Patent Description:
Significant improvements in oil and gas production have been provided by the use of hydraulic fracturing and horizontal drilling technologies. Further improvements have been realized with advances in data collection and analysis of that data.

One area of known excessive cost in oil and gas production is the use and maintenance of equipment in operating a well. Current wells are drilled with techniques such that a wellbore path can be established with a fair amount of accuracy. This is done with sensor devices either associated with bottom-hole assembly (BHA) during drilling and/or sensors selectively used during the wellbore drilling process. The BHA sensors collect data regarding the wellbore path, the geology that defines the wellbore, and other characteristics associated with the wellbore.

After an initial wellbore is formed and prior to extracting the hydrocarbons, modifications may be made to the wellbore to facilitate the extraction process. One modification is to line selected sections of the wellbore with a casing typically constructed with lengths of metal pipe. Where appropriate, cement may be used to support and seal selected sections of the metal pipes to maintain the integrity of the casing and prevent contaminant migration. Casings ensure that the extracted material does not contaminate environmentally sensitive strata such as water tables and the like. Casings may also be used to support downhole equipment maintained in the wellbore that facilitate the extraction process.

The wellbore is often mapped and logged for directional changes and the path of the casing generally matches the wellbore. However, reliance solely on a directional wellbore positioning map for the path of the casing is problematic. An accurate map of the wellbore is helpful when installing artificial lift equipment. The artificial lift equipment is needed in wells when there is insufficient pressure in the reservoir to lift the produced fluids to the surface. Therefore, the main goal of the artificial lift equipment is to lower production bottom-hole pressure (BHP) on the formation to obtain a high production rate form the well. Most oil wells require artificial lift at some point in the life of the field. Common artificial lift equipment includes: electrical submersible pumps (ESPs), which include a series of centrifugal submersible pumps that rotate by electrical downhole motors; progressive cavity pumps (PCPs); which are positive displacement pumps that use an eccentrically rotating single-helical rotor turning inside a stator, which are turned by downhole or surface motors; rod pumps, which are long slender rod and cylinders with both fixed and moveable elements inside; gas lift methods, which use an external source of high-pressure gas for supplementing formation gas to lift the well fluids and operate on the principle that gas injected into the tubing reduces the density of the fluids in the tubing; and plunger lift, which utilizes a free piston that travels up and down the wells tubing string without obstruction.

It is important to ensure maximum run life on the artificial lift equipment in order to reduce the operational cost. For example, the minimum desired run life for an ESP unit is one year; however, on occasion the equipment fails in a matter of days from installation. Failure of an ESP or any other component maintained within the casing is very expensive. These excessive costs are related to the replacement equipment, the reinstallation costs, and the loss of production during reinstallation.

One solution to this problem is to utilize high-accuracy, short-interval gyroscopes to determine the mapping or path of existing cased wells. However, these gyroscopes may not be able to measure short enough incremental distances for accurate placement of equipment. More importantly, although gyroscopes are good at measuring a change in azimuth and inclination of a casing as a predictor of force that would be exerted by the casing on installed equipment, the gyroscopes are unable to provide actual direct data measurements about casing sections that may have been pinched, bulged, spiraled, or exhibit any other type of deformation. As such, the problem with properly placing the equipment in the casing still exists.

<CIT> discloses an apparatus employing the remote field eddy-current (RFEC) inspection technique to electromagnetically measure physical parameters of a metallic pipe. RFEC devices inserted into and displaced along a cylindrical pipes may be used to measure the ratio of pipe thickness to electromagnetic skin-depth and thus allow for the non-invasive detection of flaws or metal loss. Typically these RFEC thickness measurements exhibit a so-called double-indication of flaws, an undesired artifact due to a double-peaked geometrical sensitivity function of the device. The method describes a means by which this double indication artifact may be removed by an appropriate processing of RFEC measurements performed by an apparatus specifically designed for this purpose. The invention is particularly well designed for applications in the oilfield industry.

<CIT> discloses various downhole logging tools and methods of using and making the same are disclosed. In one aspect, a downhole logging tool for inspecting one or more well tubulars includes a housing adapted to be supported in the one or more well tubulars by a support cable. A first transmitter, a second transmitter and a third transmitter are positioned in longitudinally spaced-apart relation in the housing and are operable to generate magnetic fields. Driving circuitry is operatively coupled to the first transmitter, the second transmitter and the third transmitter to selectively fire the first transmitter, the second transmitter and the third transmitter in multiple transmission modes to generate magnetic fields to stimulate pulsed eddy currents in the one or more well tubulars. A first receiver is positioned in the housing to sense decaying magnetic fields created by the pulsed eddy currents. Electronic circuitry is operatively coupled to the first receiver to determine a parameter of interest of the one or more well tubular from the sensed decaying magnetic fields.

