Source: {"pile_set_name": "USPTO Backgrounds"}

Oil and gas wells are typically drilled with a rotary drill bit, and the resulting borehole is cased with steel casing cemented in the borehole to support pressure from the surrounding formation. Hydrocarbons may then be produced through smaller diameter production tubing suspended within the casing. Although fluids can be produced from the well using internal pressure within a producing zone, pumping systems are commonly used to lift fluid from the producing zone in the well to the surface of the earth. This is often the case with mature producing fields where production has declined and operating margins are thin.
The most common pumping system used in the oil industry is the sucker rod pumping system. A pump is positioned downhole, and a drive motor transmits power to the pump from the surface with a sucker rod string positioned within the production tubing. Rod strings include both “reciprocating” types, which are axially stroked, and “rotating” types, which rotate to power progressing cavity type pumps. The latter type is increasingly used, particularly in wells producing heavy, sand-laden oil or producing fluids with high water/oil ratios. The rod string can consist of a group of connected, essentially rigid, steel or fiberglass sucker rod sections or “joints” in lengths of 25 or 30 feet. Joints are sequentially connected or disconnected as the string is inserted or removed from the borehole, respectively. Alternatively a continuous sucker rod (COROD) string can be used to connect the drive mechanism to the pump positioned within the borehole.
A number of factors conspire to wear down and eventually cause failure in both sucker rods and the production tubing in which they move. Produced fluid is often corrosive, attacking the sucker rod surface and causing pitting that may lead to loss of cross-sectional area or fatigue cracking and subsequent rod failure. Produced fluid can also act like an abrasive slurry that can lead to mechanical failure of the rod and tubing. The rod and tubing also wear against each other. Such wear may be exacerbated where the well or borehole is deviated from true vertical. Even boreholes believed to have been drilled so as to be truly vertical and considered to be nominally straight may deviate considerably from true vertical, due to factors such as drill bit rotational speed, weight on the drill bit, inherent imperfections in the size, shape, and assembly of drill string components and naturally-occurring changes in the formation of the earth that affect drilling penetration rate and direction. Also, some boreholes are intentionally drilled at varying angles using directional drilling techniques designed to reach different parts of a hydrocarbon-producing formation. As a result, sucker rods and production tubing are never truly concentric, especially during the dynamics of pumping, and instead contact one another and wear unpredictably over several thousand feet of depth. Induced wear is therefore a function of many variables, including well deviation from true vertical; angle or “dogleg” severity; downhole pump operating parameters; dynamic compression, tensile and sidewall loads; harmonics within the producing sucker rod string; produced solids; produced fluid lubricity; and water to oil ratio. Additionally, in certain conditions, such as in geologically active areas or in areas of hydrocarbon production from diatomite formations, wellbores may shift over time, causing additional deviation from vertical.
Boreholes deviate considerably from true vertical due to various factors, including drill bit rotational speed, weight on the drill bit, inherent imperfections in the size, shape, and assembly of drill string components and naturally-occurring changes in the formation of the earth. When using a tubing anchor to rigidly fix the lower part of a tubing string in a wellbore relative to the casing, it is often necessary to apply a tensile load to the tubing string to prevent sags or kinks in the tubing in certain zones of the wellbore. In certain conditions, such as in geologically active areas or in areas of hydrocarbon production from diatomite formations, producing wells may shift over time, causing additional deviation from vertical. As a result, sucker rods and production tubing are often never truly concentric, especially during the dynamics of pumping, and instead contact one another and wear in certain areas, some of which are known as “doglegs”, or where the tubing sags or is kinked. Without a continuous deviation survey of the wellbore, it is difficult, if not impossible, to identify areas where the well deviation from vertical results in contact and wear of the rods and tubing.
