars such as sucrose. Alternatively or additionally, the setting time and the viscosity rate increase of the cement composition may be controlled by using extenders that are added to the cement composition. Suitable extenders include clays such as bentonite or soluble silicates such as sodium silicate. The cement composition for use in the present invention should harden, at the temperature encountered in the zone of the wellbore that penetrated the weak formation, over a period of time of at least 1 hour, preferably, at least 2 hours, for example, 1 to 20 hours. It is within the common general knowledge of the person skilled in the art to select a cement composition having the desired setting characteristics.
The thermosetting resin composition for use in the present invention may be a thermosetting epoxy resin, furan resin or polyester resin composition. Suitably, a curing agent (catalyst) is added to the thermosetting resin composition. The thermosetting resin composition hardens over a period of time of at least 1 hour, preferably, at least 2 hours, for example, 1 to 20 hours, at the temperature prevailing in the zone of the wellbore that penetrates the weak formation. It is within the common general knowledge of the skilled person to select a thermosetting resin composition having the desired setting characteristics.
The settable polymeric composition for use in the present invention may comprise an aqueous or organic liquid, a crosslinkable polymer, a crosslinking agent and optionally a gelation delaying agent. The crosslinkable polymers suitable for use in this invention include but are not limited to biopolysaccharides, cellulose ethers and acrylamide-containing polymers. Suitably, the polymers contain crosslinkable groups such as carboxylate, phosphonate or hydroxyl groups. The person skilled in the art will understand that the polymer should contain sufficient crosslinkable groups to form a rigid cross-linked polymer. It is within the common general knowledge of the skilled person to select a biopolysaccaride, cellulose ether or acrylamide-containing polymer for the crosslinkable polymeric composition that has sufficient crosslinkable groups to form a rigid crosslinked polymer. Further polymers for use in the present invention include graft copolymers prepared by reacting hydrophilic polymers with certain allyl or vinyl monomers having a crosslinkable substituent. For example, graft copolymers of hydrophilic polymers and vinyl phosphonate are disclosed in US 5,701,956 . The crosslinking agent that is included in the settable polymeric composition may comprise any of the well known polyvalent metal compounds which are capable of creating a cross-linked structure with the particular polymer utilized, for example, a metal compound selected from the group consisting of zirconium compounds, titanium compounds, aluminium compounds, iron compounds, chromium compounds, hafnium compounds, niobium compounds and antimony compounds. The polymeric composition may also contain a gelation delaying agent in order to mitigate the risk of the composition setting prematurely before the hesitation squeeze can be completed. A gelation delaying agent is defined herein as a chemical or mixture of chemicals which delays the rate of gelation. A delaying agent useful for the retardation of the rate of gelation may be a carboxylic acid or a salt thereof. A further commonly known gelation delaying agent is an amine that has more than one functional group and contains one or more hydroxyls and that can chelate the polyvalent metal moiety of the polyvalent metal compound
Suitably, the set composition (cement, resin or polymeric composition) has a sufficient compressive strength to withstand the closure stresses exerted on the fracture. However, it is preferred that the compressive strength of the composition, when set, is less than that of the strengthened formation in order to mitigate the risk of accidentally deviating from the original wellbore when drilling out the set composition. In other words, where the set composition has a lower compressive strength than the formation, it will be easier to drill through the set composition that fills the wellbore in the strengthened zone than to drill through the formation. Typically, the settable composition has a compressive strength (UCS strength) when set which is 10-90% of the compressive strength of the formation, more preferably, 50-80%. The strength of the set composition may be controlled in a number of ways depending on the system. For cements, the slurry density is typically used to control the set strength. UCS strengths may typically vary from 500 psi to 10,000 psi for set cements, depending on the slurry design. For cross-linkable polymeric compositions, the compressive strength of the set composition will be dependent on the molecular weight of the polymer, the concentrations of cross-linking agent and of polymer employed in the settable polymeric composition, and on the concentration and type of the optional filler material that may be included in the settable polymeric composition. For resin compositions, the compressive strength of the set resin will be dependent on the number of active groups (for example, epoxy or unsaturated groups) of the resin prior to curing of the resin and on the concentration and type of the optional filler material that may be included in the settable resin composition.
As is well known to the person skilled in the art, formation pressure generally increases with increasing depth of the wellbore. It is therefore generally necessary to continuously increase the pressure of a drilling mud during a drilling operation, for example, by increasing the density of the drilling mud. A problem arises when the increased pressure of the drilling mud exceeds the initial fracture pressure of a previously drilled formation ("weak formation"). The method of the present invention may therefore be used to strengthen such weak formations thereby allowing the pressure of the drilling mud that is employed for completing the drilling operation to be increased to above the initial fracture pressure of the weak formation.
Thus, in a specific embodiment of the present invention there is provided a method of reducing formation breakdown during the drilling of a wellbore through a weak formation with a circulating drilling mud which method comprises:

(a) drilling a section of wellbore through the weak formation using a drilling mud wherein the pressure of the drilling mud is below the initial fracture pressure of the formation;
(b) displacing the drilling mud from the formation by injecting a first displacement fluid;
(c) delivering a settable composition into the zone of the wellbore that penetrates the weak formation wherein the settable fluid sets at the temperature encountered in the zone of the wellbore over a period of time of at least 1.0 hours, preferably, at least 2 hours, for example, 1 to 20 hours;
(d) increasing the pressure in the zone of the wellbore to above the initial fracture pressure of the formation by subsequently pumping a displacement fluid into the wellbore such that fractures are induced in the wall of the wellbore;
(e) continuing to pump the displacement fluid into the wellbore until the pressure in the zone of the wellbore remains substantially constant at the initial fracture propagating pressure;
(f) interrupting the pumping of the displacement fluid into the wellbore for a sufficient period of time for the settable composition to increase in viscosity;
(g) increasing the pressure in the zone of the wellbore by recommencing pumping of the displacement fluid into the wellbore until the pressure in the zone of the wellbore remains substantially constant at an increased fracture propagating pressure;
(h) optionally repeating steps (f) and (g) one or more times over the setting period of the settable composition until the pressure in the zone of the wellbore is at least 100 psi above, preferably, at least 500 psi above, in particular, at least 750 psi above the fracture pressure of step (b); and
(i) drilling out the set composition from the zone of the wellbore and optionally extending the wellbore while circulating a drilling mud in the wellbore wherein the pressure of the drilling mud in the strengthened zone of the wellbore is maintained above the initial fracture pressure of the weak formation and below the breakdown pressure of the strengthened formation.

By "breakdown pressure of the strengthened formation" is meant the maximum fluid pressure that can be sustained within the wellbore without creating a fracture in the strengthened formation.
It is envisaged that the displacement fluid may be a drilling fluid (often referred to as drilling mud). If necessary, for compatibility reasons, a spacer fluid could be placed between the pill of settable composition and the drilling mud. Typically, the spacer fluid may be a base oil or water.
The weak formation lies in a previously drilled section of the wellbore. It is therefore only necessary to replace the drilling mud that is used to drill the wellbore section in the vicinity of the weak formation. Thus, as described above, the settable composition may be introduced into the wellbore as a "pill" and may be passed to the weak formation where it is squeezed in stages into the weak formation as described above so that the composition sets in the open fractures. Typically, the pill is squeezed into the weak formation by raising the drill string until it lies immediately above the zone of the wellbore that extends through the weak formation, sealing the annulus between a drill string and the wellbore wall, and pumping the pill into the wellbore via the drill string. A displacement fluid is then pumped into the wellbore until the pressure in the vicinity of the weak formation is greater than the fracture pressure of the formation. If the wellbore extends below the weak formation, it is preferred to seal off the wellbore below the zone that penetrates through the weak formation so as to reduce the amount of the pill of settable composition that is introduced into the wellbore and to prevent the composition from setting in the wellbore below the weak zone i.e. in a zone of the wellbore that does not require strengthening. This reduces the length of the wellbore that needs to be drilled out to remove the set composition prior to recommencing drilling of the wellbore. After strengthening the weak formation, drilling of the wellbore may be continued using a drilling mud with the proviso that the pressure in the wellbore in the vicinity of the strengthened formation is maintained below the breakdown pressure of the strengthened formation.
Although the method of the present invention has been described above, in relation to a vertical well, the method of the present invention may also be applied to deviated wells (inclined or horizontal wells).
The invention is illustrated by the following Examples and Figures.

