Method and tool for evaluating fluid dynamic properties of a cement annulus surrounding a casing

Abstract

The permeability of the cement annulus surrounding a casing is measured by locating a tool inside the casing, placing a probe of the tool in hydraulic contact with the cement annulus, measuring the change of pressure in the probe over time, where the change in pressure over time is a function of among other things, the initial probe pressure, the formation pressure, and the permeability, and using the measured change over time to determine an estimated permeability. By drilling into the cement and making additional measurements of the change of pressure in the probe over time, a radial profile of the cement permeability can be generated.

Description

BACKGROUND OF THE INVENTION

1. Field of the Invention

This invention relates broadly to the in situ testing of a cement annulus located between a well casing and a formation. More particularly, this invention relates to methods and apparatus for an in situ testing of the permeability of a cement annulus located in an earth formation. While not limited thereto, the invention has particular applicability to locate formation zones that are suitable for storage of carbon dioxide in that the carbon dioxide will not be able to escape the formation zone via leakage through a permeable or degraded cement annulus.

2. State of the Art

After drilling an oil well or the like in a geological formation, the annular space surrounding the casing is generally cemented in order to consolidate the well and protect the casing. Cementing also isolates geological layers in the formation so as to prevent fluid exchange between the various formation layers, where such exchange is undesirable but is made possible by the path formed by the drilled hole. The cementing operation is also intended to prevent gas from rising via the annular space and to limit the ingress of water into the production well. Good isolation is thus the primary objective of the majority of cementing operations carried out in oil wells or the like.

Consequently, the selection of a cement formulation is an important factor in cementing operations. The appropriate cement formulation helps to achieve a durable zonal isolation, which in turn ensures a stable and productive well without requiring costly repair. Important parameters in assessing whether a cement formulation will be optimal for a particular well environment are the mechanical and adherence properties of the cement after it sets inside the annular region between casing and formation. Compressive and shear strengths constitute two important cement mechanical properties that can be related to the mechanical integrity of a cement sheath. These mechanical properties are related to the linear elastic parameters namely: Young's modulus, shear modulus, and in turn Poisson's ratio. It is well known that these properties can be ascertained from knowledge of the cement density and the velocities of propagation of the compressional and shear acoustic waves inside the cement.

In addition, it is desirable that the bond between the cement annulus and the wellbore casing be a quality bond determined by the cement's adhesion to the formation and the casing. It is desirable that the cement pumped in the annulus between the casing and the formation completely fills the annulus.

Much of the prior art associated with in situ cement evaluation involves the use of acoustic measurements to determine bond quality, the location of gaps in the cement annulus, and the mechanical qualities (e.g., strength) of the cement. For example, U.S. Pat. No. 4,551,823 to Carmichael et al. utilizes acoustic signals in an attempt to determine the quality of the cement bond to the borehole casing. U.S. Pat. No. 6,941,231 to Zeroug et al. utilizes ultrasonic measurements to determine the mechanical qualities of the cement such as the Young's modulus, the shear modulus, and Poisson's ratio. These non-invasive ultrasonic measurements are useful as opposed to other well known mechanical techniques whereby samples are stressed to a failure stage to determine their compressive or shear strength.

Acoustic tools are used to perform the acoustic measurements, and are lowered inside a well to evaluate the cement integrity through the casing. While interpretation of the acquired data can be difficult, several mathematical models have been developed to simulate the measurements and have been very helpful in anticipating the performance of the evaluation tools as well as in helping interpret the tool data. The tools, however, do not measure fluid dynamic characteristics of the cement.

SUMMARY OF THE INVENTION

The present invention is directed to measuring a fluid dynamic property of a cement annulus surrounding a borehole casing. A fluid dynamic property of the cement annulus surrounding a casing is measured by locating a tool inside the casing, placing a probe of the tool in fluid contact with the cement annulus, measuring the change of pressure in the probe over time, where the change in pressure over time is a function of among other things, the initial probe pressure, the formation pressure, and the fluid dynamic property of the cement, and using the measured change over time to determine an estimated fluid dynamic property.

According to one aspect of the invention, a cement annulus location is chosen for testing, and a wellbore tool is used to drill through the casing. In one embodiment, when the drill has broken through the casing and reaches the cement annulus, the drilling is stopped, the pressure probe is set around the drilled hole, and pressure measurements are made. The pressure measurements are then used to determine the fluid dynamic property of the cement. In another embodiment, the drill is used to drill through the casing and into, but not completely through the cement. The pressure probe is then set, and the change of pressure in the probe is measured over time. The drill may then be used to drill further into the cement, and the pressure probe may be reset for additional measurements. Further drilling and further measurements may be made, and a radial cement permeability profile (i.e., the permeability at different penetration depths into the cement at the same azimuth) may be determined.

The present invention is also directed to finding one or more locations in a formation for the sequestration of carbon dioxide. A location (depth) for sequestration of carbon dioxide is found by finding a high porosity, high permeability formation layer (target zone) having large zero or near zero permeability and preferably inert (non-reactive) cap rocks above the target zone, and testing the permeability of the cement annulus surrounding the casing at or above that zone to insure that carbon dioxide will not leak through the cement annulus at an undesirable rate. Preferably, the cement annulus should have a permeability in the range of a few microDarcys or less.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a schematic diagram partly in block form of an apparatus of the invention located in a wellbore capable of practicing the method of the invention.

FIG. 2 is a schematic showing the casing, the cement annulus, and various parameters.