For many years it has been possible to determine the deviation of a borehole, or wellbore, from true vertical. Such techniques are used extensively in the drilling of new wellbores, either as periodic “single shot” surveys, “multishot” surveys or even continuously while drilling, known as “MWD”. U.S. Pat. No. 6,453,239 to Shirasaka, et al, U.S. Pat. No. 5,821,414 to Noy, et al, U.S. Pat. No. 4,987,684 to Andreas, et al and U.S. Pat. No. 3,753,296 to Van Steenwyk, disclose such examples of surveying wellbores. However, in the case of most existing rod-pumped oil wells, any such surveys performed during the original drilling of the well largely comprised periodic surveys of wellbore direction and inclination performed only at one or two key intervals during the well-drilling operation. Consequently, a continuous profile of the wellbore deviation, giving rise to tubing and rod wear, is not generally known. Alternatively, performing a dedicated, continuous directional survey of existing wellbores, such as those contemplated in the above patents, is generally cost-prohibitive. There is a need for a cost-effective directional survey that can be integrated into well work-over operations of existing producing wellbores to obtain an accurate, nearly continuous deviation profile and allow mitigation of rod and tubing wear.
Prior art wellbore deviation techniques and tools are generally designed for the measurement of a wellbore while drilling, or are used on wireline or slickline during the process of drilling, to measure the direction and inclination of the wellbore with respect to an as-yet un-reached planned trajectory or target of interest. Prior art accelerometer and magnetometer deviation tools are also typically capable of determining wellbore inclination and azimuth only outside of the presence of magnetic interference, e.g., in open, uncased wellbores.
Oil well production string inspection methods conventionally use magnetic flux leakage techniques and typically rely only upon signal amplitude and time-based denominations or, in some cases, signal amplitude and wellbore depth, to provide the equipment operator with information representing the sucker rod or tubing string condition. U.S. Pat. Nos. 2,555,853, 2,855,564, 4,492,115, 4,636,727, 4,715,442, 4,843,317, 5,914,596, 6,316,937 disclose methods and apparatus to perform magnetic flux leakage inspections of sucker rods and tubing as elements of the production wellbore.
The amplitude of a magnetic flux leakage signal from a flaw in a ferromagnetic material under test is a function of many variables, including magnetic permeability of the material under test; magnetizing field strength; detection sensor type; sensor-to-material-under-inspection stand-off; flaw orientation relative to magnetic field direction; flaw volume; flaw depth, flaw shape; sensor-to-material-under-inspection relative velocity; sensor signal filtering and; sensor signal-to-noise ratio, among others. Conventional systems that rely only upon amplitude and time, or upon amplitude and wellbore depth, are susceptible to misinterpretation since the apparent flaw signal amplitude may be a function of many factors other than depth alone. Many such systems do not employ field standardization techniques to establish flaw standardization levels for inspection. Even those methods that do employ standardization techniques rely upon signal amplitude alone for flaw severity analysis.
Some prior art gyroscope and accelerometer deviation tools, of either the gimballed or strapped-down type, are capable of use inside cased hole and are generally used during the drilling process. U.S. Pat. No. 4,468,863 discloses a single shot or periodic multi-shot survey tool deployed on a wireline. U.S. Pat. No. 5,821,414 discloses a system for measuring deviation and inclination, while a wellbore is being drilled, to achieve an ultimate bottom hole location that positions the wellbore to optimally drain the target hydrocarbon reservoir. Most Measurement-While-Drilling applications that are intended for open hole, high temperature, high pressure environments, as disclosed in U.S. Pat. No. 6,714,870 to Weston, et al. Such tools are typically large, insulated, shock-absorbing, high pressure- and temperature-resistant to handle the extremely demanding environment of drilling in extreme temperature, vibration and pressure, as disclosed in U.S. Pat. No. 4,302,886. Systems may utilize relatively gimbaled gyroscopes or expensive and complex Coriolis-effect strapped-down gyroscopes, as disclosed in U.S. Pat. No. 6,453,239. Such tools are generally too large and lengthy to be used inside small diameter production tubing, and too expensive for most pumped well application. The high cost of these systems prohibits consideration by the operators of relatively shallow, existing rod-pumped, producing wells in the declining fields of mature sedimentary basins.
Failure of pumped oil wells due to the cumulative effect of the wear of sucker rods on tubing and such wear combined with corrosion is considered to be the single largest cause of well down time. Generally accepted methods of mitigating such wear include installing rod guides