<CIT> discloses a technique for determining conditions downhole in a well, particularly load conditions acting on a well tool, e.g. a bottom hole assembly. The loads acting on a bottom hole assembly or other well tool during a well related operation are measured. Load data is collected and may be transmitted uphole in real time for evaluation at a surface control unit. Based on the load data and other possible data related to the downhole operation, corrective actions can be taken to improve the operation. This document discloses the preamble to claims <NUM> and <NUM>.

<CIT> discloses a system for estimating downhole parameters includes: at least one parameter sensor disposed along a downhole component and configured to measure a parameter of one or more of a borehole and an earth formation and generate parameter data; and a processor in operable communication with the at least one parameter sensor, the processor configured to receive the parameter data and deformation data relating to deformation of the downhole component. The processor is configured to: generate a mathematical model of the downhole component deformation in real time based on pre-selected geometrical data representing the downhole component and the received deformation data; estimate, in real time, an alignment of the at least one parameter sensor relative to at least one of another parameter sensor and a desired alignment; and in response to estimating a misalignment of the at least one parameter sensor, correct the parameter data based on the misalignment.

<CIT> discloses a non-magnetic survey instrument for boreholes, casing or drill strings. The instrument comprises strain gauges that are used to measure deviations in the casing as the instrument moves along the casing. The instrument can therefore be used to survey the inside of a casing. However, the instrument is not configured to determine optimal locations for downhole equipment installation.

Based upon the foregoing, there is a need in the art for a way to directly measure cased hole deviations.

One embodiment of the present invention provides a method for mapping a cased wellbore, the method comprising providing a cased wellbore; routing a sensor assembly through said cased wellbore to measure strains applied to said sensor assembly, wherein the sensor assembly includes at least one strain gauge and a housing, the housing being configured to represent a piece of downhole equipment to be installed in said cased wellbore; and, determining locations in said cased wellbore for installation of said piece of downhole equipment based on the strains measured by said sensor assembly.

Other embodiments not covered by the present invention provide a method for installing downhole production equipment within a cased well, the method comprising (i) drilling a wellbore and installing casing in said wellbore; (ii) configuring a sensor assembly to represent a piece of downhole equipment to be installed in said casing; (iii) routing said sensor assembly through said casing while measuring forces exerted on said sensor assembly; and (iv) determining a location within said casing, based upon said measurement forces, where the installation of downhole equipment will be desirable; and installing downhole equipment in said location.

Another embodiment of the present invention provides a method for determining where to locate downhole equipment in a cased wellbore, comprising (i) providing a sensor assembly adapted to traverse a cased wellbore; (ii) measuring a plurality of forces exerted on said sensor assembly during traversal thereof through said cased wellbore; (iii) determining from said plurality of forces optimal locations for positioning of downhole equipment, and (iv) installing downhole equipment in one or more of the optimal locations.

Yet other embodiments not covered by the present invention provide a system for determining optimal locations for installation of downhole equipment in a cased wellbore, the system comprising (i) a conveyance system associated with a cased wellbore; (ii) a sensor assembly coupled to said conveyance system that conveys said sensor assembly within the cased wellbore, said sensor assembly measuring forces exerted by the cased wellbore during travel therethrough; and (iii) a controller adapted to communicate with said sensor assembly and said conveyance system so as to correlate measured forces with a position of the sensor assembly in the cased wellbore.

Embodiments of the invention are based, at least in part, on the discovery of a method and associated for system for mapping cased wells by using a strain-gauge sensor. It has been discovered that casing strings can deviate differently than the wellbore in which they are installed, and therefore information relative to deviations in the casing string, which is also referred to as cased hole tortuosity, is valuable to the configuration and operation of the well. The methodologies of the present invention offer a way to directly determine cased hole characteristics and mapping, which offer several advantages, including greater accuracy, over other contemplated methodologies. In particular embodiments of the invention, the information obtained by mapping the cased wellbore can be used to determine a desired location for placing downhole production equipment such as downhole lift devices.