FIG. 3 is a plot showing the value of a correction term as a function of two variables.

FIG. 4 is a flow chart showing one aspect of the invention related to testing the permeability of the cement annulus.

FIG. 5 is a permeability profile of a cement annulus at a particular depth and azimuth.

FIG. 6 is a plot of an example pressure decay measured by a probe over time.

FIG. 7 is a log of cement annulus permeability determinations as a function of borehole depth.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

Turning now to FIG. 1, a formation 10 is shown traversed by a wellbore 25 (also called a borehole) which is typically, although not necessarily filled with brine or water. The illustrated portion of the wellbore is cased with a casing 40. Surrounding the casing is a cement annulus 45 which is in contact with the formation 10. A device or logging tool 100 is suspended in the wellbore 25 on an armored multi-conductor cable 33, the length of which substantially determines the location of the tool 100 in the wellbore. Known depth gauge apparatus (not shown) may be provided to measure cable displacement over a sheave wheel (not shown), and thus the location of the tool 100 in the borehole 25, adjusted for the cable tension. The cable length is controlled by suitable means at the surface such as a drum and winch mechanism (not shown). Circuitry 51 shown at the surface of the formation 10 represents control, communication, and preprocessing circuitry for the logging apparatus. This circuitry, some of which may be located downhole in the logging tool 100 itself, may be of known type. A processor 55 and a recorder 60 may also be provided uphole.

The tool 100 may take any of numerous formats and has several basic aspects. First, tool 100 preferably includes a plurality of tool-setting piston assemblies 123, 124, 125 or other engagement means which can engage the casing and stabilize the tool at a desired location in the wellbore. Second, the tool 100 has a drill with a motor 150 coupled to a drill bit 152 capable of drilling through the casing 40 and into the cement. In one embodiment, a torque sensor 154 is coupled to the drill for the purpose of sensing the torque on the drill as described in the parent application hereto. In another embodiment, a displacement sensor 156 is coupled to the drill motor and/or the drill bit for sensing the lateral distance the drill bit moves (depth of penetration into the cement) for the purposes described below. Third, the tool 100 has a hydraulic system 160 including a hydraulic probe 162, a hydraulic line 164, and a pressure sensor 166. The probe 162 is at one end of and terminates the hydraulic line 164 and is sized to fit or stay in hydraulic contact with the hole in the casing drilled by drill bit 152 so that it hydraulically contacts the cement annulus 45. This may be accomplished, by way of example and not by way of limitation, by providing the probe with an annular packer 163 or the like which seals on the casing around the hole drilled by the drill bit. The probe may include a filter valve (not shown). In one embodiment, the hydraulic line 164 is provided with one or more valves 168a and 168b which permit the hydraulic line 164 first to be pressurized to the pressure of the wellbore, and which also permit the hydraulic line 164 then to be hydraulically isolated from the wellbore. In another embodiment, hydraulic line 164 first can be pressurized to a desired pressure by a pump 170, and then isolated therefrom by one or more valves 172. In the shown embodiment, the hydraulic line can be pressurized by either the pressure of the wellbore or by the pump 170. In any event, the pressure sensor 166 is coupled to the hydraulic line and senses the pressure of the hydraulic line 164. Fourth, the tool 100 includes electronics 200 for at least one of storing, pre-processing, processing, and sending uphole to the surface circuitry 51 information related to pressure sensed by the pressure sensor 166. The electronics 200 may have additional functions including: receiving control signals from the surface circuitry 51 and for controlling the tool-setting pistons 123, 124, 125, controlling the drill motor 150, and controlling the pump 170 and the valves 168a, 168b, 172. Further, the electronics 200 may receive signals from the torque sensor 154 and/or the displacement sensor 156 for purposes of controlling the drilling operation as discussed below. It will be appreciated that given the teachings of this invention, any tool such as the Schlumberger CHDT (a trademark of Schlumberger) which includes tool-setting pistons, a drill, a hydraulic line and electronics, can be modified, if necessary, with the appropriate sensors and can have its electronics programmed or modified to accomplish the functions of tool 100 as further described below. Reference may be had to, e.g., U.S. Pat. No. 5,692,565 which is hereby incorporated by reference herein.

As will be discussed in more detail hereinafter, according to one aspect of the invention, after the tool 100 is set at a desired location in the wellbore, the drilling system 150, under control of electronics 200 and/or uphole circuitry 51 is used to drill through the casing 40 to the cement annulus 45. The probe 162 is then preferably set against the casing around the drilled hole so that it is in hydraulic contact with the drilled hole and thus in hydraulic contact with the cement annulus 45. With the probe 162 set against the casing, the packer 163 provides hydraulic isolation of the drilled hole and the probe from the wellbore when valve 168b is also shut. Alternatively, depending on the physical arrangement of the probe, it is possible that the probe could be moved into the hole in the casing and in direct contact with the cement annulus. Once set with the probe (and hydraulic line) isolated from the borehole pressure, the pressure in the probe and hydraulic line is permitted to float (as opposed to be controlled by pumps which conduct draw-down or injection of fluid), for a period of time. The pressure is monitored by the pressure sensor coupled to the hydraulic line, and based on the change of pressure measured over time, a fluid dynamic property of the cement (e.g., permeability) is calculated by the electronics 200 and/or the uphole circuitry 51. A record of the determination may be printed or shown by the recorder.

