Patent Application
20090164128
1. Technical Field
The present disclosure generally relates to wellbore tools and in particular to methods and apparatus for estimating formation properties.
2. Background Information
Oil and gas wells have been drilled at depths ranging from a few thousand feet to as deep as five miles. A large portion of the current drilling activity involves directional drilling that includes drilling boreholes deviated from vertical by a few degrees to horizontal boreholes, to increase the hydrocarbon production from earth formations.
Information about the subterranean formations traversed by the borehole may be obtained by any number of techniques. Techniques used to obtain formation information include obtaining one or more core samples of the subterranean formations and obtaining fluid samples produced from the subterranean formations these samplings are collectively referred to herein as formation sampling. Core samples are often retrieved from the borehole and tested in a rig-site or remote laboratory to determine properties of the core sample, which properties are used to estimate formation properties. Modern fluid sampling includes various downhole tests and sometimes fluid samples are retrieved for surface laboratory testing.
Laboratory tests suffer in that in-situ conditions must be recreated using laboratory test fixtures in order to obtain meaningful test results. These recreated conditions may not accurately reflect actual in-situ conditions and the core and fluid samples may have undergone irreversible changes in transit from the downhole location to the surface laboratory. Furthermore, downhole fluid tests do not provide information relating to formation direction and other rock properties.
The following presents a general summary of several aspects of the disclosure in order to provide a basic understanding of at least some aspects of the disclosure. This summary is not an extensive overview of the disclosure. It is not intended to identify key or critical elements of the disclosure or to delineate the scope of the claims. The following summary merely presents some concepts of the disclosure in a general form as a prelude to the more detailed description that follows.
Disclosed is an apparatus for estimating a property. The apparatus may include a formation evaluation tool conveyable to a formation evaluation location, and a formation strength test device having a member that engages a borehole wall substantially adjacent the formation evaluation location for estimating the property.
In one aspect, an apparatus for estimating a property may include a carrier conveyable in a borehole to a formation. Two or more packers may be used to isolate an annular zone about the carrier, and a formation evaluation tool may be disposed on the carrier, the formation evaluation tool adapted to evaluate the formation at a formation evaluation location. A formation strength test device may be coupled to the carrier and adapted to provide information indicative of the property, the property relating to the isolated annular zone substantially adjacent the formation evaluation location.
Also disclosed is a method for estimating a property. The method includes evaluating a formation at a formation evaluation location using a formation evaluation tool, and estimating the property at least in part by engaging a borehole wall substantially adjacent the formation evaluation location with a formation strength test device.
For a detailed understanding of the present disclosure, reference should be made to the following detailed description of the several non-limiting embodiments, taken in conjunction with the accompanying drawings, in which like elements have been given like numerals and wherein:
With reference to
A string of logging tools, or simply, tool string 106 is shown lowered into the well borehole 102 by an armored electrical cable 108. The cable 108 can be spooled and unspooled from a winch or drum 110. The tool string 106 may be configured to convey information signals to surface equipment 112 by an electrical conductor and/or an optical fiber (not shown) forming part of the cable 108. The surface equipment 112 can include one part of a telemetry system 114 for communicating control signals and data signals to the tool string 106 and may further include a computer 116. The computer can also include a data recorder 118 for recording measurements made by the tool string 106 sensors and transmitted to the surface equipment 112.
The exemplary tool string 106 may be centered within the well borehole 102 by a top centralizer 120a and a bottom centralizer 120b attached to the tool string 106 at axially spaced apart locations. The centralizers 120a, 120b can be of types known in the art such as bowsprings or inflatable packers. In other non-limiting examples, the tool string 106 may be forced to a side of the borehole 102 using one or more extendable members.
The tool string 106 of
The electrical power section 122 receives or generates, depending on the particular tool configuration, electrical power for the tool string 106. In the case of a wireline configuration as shown in this example, the electrical power section 122 may include a power swivel that is connected to the wireline power cable 108. In the case of a while-drilling tool, the electrical power section 122 may include a power generating device such as a mud turbine generator, a battery module or other suitable downhole electrical power generating device. In some examples wireline tools may include power generating devices and while-drilling tools may utilize wired pipes for receiving electrical power and communication signals from the surface. The electrical power section 122 may be electrically coupled to any number of downhole tools and to any of the components in the tool string 106 requiring electrical power. The electrical power section 122 in the example shown provides electrical power to the electronics section 124.