Aspects of the invention can be described with reference to <FIG>, which shows system <NUM> including wellbore support structure <NUM>, wellbore <NUM>, and casing string <NUM>. Support structure <NUM> is aligned relative to wellbore <NUM> so that wellbore <NUM> can receive various elements supported by support structure <NUM> such as drilling rods and associated drilling equipment. Casing <NUM> is disposed within wellbore <NUM> and typically extends from the surface through the entire length, or substantially the entire length, of the wellbore. An annulus <NUM> is disposed between casing string <NUM> and wellbore <NUM>. Casing string <NUM> is typically secured in place with a cement <NUM>, which is disposed within annulus <NUM>. Disposed within casing string <NUM> is a cylindrical opening <NUM>, which may be referred to as cased hole <NUM>.

Support structure <NUM>, which may also be referred to as derrick <NUM>, is a support structure that can support or otherwise carry structural rigging and other mechanical, electrical, and hydraulic equipment that may needed to undertake various tasks relative to the construction and/or operation of a well, such as drilling. After the drilling operation, the drilling equipment is removed to allow for the manipulation of other equipment, such casings and its associated structural features, to be installed in the well, as well as other extraction equipment utilized to extract hydrocarbons, such as lift equipment.

As the skilled person understands, casing string <NUM> includes a plurality of pipes, which are also referred to as casings, interconnected by coupling elements. The individual casing are typically about <NUM> metres (<NUM> feet) in length and can vary in diameter, depending upon the type of well, and the location within the well, the individual casing. Generally speaking, wellbores typically have a diameter of from between <NUM> to <NUM> (<NUM>" to <NUM>"), and the casings have a correspondingly reduced diameter. In some embodiments, the casing outer diameter may range from <NUM> to <NUM> (<NUM>" or 9½") or larger. As the skilled person appreciates, the inner diameter of the casing can be a significant factor in determining the outer diameter size of the downhole equipment that is installed within the well, and the outer diameter of the downhole equipment is sized to provide the maximum extraction capability. Additionally, although the wellbore <NUM> and the casing <NUM> are shown in a substantially vertical orientation, skilled artisans will appreciate that the wellbore and casing may be in any orientation used for the extraction of resources (e.g. horizontal). In any event, it is desirable to install downhole equipment that operates efficiently without failure, as discussed above.

From a functional standpoint, the casing string is typically employed to protect the wellbore and prevent fluids or other contaminants from migrating into the geographical strata surrounding the wellbore or vice versa, maintain wellbore stability, prevent contamination of water sands, isolate water from producing formations, and control well pressures during drilling, production, and workover operations. Casing can also provide locations for the installation of blowout preventers, wellhead equipment, pumps, lifts, and other downhole equipment, as well production packers and production tubing.

Wells often include a plurality of different types of casing and/or casing strings, which collectively form an overall casing system. An exemplary casing system can be described with respect to <FIG>, which shows casing system <NUM>', which includes several concentric sub-casings (which may include concentric sub-casing strings). As shown, casing system <NUM>' may include a conductor casing 16A, which is the outermost casing string and which supports one or more additional casing strings disposed within string 16A. For example, a diametrically smaller casing 16B may be positioned within casing 16A, and in a similar manner, a smaller diameter intermediate casing 16C can be positioned within casing 16B. And, a diametrically smaller production casing 16D can be positioned within intermediate casing 16C. Each casing string of the casing system may be of a different length as required by the well design. Cement <NUM> may be disposed between each of the concentric strings, and the cement disposed between any two casing strings may run the entire length of the shorter of two adjacent strings, or the cement may be disposed for only a portion of the length between two adjacent strings. It will be appreciated that the concentric casing may be used at different depths of the well depending on the surrounding geology. Although not shown, liners, which do not extend to the surface of the well, may be positioned within casings. These liners may provide continuity between adjacent axially positioned casings.

The drilling of the wellbore and the installation of the casings (including the cementing of the casings) can take place by using conventional techniques, which are well known in the art. For example, it is often typical practice to drill a section of the wellbore (i.e. drill to a desired depth), and then line the wellbore with appropriate casings. After this step, additional drilling may take place below the location where the casing is installed to lengthen the wellbore, and then additional casing is installed within this newly drilled section. Typically, the casing that is installed following this additional or subsequent drilling step is narrower in diameter than the previously installed casing string, which results in the configuration or system shown in <FIG>. These steps can be repeated as required by the well design until the final casing is installed, which is typically the production casing.