Example 1

An aqueous cement composition (300 ml) comprising 73% wt/wt of Portland cement was placed in a 500 ml beaker that was fitted with a stirrer paddle. The cement composition was heated at a temperature of 50°C whilst the stirrer paddle was rotated at a rate of 6 revolutions per minute (rpm). The torque of the composition was measured as the cement thickened.
This experiment was repeated with 10% by weight of bentonite clay added to the cement composition as a retarder.
The results of these experiments are shown in Figure 1 which shows a "right angled" set for the initial cement composition and a gradual set for the composition that contained the bentonite clay.

Example 2

A polyester resin composition (Norester 854^™, supplied by Nord Composites, France) had an initial viscosity of 1500 mPa.s at a temperature of 20°C. A methyl ethyl ketone peroxide catalyst (2% Butanox M50^™) was added to the resin composition which was then found to set gradually over a period of 400 minutes. The person skilled in the art could readily provide a composition that sets gradually at the higher temperatures prevailing in a wellbore by reducing the concentration of the catalyst.

Example 3

Figure 2 shows the calculated pressure required to initiate flow in a number of theoretical fractures having a constant width of 1mm and a height of 30 metres where the fractures extend different distances into the rock (fracture lengths of 0.5, 1, 2, 3 and 5 metres).
The pressure was calculated using the following equation that is based on force balance considerations: $Ty = W * deltaP / 2 * L$

wherein Ty is the yield stress (gel strength); W is the fracture width, delta P is the pressure to initiate flow in the fracture, and L is the penetration depth (length) of the fracture.
The data illustrated in Figure 2 shows that for progressively longer fractures (where there is progressively deeper penetration of the settable composition) it becomes progressively harder to pump the composition into the fractures. Thus, as the viscosity of the settable composition increases with time due to gradual setting of the composition (i.e. as the yield stress increases), it becomes more difficult (requires higher pressure) to force the composition into the fracture, especially for long fractures.

Claims

A method of strengthening a wellbore wall in a zone of a wellbore that penetrates through a formation that is susceptible to formation breakdown ("weak formation") comprising:
(a) delivering a settable composition into the zone of the wellbore wherein the settable composition gradually increases in viscosity at the temperature encountered in the zone of the wellbore over a period of time of at least 1 hour, preferably, at least 2 hours, for example, 1 to 20 hours;

(b) increasing the pressure in the zone of the wellbore to at or above the initial fracture pressure of the formation by subsequently pumping a displacement fluid into the wellbore such that fractures are induced in the wall of the wellbore;

(c) continuing to pump the displacement fluid into the wellbore until the pressure in the zone of the wellbore remains substantially constant at an initial fracture propagating pressure;

(d) interrupting the pumping of the displacement fluid into the wellbore for a sufficient period of time for the settable composition to increase in viscosity;

(e) increasing the pressure in the zone of the wellbore by recommencing pumping of the displacement fluid into the wellbore until the pressure in the zone of the wellbore remains substantially constant at an increased fracture propagating pressure;

(f) optionally repeating steps (d) and (e) one or more times over the setting period of the settable composition until the pressure in the zone of the wellbore is at least 100 psi above, preferably, at least 500 psi above, in particular, at least 750 psi above the initial fracture pressure of step (b);

(g) maintaining the pumping pressure of the displacement fluid until the settable composition has completely set in the fractures and in the zone of the wellbore; and

(h) drilling out the set composition from the zone of the wellbore.
A method of reducing formation breakdown during the drilling of a wellbore through a formation that is susceptible to formation breakdown ("weak formation") with a circulating drilling mud which method comprises:
(a) drilling a section of wellbore through the weak formation using a drilling mud wherein the pressure of the drilling mud is below the initial fracture pressure of the formation;

(b) displacing the drilling mud from the formation by injecting a first displacement fluid;