With reference to
In wireline applications, the electronics section 124 may be limited to transmitter and receiver circuits to convey information to a surface controller and to receive information from the surface controller via a wireline communication cable. In the example shown, the processor system 200 further includes a memory unit 204 for storing programs and information processed using the processor 202. Transmitter and receiver circuits 206 are included for transmitting and receiving information to and from the tool string 106. Signal conditioning circuits 208 and any other electrical component suitable for the tool string 106 may be housed within the electronics section 124. A power bus 210 may be used to communicate electrical power from the electrical power section 122 to the several components and circuits housed within the electronics section 124. A data bus 212 may be used to communicate information between the mandrel section 128 and the processing system 200 and between the processing system 200 and the surface computer 116 and recorder 118. The electrical power section 122 and electronics section 124 may be used to provide power and control information to the mechanical power section 126 where the mechanical power section 126 includes electro-mechanical devices.
In the non-limiting example of
In several non-limiting examples, the mandrel section 128 may utilize mechanical power from the mechanical power section 126 and may also receive electrical power from the electrical power section 126. Control of the mandrel section 128 and of devices on the mandrel section 128 may be provided by the electronics section 124 or by a controller disposed on the mandrel section 128. In some embodiments, the power and control may be used for orienting the mandrel section 128 within the well borehole. The mandrel section 128 can be configured as a rotating sub that rotates about and with respect to the longitudinal axis of the tool string 106. Bearing couplings 132 and drive mechanism 134 may be used to rotate the mandrel section 128. In other examples, the mandrel section 128 may be oriented by rotating the tool string 106 and mandrel section 128 together. The electrical power from the electrical power section 122, control electronics in the electronics section 124, and mechanical power from the mechanical power section 126 may be in communication with the mandrel section 128 to power and control the formation strength test device 130 and with the formation sampling and test tool 138.
Referring now to
Each of the pistons in the example shown includes a wall-engaging end 310, 312, 314 having a predetermined surface shape and area. The exemplary formation strength test device 130 includes one piston 300 having a wall-engaging end 310 that has large surface area with at least one radius of curvature about equal to the borehole radius. A second of the extendable pistons 302 includes a wall-engaging end 312 with a surface area that is smaller than the end of the first piston 300, and the third of the extendable pistons 304 includes a wall-engaging end 314 with a surface area that is smaller than either of the first and second pistons. The end of the third piston 304 may include a pointed or chisel-shaped end to increase the force per unit area. Information relating to the speed of extension, force applied by the respective piston, distance of piston travel and the like may be monitored by suitable sensors 316 associated with the respective piston. Information measured by the sensors 316 may be transmitted to the electronics section 124 via the data bus 212 for processing.
Continuing now with the exemplary tool of
The formation evaluation tool 138 may further include one or more fluid test devices 150 to test fluid samples received by the formation evaluation tool 138. The test devices 150 may include any number of transducers 152 and sensors for measuring characteristics of the fluid received by the tool. Non-limiting examples of suitable transducers 152 include optical sensors, NMR sensors, acoustic sensors, resistivity sensors, capacitance sensors, pressure sensors, temperature sensors, and any other transducer useful in characterizing fluid sampled by the tool 138. Furthermore, one or more of the transducers 152 may be associated with the fluid conduit leading from the extendable probe 140 to measure fluid characteristics of fluid in the conduit prior to directing the fluid to the chambers 142. In this manner and using not-shown conduits leading back to the borehole 102, fluid entering the probe 140 may be flushed until the fluid in the conduit leading to the chambers is substantially free of borehole fluid. Determination of fluid content may be accomplished by transmitting output signals from the transducers 152 to a suitable processor for estimating fluid content. In several examples, downhole signal processing may be accomplished using the electronics section 124 of the tool string 106. The electronics section 124 may include a downhole spectrometer that receives signals from optical sensors in the formation evaluation tool 138 to determine fluid content. Formation properties estimated based on the fluid content measurements may be further enhanced by an understanding of formation property measurements taken in several directions, which may be accomplished using articulated strength measurement pistons.