After installation of the casing, which may include cementing of the casings, the casing string is mapped pursuant to practice of this invention. It will be appreciated that the mapping of the innermost casing string, which could include a liner where a liner is present, is the target for the mapping, despite the presence of a plurality of concentric casings (i.e. a casing system <NUM>'). For example, the target of the mapping process of the present invention may include mapping of the production casing. It will also be appreciated that the mapping of the casing will take place prior to installation of any production tubing or production equipment such as lift equipment.

As indicated above, the goal of mapping the casing is to determine the overall tortuosity of the casing; for example, mapping the casing serves to identify any deviations in the casing string, which deviations may include directional deviations, deviations in the diameter of the casing at any given point along the length of the casing, changes in orientation, and/or combination of distortions and changes in orientation. It will be appreciated that these deviations can result from deviations in the wellbore or result from installation of the casing. For example, forces applied to the casing during installation or changes in nearby geology can pinch, collapse, spiral, helically distort, bend, bulge, undulate or otherwise deform a portion of the casing string. With reference again to <FIG>, a deviation is shown where a portion of casing <NUM> is inclined or slightly offset at a distance "x.

In one or more embodiments, the mapping step, which may also be referred to as logging step, takes place by routing, which may also be referred to as conveying, a sensor device, which may also be referred to as a sensor assembly, through the casing. With reference to <FIG>, a sensor assembly <NUM> is shown positioned within cased hole <NUM>. Sensor assembly <NUM> may be connected to a conveyance system <NUM> via a cable <NUM>. As used herein, a conveyance system generally refers to any system that is adapted to convey sensor assembly <NUM> through the casing <NUM>. Also, several other conveyance or attachments elements can be used in lieu or in addition to cable <NUM>. For example, sensor <NUM> can be connected to conveyance system <NUM> via jointed pipe, a wireline, a single-strand slickline, a multi-strand braided wire, an electric wireline, coil tubing, a solid pipe, a continuous solid rod, or any other conveyance elements known in the art. Other embodiments may employ a sensor assembly that is capable of operating autonomously within the casing without a physical connection to a conveyance system.

A controller <NUM> may be in communication with conveyance system <NUM> for the purpose of controlling the routing and retrieval of assembly <NUM>. Additionally, the same or a different controller or data collection and/or processing unit can be communication with assembly <NUM> to receive the data collected from assembly <NUM>. For example, controller <NUM> may provide the necessary hardware, software, memory, and related components that are adapted for transferring the data or directly analyzing the data collected so as to determine deviations within casing <NUM>.

In particular embodiments, sensor assembly <NUM> is routed through cased hole <NUM> by gravity feeding the assembly <NUM> into cased hole <NUM>. This step of conveying can be assisted by the use of weights (not shown) attached to or otherwise acting on sensor assembly <NUM> or conveying element <NUM>, which may help propel sensor assembly <NUM> through casing <NUM>. In some embodiments, a tractor mechanism may also be employed to push or pull sensor assembly <NUM> through casing <NUM>. It will also be appreciated that conveyance system <NUM>, with assistance of attachment elements <NUM>, can assist in retrieving assembly <NUM> after it has completed its path through cased hole <NUM>.

In one or more embodiments, conveyance system <NUM> may include or incorporate communication wires so as to transmit data collected from sensor assembly <NUM>. Skilled artisans will also appreciate that the data may be stored internally in sensor assembly <NUM> and retrieved at a later time for analysis, or the data may be transmitted directly from sensor assembly <NUM> utilizing wired, wireless, or other types of data signals.

In accord with the present invention, sensor assembly <NUM> includes one or more strain gauge sensors, or any other type of measurable force sensor, that can measure strain placed upon one or more elements of assembly <NUM>. An exemplary assembly <NUM> can be described with reference to <FIG>. Generally speaking, assembly <NUM> includes a body <NUM>, a lead end <NUM>, a trailing end <NUM>, a carriage <NUM>, wheels <NUM>, and a strain-gauge sensor <NUM>. As will be appreciated, lead end <NUM> can be designed to be first inserted into cased hole <NUM> with trailing end <NUM> directly or indirectly connected to the conveyance system <NUM>. Carriage <NUM> can be adapted to swivel <NUM>° about the axial length of body <NUM>, and carriage <NUM> can carry any number of wheels <NUM>. Together, swivel carriage <NUM> and wheels <NUM> may facilitate the traversal of sensor assembly <NUM> through casing <NUM>. In one or more embodiments, swivel carriage <NUM> and wheels <NUM> may provide the point of contact with the casing string and sensor <NUM> measures strain imparted thereon.