In order to understand how a determination of a fluid dynamic property of the cement may be made by monitoring the pressure in the hydraulic line connected to the probe over time, an understanding of the theoretical underpinnings of the invention is helpful. Translating into a flow problem a problem solved by H. Weber, “Ueber die besselschen functionen und ihre anwendung auf die theorie der electrischen strome”, Journal fur Math., 75:75-105 (1873) who considered the charged electrical disk potential in an infinite medium, it can be seen that the probe-pressure p_p within the probe of radius r_p, with respect to the far-field pressure is

$\begin{array}{cc}{p}_p=\frac{Q\mu }{4{\mathrm{kr}}_p}& \left(1\right)\end{array}$ when a fluid of viscosity μ is injected at rate Q into a formation of permeability k. Here, the probe area is open to flow. For all radii greater than radius r_p, i.e., for radii outside of the probe, no flow is allowed to occur.

The infinite medium results of Weber (1873) were modified by Ramakrishnan, et al. “A laboratory investigation of permeability in hemispherical flow with application to formation testers”, SPE Form. Eval., 10:99-108 (1995) and were confirmed by laboratory experiments. One of the experiments deals with the problem of a probe placed in a radially infinite medium of thickness “l”. For this problem, a small correction to the infinite medium result applies and is given by:

$\begin{array}{cc}{p}_p=\frac{Q\mu }{4{\mathrm{kr}}_p}\lfloor 1-\frac{2r_p\ln 2}{\pi l}+o\left(\frac{r_p}{l}\right)\rfloor & \left(2\right)\end{array}$ where “o” is an order indication showing the last term to be small relative to the other terms and can be ignored. This result is applicable when the boundary at “l” is kept at a constant pressure (which is normalized to zero). The boundary condition at the interface of the casing and the cement (r≧r_p, z=0, see FIG. 2) is the same as in the case of the cement constituting an infinite medium. As will be discussed hereinafter, where the cement is drilled such that the probe is effectively in contact with the cement at a location inside the cement (i.e., z>0), the flowing area for the flow from the cement into the probe increases. Hence the mixed boundary conditions of the problem need to be modified and a correction term to the original probe pressure solution is required for accuracy.

Turning now to the tool in the wellbore, before the probe is isolated from the wellbore, it may be assumed that the fluid pressure in the tool flowline is p_w which is the wellbore pressure at the depth of the tool. In a cased hole, the wellbore fluid may be assumed to be clean brine, and the fluid in the hydraulic probe line is assumed to contain the same brine, although the probe line may be loaded with a different fluid, if desired. At the moment the probe is set (time t=0), the pressure of the fluid in the tool is p_w, and the tool fluid line is isolated, e.g., through the use of one or more valves, except for any leak through the cement into or from the formation. This arrangement amounts to a complicated boundary value problem of mixed nature. See, Wilkinson and Hammond, “A perturbation method for mixed boundary-value problems in pressure transient testing”, Trans. Porous Media, 5:609-636 (1990). The pressure at the open cylinder probe face and in the flow line is uniform, and flow may occur into and out of it with little frictional resistance in the tool flow line itself, and is controlled entirely by the permeability of the cement and the formation. The pressure inside the tool (probe) is equilibrated on a fast time scale, because hydraulic constrictions inside the tool are negligible compared to the resistance at the pore throats of the cement or the formation. Due to the casing, no fluid communication to the cement occurs outside the probe interface.

Although the mixed boundary problem is arguably unsolvable, approximations may be made to make the problem solvable. First, it may be assumed that the cement permeability is orders of magnitude smaller than the formation permeability, and thus the ratio of the cement to formation permeability approaches zero. By ignoring the formation permeability, pressure from the far-field is imposed at the cement-formation interface; i.e., on a short enough time scale compared to the overall transient for pressure in the tool to decay through the cement, pressure dissipation to infinity occurs. Without loss of generality, the pressure gradient in the formation can be put to be zero. In addition, for purposes of simplicity of discussion, the undisturbed formation pressure in the formulation can be subtracted in all cases to reduce the formation pressure to zero in the equations. This also means that the probe pressure calculated is normalized as the difference between the actual probe pressure and the undisturbed formation pressure. By neglecting formation resistance (i.e., by setting the pressure gradient in the formation to zero), it should be noted that the computed cement permeability is likely to be slightly smaller than its true value.

In addition, extensive work has been carried out with regard to the influence of the wellbore curvature in terms of a small parameter r_p/r_w (the ratio of the probe radius to the wellbore radius). This ratio is usually small, about 0.05. Since the ratio is small, the wellbore may be treated as a plane from the perspective of the probe. Thus, the pressure drop obtained is correct to a leading order, since it is dominated by gradients near the wellbore and the curvature of the wellbore does not strongly influence the observed steady-state pressures.

Now a second approximation may be made to help solve the mixed boundary problem. There is a time scale relevant to pressure propagation through the cement. If the cement thickness is l_c (see FIG. 2), this time scale is t_c=φμcl_c²/k_c, where φ is the porosity of the cement, k_c is the cement permeability, and c is the compressibility of the fluid saturating the pore space of the cement annulus. Within this time scale, however, pressure at the probe is well established because much of the pressure drop occurs within a few probe radii. Since the cement thickness is several probe radii, it is convenient to consider a hemispherical pore volume of V_c=φ⅔πl_c³ of the cement adjacent the probe for comparison with the volume of the tool V_t to estimate the influence of storage. Tool fluid volume connected to the probe is a few hundred mL, where V_c is measured in tens of mL. To leading order, the pressure experienced at the probe is as though a steady flow has been established in the cement region. The transient seen by the probe would be expected to be dominated by storage, with the formation being in a (pseudo) steady-state.