The formation strength test device 130 described above and shown in the exemplary views may include one or more articulated piston assemblies to move the respective pistons 300, 302, 304 in several angular directions with respect to the mandrel 128 longitudinal axis. Referring to
Continuing with
Referring now to
In several non-limiting embodiments, the packers 502 selectively expand to isolate the annular section between the packers 502. The packers 502 may be actuated by any number of actuating mechanisms. The packers may be actuated using pressurized hydraulic fluid received via the power transfer medium 306 leading from the mechanical power section 126. In other embodiments, the packers 502 may be mechanically compressed or actuated using hydraulically actuated pistons or the like. When actuated, each packer element 502 expands and sealingly engages an adjacent borehole wall area to form a fluid barrier across an annulus portion of the borehole 102. In one example, the packers 502 include flexible bladders that can deform sufficiently to maintain a sealing engagement with the formation 104 even though the mandrel 128 may not be centrally positioned in the borehole 102. The packers 502, when actuated, provide the isolated zone that reduces or prevents fluid movement into or out of the isolated zone between the packers 502.
It will be appreciated from the present disclosure that isolating a zone along the wellbore axis increases the likelihood that formation fluid can be efficiently extracted from a formation. For instance, a wellbore wall may include laminated areas that block fluid flow or fractures that prevent an effective seal from being formed by a pad pressed on the borehole wall. An isolated axial zone when used with or without an additional extendable sampling probe having a sealing pad provides a greater likelihood that a region or area having favorable flow characteristics will be captured. Thus, laminated areas or fractures will be less likely to interfere with fluid sampling. Moreover, the formation could have low permeability, which restricts the flow of fluid out of the formation. Utilizing an isolated zone can increase the flow rate of fluid into the zone and therefore reduce the time needed to obtain a pristine fluid sample. The formation fluid sampling tool 504 may include a pump that can cause the isolated zone between the packers 502 to have an environmental condition different that the environment of the regions above and below the isolated zone. In several examples, the different environmental condition may include a different pressure and/or a different fluid content.
Downhole tools such as those described above and shown in
Formation properties include several components that may be measured in-situ or estimated using in-situ measurements provided by the formation strength test tool of the present disclosure. The several components of formation properties include stress, Young's modulus, Poisson's Ratio and formation unconfined compressive strength. A short discussion of these formation properties follows.
Stress on a given sample is defined as the force acting on a surface of unit area. It is the force divided by the area as the area approaches zero. Stress has the units of force divided by area, such as pounds per square inch, or psi, kilo Pascals (kilo Newtons per square meter), kPa, MPa, etc. A given amount of force acting on a smaller area results in a higher stress, and vice versa.
The Young's modulus of a rock sample is the stiffness of the formation, defined as the amount of axial load (or stress) sufficient to make the rock sample undergo a unit amount of deformation (or strain) in the direction of load application, when deformed within its elastic limit. The higher the Young's modulus, the harder it is to deform it. It is an elastic property of the material and is usually denoted by the English alphabet E having units the same as that of stress.
The Poisson's ratio of an elastic material is also its material property that describes the amount of radial expansion when subject to an axial compressive stress (or deformation measured in a direction perpendicular to the direction of loading). Poisson's ratio is the ratio of the elastic material radial deformation (strain) to its axial deformation (strain), when deformed within its elastic limit. Rocks usually have a Poisson's ratio ranging from 0.1 to 0.4. The maximum value of Poisson's ratio is 0.5 corresponding to an incompressible material (such as water). It is denoted by the Greek letter ν (nu). Since it is a ratio, it is unitless.
The Unconfined Compressive Strength (UCS) of a material is the maximum compressive stress an element of rock can take before undergoing failure. It is usually determined in the laboratory on cylindrical cores, subjected to axial compressive stress under unconfined conditions (no lateral support or confining pressure being applied on the sides). It has the same units as that of stress (force per unit area: psi, MPa, etc.).
In-situ stresses are the stresses that exist within the surface of the earth. There are three principal (major) stresses acting on any element within the surface of the earth. The three stresses are mutually perpendicular to one another and include the vertical (overburden) stress resulting from the weight of the overlying sediments (σv), the minimum horizontal stress (σHmin) resulting from Poisson's effect, and maximum horizontal stress (σHmax) resulting from Poisson's and tectonic/thermal effects.