In one or more embodiments, assembly <NUM> is sized or is otherwise configured to be insertable into the casing <NUM>. For example, one or more elements of assembly <NUM> are designed and/or shaped to represent the general geometry of downhole equipment that is envisaged for the well. In other words, one or more elements of assembly <NUM> are configured to experience the same or similar forces that will be experienced by downhole equipment that will be subsequently installed within the well. For example, housing <NUM> can be sized to have mechanical properties such as an outer diameter and length and/or stiffness or flexibility that matches or otherwise approximates the proposed equipment to be installed. Or, either alone or in conjunction with the body, the wheels can be sized or positioned to represent or otherwise mimic a feature of the anticipated downhole equipment such as the diameter of the anticipated downhole equipment. In this way, the forces detected by the sensor assembly passing through the sections of the casing accurately mimic the forces that will be exerted on the proposed equipment <NUM>.

In one or more embodiments, sensor assembly <NUM>, through sensor <NUM>, optionally operating in conjunction with one or more elements of assembly <NUM>, is adapted to directly and electronically measure one or more forces that can be experienced by the anticipated downhole equipment. For example, sensor assembly <NUM> can be adapted to directly experience and measure bending force, tubular bending, axial stress, shear, pressure, and torsional strain experienced by sensor assembly <NUM> as it passes through the casing. As indicated above, these measured forces can be used to determine or predict the resulting stresses and forces exerted on downhole production equipment subsequently installed. In one or more embodiments, assembly <NUM> may include other sensors, such as those adapted to detect or measure temperature or any other environmental characteristic relevant to the installation or operation of downhole equipment.

Accordingly, the mapping step of the present invention includes gathering data obtained by sensor assembly <NUM> (e.g. data from strain-gauge sensor <NUM>). Additionally, the step of mapping includes gathering locational information relative to where data from the assembly <NUM> (e.g. strain gauge data) is obtained. For example, mapping step may include determining and gathering data on the depth of the assembly relative to the surface. This data can be obtained directly from assembly <NUM>, where assembly <NUM> is adapted to gather and provide this data, or from conveyance system <NUM>, which can be adapted to gather and provide this data. For example, the depth of assembly <NUM> can determined by the length of cable fed into the cased hole. Accordingly, the mapping of the casing represents an interior dimensional and force profile of the casing at predetermined locations or intervals throughout the length or a portion of the installed casing.

In one or more embodiments, the information obtained from sensor assembly <NUM> being routed through at least a portion of the casing (i.e. mapping information), either alone or together with existing information from previous failures of installed downhole equipment, may be used to assist in selecting optimal locations for the anticipated downhole equipment. In addition, the information (such as bending and stress measurements) can help to identify locations in the casing string that exceed predetermined force thresholds where additional electrical cable protection may be required to ensure that an electrical conduit installed between casing and production tubing is not damaged during installation or while operating the lift equipment.

Accordingly, aspects of the invention include the step of installing downhole equipment based upon data and information derived from the mapping operation. With reference to <FIG>, downhole equipment <NUM> is installed in casing <NUM> at a desired location where, based upon gathered data and information generated therefrom, the location is expected to provide a technologically useful production outcome. As those skilled in the art appreciate, successful outcomes depend on many factors including the longevity of the downhole equipment, which can be prolonged by proper placement of the equipment in a location of the well that does not suffer from deleterious tortuosity.

Practice of one or more embodiments of the invention is not limited by the type of downhole equipment installed. In one or more embodiments, the equipment includes production equipment such as artificial lift equipment. Artificial lift equipment many include, but is not limited to, electrical submersible pumps (ESPs), progressive cavity pumps (PCPs), rod pumps, gas lifts, plunger lifts, hydraulic lifts, foam lifts or any related piece of equipment installed within a section of casing.