With the pressure in the cement region assumed to be at a steady-state, and with the curvature of the wellbore being small enough to be neglected, and with the probe assumed to be set in close proximity to the inner radius of the cement just past the casing, the following equations apply:

$\begin{array}{cc}\frac{{\partial }^{2}p}{\partial z^2}+\frac{1}{r}\frac{\partial }{\partial r}\left(r\frac{\partial p}{\partial r}\right)=0& \left(3\right)\\ p=0,\forall r,z=l_c& \left(4\right)\\ \frac{\partial p}{\partial z}=0,z=0,r>r_p& \left(5\right)\end{array}$ where, as indicated in FIG. 2, z is the coordinate projecting into the formation, r is the radial distance from the center of the probe along the probe face, r_p is the radius of the probe. As will be appreciated, equation (3) is a mass conservation equation which balances fluid movement in the z and r directions. Equation (3) is not a function of time because, as set forth above, it is assumed that the cement is at a steady state. Equation (4) dictates that at the cement-formation interface (i.e., when z equals the cement thickness l_c), the difference between the formation pressure and the pressure found at the interface (i.e., p is the normalized pressure) is zero. Equation (5) dictates that at the cement-casing interface beyond the location of the probe, there is no pressure gradient in the cement which satisfies that there is no flow exchange between the cement and the wellbore. Additionally, where the cement is drilled to a depth of l_p (see FIG. 2), conditions for flow at the probe can be defined according to:

$\begin{array}{cc}p=p_p\left(r\le r_p,z=l_p;r=r_p,z<l_p\right)\mathrm{and}& \left(6\right)\\ -2\pi \frac{k}{\mu }{\int }_0^{r_p}r\frac{\partial p}{\partial z}\left(r;l_p\right)dr-2\pi r_p\frac{k}{\mu }{\int }_0^{l_p}\frac{\partial p}{\partial r}\left(r_p;z\right)dr=Q& \left(7\right)\end{array}$ where Q is the total flow into the probe,

$-\frac{k}{\mu }\frac{\partial p}{\partial z}$ is the horizontal flux through the cement to the probe, and

$-\frac{k}{\mu }\frac{\partial p}{\partial z}$ is the circumferential flux (flux through the curved surface) through the cement to the probe. It is noted that when the cement is drilled, the probe preferably is not pushed into the casing or cement because when the probe is hydraulically face-sealed around the drilled hole, the drilled hole is effectively an extension of the probe and thus the probe may be considered to be located in the cement with the flow into the probe occurring through both the front face and the circumferential surface of the probe. However, even if the probe is pushed into the cement, if the circumferential surface of the drill hole in the cement and the probe have a hydraulically conducting gap between them, equations (6) and (7) will still apply with the hole being considered an extension of the probe, i,e., the curved surface of the probe effectively allows fluid to flow radially inward. Equation (6) states that for the drilled surface at all locations, the normalized pressure p is uniform and equal to the normalized probe pressure within the tool (i.e., the actual probe pressure minus the formation pressure). Equation (7) states that the total flow Q seen by the probe is the sum of the integrated fluxes in two directions which relates to the fluid pressure gradient within the cement, the permeability of the cement, and the viscosity of the fluid. It will be appreciated by those skilled in the art, that when l_p=0 (i.e., at the casing/cement interface), equation (7) reduces to

$2\pi {\int }_0^{r_p}\mathrm{rq}\left(r\right)dr=Q$ where the horizontal flux into the probe

$q\left(r\right)=-\frac{k}{\mu }\frac{\partial p}{\partial z}.$

When the wellbore pressure to which the probe is initially set is larger than the formation fluid pressure, fluid leaks from the tool into the formation via the probe and through the cement. When the formation fluid pressure is larger than the probe pressure, fluid leaks from the formation via the cement into the tool. For purposes of discussion herein, it will be assumed that the wellbore pressure (initial probe pressure) is larger, although the arrangement will work just as well for the opposite case with appropriate signs being reversed. When the pressures are different, and the initial pressure in the probe is p_w, the leak rate is governed by the pressure difference p_w, the differential equations and boundary conditions set forth in equations (3) through (7) above, and the (de)compression of the fluid in the tool. Understandably, because the borehole fluid is of low compressibility, the fractional volumetric change will be very small. For example, if the compressibility of the fluid is 10⁻⁹ m²N⁻¹, and the difference in the pressure is 6 MPa, the fractional volume change would be 0.006 (0.6%) until equilibrium is reached. For a storage volume of 200 mL, a volume change of 1.2 mL would occur over the entire test. This volume can flow through a cement having a permeability of 1 μD at a time scale of hours. As is described hereinafter, by measuring the pressure change over a period of minutes, a permeability estimate can be obtained by fitting the obtained data to a curve.