E=δσ
1/δε1 Equation 1
ν=−δε3/δε1 Equation 2
UCS=σmax Equation 3
In these equations, ε1=δ1/L and ε3=2*δ3/D. One may use known, calculated or measured values for the force applied, the cross-section area of the sample, the length of the unstressed sample cylinder, the vertical deformation and the radial deformation to provide estimates of E, ν and UCS. These parameters provide valuable information for determining the viability of a subterranean formation for hydrocarbon production.
In one embodiment, a formation strength test device is used to obtain formation property information 906 prior to extracting a sample 904. In another example, a formation sample is extracted 904 using a sampling tool prior to conducting a formation strength test device 906. In yet another example, the formation strength test and formation sample are conducted simultaneously.
The location of the formation strength test and the location of the formation sampling are each at the formation of interest and substantially adjacent the same location. As used herein, “substantially adjacent” is used to mean respective borehole wall areas for the formation strength test and formation sampling that may be overlapping in whole or in part, may be adjacent borehole wall areas, may include areas displaced about the circumference of the borehole wall at the formation of interest, and may include areas that are displaced axially along the borehole wall. Measurements substantially adjacent a formation sample location include measurements within a tool, measurements made in or on the borehole wall, and measurements that are affected by any interaction with the formation substantially adjacent a formation sampling location.
In one embodiment, a carrier that carries the formation strength test tool and the formation evaluation tool may be adjusted or moved within the borehole to bring the formation strength test tool and the coring tool to engage the borehole wall at the selected location. In another embodiment, a carrier that carries the formation strength test tool and the coring tool may be fixed within the borehole using one or more packers, an extendable anchor or other device that will hold the carrier at a fixed location. In the example of a fixed carrier, the formation strength test tool and the formation evaluation tool may be disposed on the carrier in fixed locations to engage the borehole wall in adjacent or slightly displaced locations on the borehole wall. In other examples, the carrier may be fixed at a location with the formation strength test tool and the formation evaluation tool being disposed on the carrier in a moveable manner to allow the formation strength test tool and the coring tool to engage the borehole wall in a common location on the borehole wall.
One example of the method includes moving a coring tool to a selected borehole wall location and cutting a core in the formation of interest without dislodging the core sample from the formation. This is accomplished by using a core tool to cut into the formation and then extracting the core bit from the formation while leaving the core sample connected to the formation. With the core sample still connected to the formation, a formation strength test tool engages the core sample. A force is applied to the core sample using the formation strength test tool. Measurements are made to determine the force applied and the piston extension distance. Core sample deformation is also measured, and the in-situ measurements are used to estimate the formation properties substantially adjacent the core sample location.
In another optional embodiment, formation analysis may include sampling or testing formation strength or stress by deforming the formation, which may include fracturing or chipping the formation, to estimate formation stress in situ. One method of estimating formation stress includes evaluating the ratio of force of deformation and area over which the force is applied to the formation. Pistons can exert the force onto the formation, the pistons can be disposed in housing that is rotatable within a wellbore that pierces the formation. The pistons can rotate about the wellbore's circumference and may be oriented at difference angles with respect to the wellbore axis or with respect to a formation dip. Rotation and tilt provides for three dimensional measurements within the wellbore. Mechanically measuring formation stress yields data useful for optimizing well drilling programs, casing design, modeling/planning development, and formation set.
The present disclosure is to be taken as illustrative rather than as limiting the scope or nature of the claims below. Numerous modifications and variations will become apparent to those skilled in the art after studying the disclosure, including use of equivalent functional and/or structural substitutes for elements described herein, use of equivalent functional couplings for couplings described herein, and/or use of equivalent functional actions for actions described herein. Such insubstantial variations are to be considered within the scope of the claims below.
The present application is a non-provisional application of U.S. provisional application 60/990,521 filed on Nov. 27, 2007, the entire specification being hereby incorporated herein by reference.
| Number | Date | Country | |
|---|---|---|---|
| 60990521 | Nov 2007 | US |