Referring now to <FIG>, it can be seen that a method for determining an optimal installation of downhole equipment in a cased wellbore is designated generally by the numeral <NUM>. Initially it is noted that step <NUM> provides for drilling a wellbore and installing a casing in selected sections of the wellbore. Skilled artisans will appreciate that the entire wellbore may be cased or that only selected sections of the wellbore may be cased. Positioning of the selected cased sections of the wellbore are dependent upon factors such as the geology of the wellbore and desired locations of wellbore equipment. Next, an evaluation process <NUM> is implemented which may include some or all of the following steps. At step <NUM>, dimensions and limitations of the downhole equipment <NUM> to be installed are determined and general dimensions of the cased wellbore <NUM> are determined. For example, an educated estimation is made as to what size and configuration of downhole equipment will fit and operate in estimated locations of the cased wellbore and the sensor assembly is configured accordingly. To this end, the sensor assembly <NUM> is configured to represent a piece of downhole equipment to be installed in the casing. For example, configuration of the sensor assembly <NUM> may be done by shaping the body <NUM> to dimensionally represent the shape of the downhole equipment to be installed. Configuration may also include strategic placement of the strain gauge sensor within the shaped assembly to accurately represent the mechanical properties of the equipment and/or mimic the forces that will be applied to the equipment during use. Planning and selection of measurement and string running gear configurations that are sized to simulate the downhole equipment installation and operational loads that will likely be encountered by that equipment are implemented at step <NUM>.

Next, at step <NUM>, the sensor assembly is conveyed through the casing while measuring forces exerted on the sensor assembly. In particular, the sensor assembly <NUM>, which incorporates the measurement tool string and the selected sensors, is conveyed in the cased wellbore <NUM> for the purpose of collecting downhole sensor data which represents the path of the cased wellbore. The sensor assembly may also detect changes in the casing's path, and any dimensional variations that result in extraneous forces on the sensor assembly. This step may be implemented by the conveyance system <NUM>. After completion of the conveyance of the sensor assembly <NUM> at step <NUM>, the sensor assembly can be retrieved, and the data from the sensor assembly can be retrieved and downloaded into an appropriately configured database whereupon the measured data is processed and reviewed. Alternatively, the data can be transmitted in real time while the sensor assembly is routed through the cased hole. At step <NUM>, a casing map that identifies the path, changes in the path and the associated load conditions from the data acquired may be generated with appropriate software programs run by the controller <NUM>, which may employ artificial intelligence and/or machine learning algorithms. This allows for the determination of locations throughout the casing which will likely exert acceptable amounts of force on the piece of downhole equipment to be installed. In the same context, it will also be determined during this step the locations which may exert unacceptable amounts of force on a piece of installed downhole equipment.

Accordingly, at step <NUM>, the casing map and the associated load conditions are used to determine the best/optimal equipment installation location(s) and/or configuration using predetermined thresholds and other experiential guidance generated by the software programs. This analysis may also consider force thresholds for which added protection may be needed for electrical conduits. Upon completion of the ideal equipment and/or configuration, it will be determined at step <NUM> whether the downhole equipment will have a suitable life expectancy. If it is believed that the casing <NUM> will adversely affect operation of the equipment and no optimal location can be found for the equipment in the wellbore, then, at step <NUM>, it is determined whether smaller equipment can be utilized. If this is the case, then the method returns to step <NUM> and steps <NUM>-<NUM> are repeated. For example, the sensor assembly can be adjusted or reconfigured (e.g. outer diameter or length) and the assembly can be rerouted to determine whether the forces experienced by the sensor exceed predetermined thresholds for any given region or location.

However, if at step <NUM> it is determined that smaller equipment cannot be utilized, then the technician will evaluate production contingency options and select another lift or production method for the evaluation of new downhole equipment. In other words, step <NUM> will return to step <NUM> to determine whether other downhole equipment can be implemented or not.

Returning to step <NUM>, if it is determined that the downhole equipment to be installed has suitable life expectancy, then the method continues to step <NUM> where a complete installation of the downhole equipment into the optimal range and/or optimal configuration is completed.

Claim 1:
A method for mapping a cased wellbore (<NUM>), the method comprising:
(i) providing a cased wellbore (<NUM>);
(ii) routing a sensor assembly (<NUM>) through said cased wellbore (<NUM>) to measure strains applied to said sensor assembly (<NUM>), characterized in that the sensor assembly (<NUM>) includes at least one strain gauge (<NUM>) and a housing (<NUM>), the housing (<NUM>) is configured to represent a piece of downhole equipment to be installed in said cased wellbore (<NUM>);
(iii) determining locations in said cased wellbore (<NUM>) for installation of said piece of downhole equipment based on the strains measured by said sensor assembly (<NUM>).