As previously indicated, the fluid in the tool equilibrates pressure on a time scale which is much shorter than the overall pressure decay dictated by the low permeabilities of the cement annulus. Therefore, the fluid pressure at the probe p_p is the same as the fluid pressure measured in the tool p_t. If all properties of the fluid within the tool are shown with subscript t, the volume denoted by V_t, and the net flow out of the tool is Q, a mass balance (mass conservation) equation for the fluid in the tool may be written according to:

$\begin{array}{cc}{V}_t\frac{d{\rho }_t}{dt}+{\rho }_t\frac{d{V}_t}{dt}=-{\rho }_{t}Q& \left(8\right)\end{array}$ where ρ_t is the density of the fluid in the tool. The fluid volume of the system V_t coupled to the probe is fixed. Using the isothermal equation of state for a fluid of small compressibility

$\begin{array}{cc}\frac{1}{\rho }\frac{\partial \rho }{\partial p}=c& \left(9\right)\end{array}$ where c is the compressibility (c_t being the compressibility for the tool fluid), and substituting equation (9) into equation (8) for a fixed V_t yields:

$\begin{array}{cc}{V}_t{c}_t\frac{d{p}_p}{dt}=-Q.& \left(10\right)\end{array}$ Equation (10) states that the new flow of fluid out of the tool is equal to the decompression volume of the hydraulic system of the tool.

It has already been suggested by equation (2) that the probe pressure and the flow rate from the tool are related when the formation pressure is fixed. Replacing l with the thickness of the cement l_c, and replacing the permeability k with the permeability of the cement k_c, equation (2) can be rewritten and revised to the order (r_p/l_c) according to:

$\begin{array}{cc}{p}_p=\frac{Q\mu }{4k_c{r}_p}\left[1-\frac{2r_p\ln 2}{\pi l_c}\right].& \left(11\right)\end{array}$ As previously discussed, when the cement annulus is drilled such that the probe is effectively in contact with a particular depth inside the cement as opposed to just the interface between the casing and the cement, a correction term is required for equation (11). In particular, for a fixed flow Q, a numerical solution can be generated for the steady state pressure at the probe p_p for any drilled depth l_p. Therefore, it is possible to define a correction term and modify equation (11) to

$\begin{array}{cc}{p}_p=\frac{Q\mu }{4k_c{r}_p}\left[1-\frac{2r_p\ln 2}{\pi l_c}-F\left(\frac{l_p}{l_c};\frac{r_p}{l_c}\right)\right]& \left(12\right)\end{array}$ where l_p/l_c represents the percentage through the cement annulus that has been drilled. Equation (12) takes dimensionless analysis into account by representing a dimensionless correction term F as a function of two possible dimensionless groups l_p/l_c and r_p/l_c. By rearranging equation (12) and using equation (11), the correction term F can be defined according to

$\begin{array}{cc}F\left(\frac{l_p}{l_c};\frac{r_p}{l_c}\right)=\left(1-\frac{p_p}{p_p^0}\right)\left(1-\frac{2r_p\ln 2}{\pi l_c}\right)& \left(13\right)\end{array}$ where p_p is the probe pressure and p⁰_p is the probe pressure for zero drill bit penetration; i.e., at the casing-cement interface when l_p/l_c=0 (see Equation 11). It will be appreciated that for zero drill bit penetration, p_p/p⁰_p=1, the function F reduces to zero as it should. Also, when l_p=l_c, the probe pressure will be equal to the formation pressure, p_p/p⁰_p=0, and the function F reduces to a value that causes the probe pressure p_p of equation (12) to equal 0 as it should.

In practice, l_p/l_c may vary from 0 to 1. Typically, values for r_p/l_c will be between 0.1 and 0.3. For any given tool, r_p is fixed. For a given depth and azimuth of the well test, the thickness of the cemented annulus l_c is also fixed. Hence, it is desirable to investigate and appropriately quantify the correction term F as a function of l_p/l_c for a fixed value of r_p/l_c. In order to do this, it should be appreciated that the problem may be solved numerically, e.g., by finite-difference in 2D cylindrical coordinates. In other words, for a fixed flow Q out of the tool flowline, through the probe, and into the cement, a numerical solution can be generated for the steady state pressure at the probe p_p for any probe geometry (i.e., for a given probe radius r_p and probe penetration l_p for any cement thickness l_c). While there are many ways to numerically model this problem, the result should be the same for the value of the probe pressure p_p for fixed Q, r_p, l_p, k, μ and l_c. Using a numerical code, probe pressure values are calculated, and equation (13) is used to generate values of F. The values of F can be generated for a range of l_p/l_c and r_p/l_c as shown in FIG. 3. FIG. 3 illustrates that when the drill bit penetrates even a small amount into the cement annulus (e.g., 10% of the way; l_p/l_c=0.1), the correction term F is significant since it is larger than the second term in the brackets of equation (12). FIG. 3 also illustrates that at 20% penetration into the cement annulus, depending upon the ratio of the probe radius to the cement thickness, the correction term (which for the ratios shown is between 0.37 and 0.60) will typically well exceed the second term in the brackets of equation (12) (which for the ratios shown is between 0.13 and 0.04).

It will be appreciated that equation (12) may be rewritten to solve for Q as follows:

$\begin{array}{cc}Q=p_p\left(\frac{4{\mathrm{kr}}_p}{\mu }\right)\frac{1}{1-\frac{2\ln 2}{\pi }\frac{r_p}{l_c}-F}.& \left(14\right)\end{array}$ Substituting equation (10) into equation (14) for Q yields:

$\begin{array}{cc}\frac{d{p}_p}{dt}=-\frac{p_p}{V_t{c}_t}\left(\frac{4k_c{r}_p}{\mu }\right)\left(\frac{1}{1-\frac{2\ln 2}{\pi }\frac{r_p}{l_c}-F}\right)& \left(15\right)\end{array}$ the solution of which gives rise to an exponential decay to formation pressurep_p=p_wexp(−t/τ)  (16)where τ is the relaxation time constant of the pressure in the probe (hydraulic line) of the tool. Equation (16) suggests that the normalized probe pressure is equal to the normalized initial probe (wellbore) pressure p_w (i.e., the difference in pressure between the initial probe (wellbore) pressure and the formation pressure) times the exponential decay term. From Equations (15) and (16), the relaxation time constant τ of the pressure in the probe can then be determined as