(c) delivering a settable composition into the zone of the wellbore that penetrates the weak formation wherein the settable fluid sets at the temperature encountered in the zone of the wellbore over a period of time of at least 1.0 hours, preferably, at least 2 hours, for example, 1 to 20 hours;

(d) increasing the pressure in the zone of the wellbore to above the initial fracture pressure of the formation by subsequently pumping a displacement fluid into the wellbore such that fractures are induced in the wall of the wellbore;

(e) continuing to pump the displacement fluid into the wellbore until the pressure in the zone of the wellbore remains substantially constant at the initial fracture propagating pressure;

(f) interrupting the pumping of the displacement fluid into the wellbore for a sufficient period of time for the settable composition to increase in viscosity;

(g) increasing the pressure in the zone of the wellbore by recommencing pumping of the displacement fluid into the wellbore until the pressure in the zone of the wellbore remains substantially constant at an increased fracture propagating pressure;

(h) optionally repeating steps (f) and (g) one or more times over the setting period of the settable composition until the pressure in the zone of the wellbore is at least 100 psi above, preferably, at least 500 psi above, in particular, at least 750 psi above the fracture pressure of step (b); and

(i) drilling out the set composition from the zone of the wellbore and optionally extending the wellbore while circulating a drilling mud in the wellbore wherein the pressure of the drilling mud in the strengthened zone of the wellbore is maintained above the initial fracture pressure of the weak formation and below the breakdown pressure of the strengthened formation.
A method as claimed in Claims 1 or 2 wherein the settable composition has an initial viscosity in the range of 1 to 1000 centipoise (cP) and is delivered to the zone of the wellbore by being pumped down the wellbore.
A method as claimed in any one of the preceding claims wherein the setting period of the settable composition is in the range of 1 to 20 hours and the rate of increase in viscosity of the settable composition over the setting period is linear or non-linear.
A method as claimed in any one of the preceding claims wherein the squeeze pressure is increased by between 25-500 psi for each successive step of pumping the displacement fluid.
A method as claimed in any one of the preceding claims wherein the displacement fluid is pumped into the wellbore during the pumping step(s) at a rate of 0.25 to 0.5 bbls/minute.
A method as claimed in any one of the preceding claims wherein interruption and recommencement of pumping of the displacement fluid is automated using a negative feedback control system.
A method as claimed in any one of the preceding claims wherein the amount of settable composition that is injected into the wellbore is minimized such that displacement fluid is present in the wellbore above the zone of the wellbore that penetrates the weak formation.
A method as claimed in any one of the preceding claims wherein the settable composition comprises a particulate filler material having an average particle size of less than 100 microns, preferably, less than 50 microns.
A method as claimed in any one of the preceding claims wherein the settable composition is selected from the group consisting of (a) cement compositions, (b) thermosetting resin compositions selected from epoxy resin compositions, furan resin compositions, and polyester resin compositions, and (c) cross-linkable polymeric compositions.
A method as claimed in any one of the preceding claims wherein the settable composition, when set, has a compressive strength (UCS strength) which is 10-90%, preferably 50-80%, of the compressive strength of the formation.
A method as claimed in any one of the preceding claims wherein the displacement fluid is a drilling fluid.
A method as claimed in any one of Claims 2 to 12 wherein the wellbore is drilled using a drilling mud that is circulated into the wellbore via a drill string and wherein after displacing the drilling mud with the first displacement fluid, the drill string is raised to a position above the zone of the wellbore that extends through the weak formation, the annulus formed between the drill string and the wellbore wall is sealed, and the settable composition and the second displacement fluid are sequentially pumped into the wellbore via the drill string.
A method as claimed in Claim 13 wherein the wellbore that is drilled through the weak formation extends below the weak formation, and wherein the portion of the wellbore below the weak formation is sealed off thereby preventing the composition from setting in the wellbore below the weak formation.
A method as claimed in Claims 13 or 14 wherein after drilling through the set composition, drilling of the wellbore is continued using a drilling mud with the proviso that the pressure in the wellbore in the vicinity of the strengthened formation is maintained at below the breakdown pressure of the strengthened formation.