$\begin{array}{cc}\tau =V_t{c}_t\frac{\mu }{4k_c{r}_p}\left[1-\frac{2\ln 2}{\pi }\frac{r_p}{l_c}-F\left(\frac{l_p}{l_c};\frac{r_p}{l_c}\right)\right].& \left(17\right)\end{array}$ Rearranging equation (17) yields:

$\begin{array}{cc}{k}_c=V_t{c}_t\frac{\mu }{4\tau r_p}\left[1-\frac{2\ln 2}{\pi }\frac{r_p}{l_c}-F\left(\frac{l_p}{l_c};\frac{r_p}{l_c}\right)\right].& \left(18\right)\end{array}$

From equation (18) it is seen that the permeability of the cement annulus surrounding the casing can be calculated provided certain quantities are known, estimated, or determined. In particular, the volume of the hydraulic line of the tool V_t and the radius of the probe r_p are both known. The viscosity of the fluid μ in the hydraulic line of the tool is either known, easily estimated, or easily determined or calculated. The thickness of the cement l_c is also either known or can be estimated or determined from acoustic logs known in the art. The compressibility of the fluid c_t in the hydraulic line of the tool is either known or can be estimated or determined as will be discussed hereinafter. In addition, the location of the probe face (or alternatively, the radial drilling distance into the cement) l_p is known or can be estimated, and the correction function F can be estimated (e.g., from a table, chart, or graph containing the information of FIG. 3). Finally, the relaxation time constant τ of the pressure in the hydraulic line of the tool can be found as discussed hereinafter by placing the hydraulic probe of the tool against or in the cement and measuring the pressure decay.

According to one aspect of the invention, the compressibility of the fluid c_t in the hydraulic line of the tool is determined by making an in situ compressibility measurement. More particularly, an experiment is conducted on the hydraulic line of the tool whereby a known volume of expansion is imposed on the fixed amount of fluid in the system, and the change in flow-line pressure is detected by the pressure sensor. The compressibility of the fluid is then calculated according to

$\begin{array}{cc}{c}_t=-\frac{1}{V}\frac{\Delta V}{\Delta p}& \left(19\right)\end{array}$ where V is the volume of the flow-line, ΔV is the expansion volume added to the flow line, and Δp is the change in pressure. Alternatively, a known amount of fluid can be forced into a fixed volume area, and the change in pressure measured. In other cases, the compressibility of the fluid may already be known, so no test is required.

According to another aspect of the invention, prior to placing the probe in hydraulic contact with the cement annulus, the casing around which the cement annulus is located is drilled. The drilling is preferably conducted according to steps shown in FIG. 4. Thus, at 200, the depth in the wellbore at which the test is to be conducted is selected. The depth is selected after reviewing logs such as acoustic logs (e.g., cement bond logs), which might indicate the condition of the cement. Additionally, corrosion logs provide information about the state of the steel casing. Such logs are well known in the art. It is noted that poor bonding is usually an indication of poor cement, and it is desirable to measure cement permeability in such zones and also in those zones where the cement appears robust. A robust cement may still have unacceptably high permeability e.g., due to microcracks. Generally, it is desirable to have at least robust casing and cement zones above those where the cement is found to be inadequate. If robust zones are not found, remedial action could be indicated. Regardless, at 210, the thickness of the cement annulus is identified, typically via acoustic logs or from known casing size and drill bit size. Then at 220, the casing is preferably evaluated so that the cement-casing interface can be located. The true casing thickness l_s (see FIG. 2) is defined by l_s≈l_s0−l_r, where l_s0 is the initial thickness of the steel, and l_r is the reduction in the thickness (ostensibly due to corrosion). At 240, the tool is used to drill into the casing and the penetration depth of the drill bit is monitored by an appropriate sensor. The tool is used to drill to a penetration depth of l=l_s+l_p where 0≦l_p≦l_c. In some cases it may be desirable to eventually drill into the formation in order to measure formation pressure.

Once the tool has been located at a desired location in the wellbore and the casing has been drilled up to or into the cement, the probe pressure in the probe (hydraulic line of the tool) is set at step 250 to a determined value, e.g., the pressure of the wellbore, and subsequently brought in hydraulic contact with the cement annulus at 250. With an elastomeric packer 163 around the probe, the hydraulic line is isolated from the borehole typically by closing a valve 168b connecting the hydraulic line to the borehole. Now, with the probe in hydraulic contact with the cement annulus only, and with no action taken (i.e., the process is “passive” as no piston or pump is used to exert a draw-down pressure or injection pressure), the pressure in the hydraulic line is allowed to float so that it decays (or grows) slowly toward the formation pressure. The pressure decay is measured at 270 over time by the pressure sensor of the tool. If the pressure does not decay (e.g., because the formation pressure and the pressure in the hydraulic line are the same), the probe pressure may be increased or decreased and then let float to permit the probe pressure to be measured for a decay or growth. Using the pressure decay data, the relaxation time constant τ and optionally the starting probe pressure and formation pressures are found using a suitably programmed processor (such as a computer, microprocessor or a DSP) via a best fit analysis 280a (as discussed below) and using the correction function F determined at 280b based on the values r_p/l_c and l_p/l_c. Once the relaxation time constant is calculated, the processor estimates the permeability of the cement at 290 according to equation (18).

According to one aspect of the invention, testing can continue at 295 at that borehole depth. Testing continues by drilling at 240 to a new monitored penetration depth in the cement and preferably resetting the probe at 250 by resetting the pressure in the probe to the borehole pressure (although it could be maintained at the pressure reached at the end of the previous test). Then at 270, the pressure in the hydraulic line is allowed to float and the pressure decay is measured over time by the pressure sensor of the tool, as before. The procedure continues by conducting a best fit analysis 280a and using the correction function F selected at 280b (now based on the new l_p as monitored by the appropriate sensor) in order to determine the permeability of the cement at 290 according to equation (18). It is noted that the permeability found at the new location in the cement may be the same, or might differ from the previous determination. Regardless, testing can continue at 295, or be terminated at 300. Generally, it is desirable to avoid drilling completely through the cement and into the formation, unless there is a need to know precise formation pressure. Thus, at 295, the location of the probe face can be compared to the location of the cement/formation interface in order to make a determination of whether to discontinue testing at that location. By way of example, if (l_c−l_p)/r_p≧2, testing might continue. However, as the distance between the probe face and the cement/formation interface gets to be about twice the radius of the probe, it might be advisable to terminate testing to avoid the possibility of drilling into the formation. It is noted that as many tests as desired may be conducted in the cement, although since each test takes time, no more than a few tests (e.g., four) at a single location would be conducted. Where multiple tests are run, a radial cement permeability profile (i.e., the permeability at different penetration depths into the cement at the same azimuth) can be generated as seen in FIG. 5 where values for cement permeability are shown as a function of penetration depth of the drilling into the cement. The profile may be provided in a viewable format such as on paper or on a screen. A large change in the inferred permeability at a particular l_p is suggestive of internal fractures in the cement. Thus, FIG. 5, which shows a jump in estimated permeability of the cement from the measurement made at 1.0 cm into the cement to the estimated permeability from the measurement made at 1.5 cm into the cement might suggest a possible microcrack or other anomaly in the cement. Conversely, a consistent permeability estimate is indicative of the cement homogeneity.

A determination of the suitability for storing carbon dioxide below or at that location in the formation may then be made by comparing the permeability to a threshold value at 350. If an internal fracture or other anomaly is identified, it is preferred to test a higher elevation to investigate the presence of large vertically conductive fractures. A threshold permeability value of 5 μD or less is preferable, although higher or lower thresholds could be utilized. The entire procedure may then be repeated at other locations in the wellbore if desired in order to obtain a log or a chart of the permeability of the cement at different depths in the wellbore (see e.g., FIG. 7) and/or make determinations as to the suitability of storing carbon dioxide in the formation at different depths of the formation. Where the radial profile of cement permeability suggests inhomogeneity, the information for that depth may be left off the log, or multiple values may be entered, or the largest value, an average value, or some other value may be entered with appropriate notation. The log or chart is provided in a viewable format such as on paper or on a screen. Also, if desired, after conducting a test at any location, the casing may be sealed (i.e., the hole repaired) as is known in the art.

The fitting of the relaxation time constant and the probe and formation pressures to the data for purposes of calculating the relaxation time constant and then the permeability can be understood as follows. The normalized pressure of the probe (p_p) is defined as the true pressure in the probe (p_p*) minus the true pressure of the formation p_f*:p_p=p_p*−p_f*.  (20)The pressure decay may then be represented by restating equation (16) in light of equation (20) according to:

$\begin{array}{cc}{p}_p^{*}=p_f^{*}+\left(p_w^{*}-p_f^{*}\right)e^{\frac{-t}{\tau }}& \left(21\right)\end{array}$ where p_w* is the true wellbore pressure.

To demonstrate how the data can be used to find the relaxation time, a synthetic pressure decay data set using equation (21) was generated with the following values: p_f*=100 bar, p_w*=110 bar, and the relaxation time τ=18,000 seconds (5 hours). Zero mean Gaussian noise with a standard deviation of 0.025 bar was added. FIG. 6 shows the pressure as would be measured by the pressure sensor in the tool. After five hours (18,000 seconds), the probe pressure is seen to approach 103.7 bar which indicates a 63% decay (i.e., which defines the relaxation time constant) towards the formation pressure.

It is assumed that the probe is set and the pressure decay is measured, and the tool is withdrawn from contact with the cement annulus before the formation pressure is reached. In this situation, the formation pressure p_f* is unknown. Thus, equation (21) should be fit to the data with at least two unknowns: p_f* and τ. While the wellbore (probe) pressure is generally known, it was shown in the previously incorporated parent application that in fact it is best to fit equation (21) to the data assuming that the wellbore pressure is not known. Likewise, while it is possible to drill into the formation to obtain the formation pressure, it was shown in the previously incorporated parent application that in fact it is best to fit equation (21) to the data assuming that the formation pressure is not known.

In accord with another aspect of the invention, the probe may be withdrawn from fluid contact with the cement annulus before the expected relaxation time. Again, as set forth in the previously incorporated parent application, even in this situation, a three parameter fit is preferred unless extremely accurate estimates of both the wellbore pressure and formation pressure are available. It is believed that a test duration of approximately half-hour will be sufficient in most cases.

According to another aspect of the invention, and as set forth in the previously incorporated parent application, it is possible to test for the convergence of τ prior to terminating the test. In particular, the probe of the tool may be in contact with the cement annulus for a time period of T₁ and the data may be fit to equation (21) to obtain a first determination of a relaxation time constant τ=τ₁ along with its variation range. The test may then continue until time T₂. The data between T₁ and T₂ and between t=0 and T₂ may then be fit to equation (21) in order to obtain two more values τ₁₂ and τ₂ along with their ranges. All three relaxation time constants may then be compared to facilitate a decision as to whether to terminate or prolong the test. Thus, for example, if the relaxation time constant is converging, a decision can be made to terminate the test. In addition or alternatively, the formation pressure estimates can be analyzed to determine whether they are converging in order to determine whether to terminate or prolong a test.

There have been described and illustrated herein several embodiments of a tool and a method that determine the permeability of a cement annulus and/or the radial homogenized permeability profile of the annulus located between the casing and the formation. While particular embodiments of the invention have been described, it is not intended that the invention be limited thereto, as it is intended that the invention be as broad in scope as the art will allow and that the specification be read likewise. Thus, while a particular arrangement of a probe and drill were described, other arrangements could be utilized. In addition, with respect to the correction term, while certain ranges were shown for the ratio of the probe radius to the cement annulus thickness, it will be appreciated that other ratios could be utilized. Further, while it is preferred that the probe be located in the casing and around the drilled hole for testing, if desired, the probe can actually be located within the drilled hole in the cement annulus. It will therefore be appreciated by those skilled in the art that yet other modifications could be made to the provided invention without deviating from its spirit and scope as claimed.

Claims

1. A method of determining an estimate of the permeability of a cement annulus in a formation traversed by a wellbore having a casing around which the cement annulus is located, using a tool having a hydraulic probe and a pressure sensor, comprising: a) locating the tool at a depth inside the wellbore;b) drilling a hole through the casing and partially into the cement annulus;c) locating the hydraulic probe in hydraulic contact with the cement annulus;d) using the pressure sensor to measure the pressure in the hydraulic probe over a period of time in order to obtain pressure data;e) finding a relaxation time constant estimate of the pressure data by fitting the pressure data to an exponential curve which is a function of the relaxation time constant, and a difference between a starting pressure in the hydraulic probe and the formation pressure; andf) determining an estimate of the permeability of the cement annulus according to an equation which relates said permeability of the cement annulus to said relaxation time constant estimate.

2. A method according to claim 1, wherein: said relaxation time constant estimate is determined according to

3. A method according to claim 1, wherein: said equation is

4. A method according to claim 3, wherein: said correction term function

5. A method according to claim 3, further comprising: determining said compressibility of the fluid in the tool by imposing a known volume of expansion on the fixed amount of fluid in the system, sensing a resulting change in flow-line pressure, and calculating compressibility according to

6. A method according to claim 1, further comprising: g) drilling further into the cement annulus to a new radial depth, and repeating steps c) through f) with the new radial depth to find an estimate of permeability of the cement annulus at the new radial depth.

7. A method according to claim 6, further comprising: repeating step g) and generating a radial profile of estimated cement annulus permeability.

8. A method according to claim 1, wherein: said fitting comprises permitting said relaxation time constant estimate, said pressure in the hydraulic probe and said formation pressure to be variables which are varied to find a best fit.

9. A method according to claim 1, wherein: said fitting comprises fixing at least one of said pressures in finding said relaxation time constant estimate.

10. A method according to claim 1, further comprising: comparing said determined permeability estimate to a threshold value for the purpose of determining the suitability of storing carbon dioxide in the formation at or below that depth.

11. A method according to claim 1, wherein: said locating the tool includes selecting said depth by reviewing cement and casing quality logs.

12. A method according to claim 1, wherein: said period of time is less than said relaxation time constant estimate.

13. A method according to claim 1, further comprising: generating a viewable log or chart showing at least one permeability estimate or indication of suitability for storing carbon dioxide at or below at least one depth in the formation.

14. A system for determining an estimate of the permeability of a cement annulus in a formation traversed by a wellbore having a casing, comprising: a tool having a hydraulic probe, a pressure sensor in hydraulic contact with the hydraulic probe and sensing pressure in the hydraulic probe, a drill capable of drilling the casing and cement annulus, and means for hydraulically isolating said hydraulic probe in hydraulic contact with the cement annulus from the wellbore; andprocessing means coupled to said pressure sensor, said processing means for obtaining pressure measurement data obtained by said pressure sensor over a period of time while said hydraulic probe is hydraulically isolated from the wellbore and in hydraulic contact with the cement annulus, for finding a relaxation time constant estimate of the pressure data by fitting the pressure data to an exponential curve which is parameterized by the relaxation time constant, and a difference between a starting pressure in the hydraulic probe and the formation pressure, and for determining an estimate of the permeability of the cement annulus according to an equation which relates said permeability of the cement annulus to said relaxation time constant estimate.

15. A system according to claim 14, wherein: said processing means is at least partially located separately from said tool.

16. A system according to claim 14, further comprising: means coupled to said processing means for generating a viewable log or table of at least one estimate of the permeability of the cement annulus as a function of depth in the wellbore or formation.

17. A system according to claim 14, wherein: said processing means for finding said relaxation time constant estimate finds said relaxation time constant according to

18. A system according to claim 14, wherein: said equation is

19. A system according to claim 18, wherein: said correction term function is obtained from a table, chart, or graph.

20. A system according to claim 14, further comprising: means coupled to said processing means for generating a viewable log or table of at least one estimate of the permeability of the cement annulus as a function of radial depth of said cement annulus.