Abstract:
Method and apparatus for identifying lost circulation in subterranean wells, in particular, methods for treating the identified lost circulation zones with fluid compositions that are pumped into a wellbore enter voids in the subterranean-well formation through which wellbore fluids escape, and form a seal that limits further egress of wellbore fluid into the lost-circulation zone.

Description:
BACKGROUND OF THE INVENTION 
       [0001]    The statements in this section merely provide background information related to the present disclosure and may not constitute prior art. 
         [0002]    Embodiments relate to equipment and methods for identifying the presence and location of lost circulation in subterranean wells; in particular, methods for treating the identified lost circulation zones with fluid compositions that are pumped into a wellbore, enter voids in the subterranean-well formation through which wellbore fluids escape, and form a seal that limits further egress of wellbore fluid into the formation. 
         [0003]    During the construction of a subterranean well, drilling and cementing operations are performed that involve circulating fluids in and out of the well. The fluids exert hydrostatic and pumping pressure against the subterranean rock formations, and may induce a condition known as lost circulation. Lost circulation is the total or partial loss of drilling fluids or cement slurries into highly permeable zones, cavernous formations and fractures or voids. Such openings may be naturally occurring or induced by pressure exerted during pumping operations. Lost circulation should not be confused with fluid loss, which is a filtration process wherein the liquid phase of a drilling fluid or cement slurry escapes into the formation, leaving the solid components behind. 
         [0004]    Lost circulation can be an expensive and time-consuming problem. During drilling, this loss may vary from a gradual lowering of the mud level in the pits to a complete loss of returns. Lost circulation may also pose a safety hazard, leading to well-control problems and environmental incidents. During cementing, lost circulation may severely compromise the quality of the cement job, reducing annular coverage, leaving casing exposed to corrosive downhole fluids, and failing to provide adequate zonal isolation. Lost circulation may also be a problem encountered during well-completion and workover operations, potentially causing formation damage, lost reserves and even loss of the well. 
         [0005]    While drilling, it is routine practice to monitor the amount of drilling fluid pumped into the well and flowing back from the well, any difference between these volumes being attributed to downhole losses; this global fluid mass balance provides an accurate indication of downhole fluid losses or gains, but does not reveal the location at which such events are occurring. 
         [0006]    Lost-circulation solutions may be classified into three principal categories: bridging agents, surface-mixed systems and downhole-mixed systems. Bridging agents, also known as lost-circulation materials (LCMs), are solids of various sizes and shapes (e.g., granular, lamellar, fibrous and mixtures thereof). They are generally chosen according to the size of the voids or cracks in the subterranean formation (if known) and, as fluid escapes into the formation, congregate and form a barrier that minimizes or stops further fluid flow. Surface-mixed systems are generally fluids composed of a hydraulic cement slurry or a polymer solution that enters voids in the subterranean formation, sets or thickens, and forms a seal that minimizes or stops further fluid flow. Downhole-mixed systems generally consist of two or more fluids that, upon making contact in the wellbore or the lost-circulation zone, form a viscous plug or a precipitate that seals the zone. 
         [0007]    A thorough overview of LCMs, surface-mixed systems and downhole-mixed systems, including guidelines for choosing the appropriate solution for a given situation, is presented in the following reference: Daccord G, Craster B, Ladva H, Jones TGJ and Manescu G: “Cement-Formation Interactions,” in Nelson E and Guillot D (eds.):  Well Cementing— 2 nd  Edition, Houston: Schlumberger (2006): 202-219, included herein by reference thereto. 
         [0008]    Mechanical solutions also exist, and generally involve placing a piece of tubular in front of the loss zone, thereby making this portion of the wellbore impervious. 
         [0009]    Both chemical and mechanical methods work best when the depth of the zone to be plugged is well known—this is of paramount importance for mechanical solutions. Failure to place fluid systems at the optimal depth may lead to various detrimental effects such as dilution of the fluid system into the drilling fluid already present in the well or unknown delay between the time when the fluid exits the drill string and when it enters the loss zone. Often, the fluid system even undergoes chemical reactions, for instance in order to increase its viscosity once it is placed into the loss zone. If the chemical reaction takes place too soon or too late, the effectiveness of the treatment may be dramatically reduced. 
         [0010]    Presently, identification of the depth of loss zones is seldom performed because it requires time and specialized equipment. One method consists of recording formation-evaluation logs and wellbore images using either wireline or “while-drilling tools.” From this information, specialists can infer the probable depths of loss zones. This method is usually reserved for situations in which losses are severe and the associated hazards are high. In the majority of situations, it is not economical to spend rig time recording this information. 
         [0011]    Monitoring the drilling-fluid pressure and temperature in the annulus while drilling is a common practice. These measurements are weakly sensitive to losses of drilling fluid to the formation, but they are much more sensitive to other parameters—fluid rheology, hole cleaning, pipe movement, etc. As a result, it is practically impossible to extract any information on loss zones depth from these measurements. 
         [0012]    In paper SPE 97372, the authors describe means of performing reservoir testing while drilling underbalanced. Examples are provided in which distributed-pressure measurements are made along the drillstring, together with the flow rate at surface. The flow is multiphase, and the objective is to estimate reservoir pressure by analyzing the annulus pressure. This paper is included herein by reference. 
         [0013]    In paper SPE 108345, the authors studied the best theoretical distributed measurements that could be made while drilling. They provide two theoretical examples of (1) a fluid influx from the formation into the well and (2) loss of drilling fluid into a fracture. The measurements considered included pressure and flow rate. The authors concluded that annular-flow-rate measurements do not exist at present and “could be essential in improving an early detection of [ . . . ] incidents resulting in loss of circulation.” This paper is included herein by reference. 
         [0014]    Many patents have been issued concerning the measurement of mud returns at surface, e.g., U.S. Pat. No. 5,063,776 and U.S. Pat. No. 6,257,354, included herein by reference thereto. These methods are aimed at the real-time analysis of downhole events using surface-flow-rate measurements and eventually downhole-pressure measurements. These methods are intrinsically unable to measure the depth at which drilling fluid losses are occurring. 
         [0015]    WO2007/148269 relates to a system including a section of tubular having a main flow passage, a fluid diversion port and at least two sensors in the section of tubular, one being located upstream of the fluid diversion port and one being located downstream, included herein by reference thereto. This patent application does not relate to lost circulation, as pumping lost-circulation solutions through a tubular port would create risks of losing the tubular as the lost-circulation solution could form a plug instantaneously, thereby sticking also the tubular. 
         [0016]    Thus, despite valuable contributions in the art, the industry still has difficulties properly locating the position of lost-circulation zones in a timely manner, especially while drilling. 
       SUMMARY OF THE INVENTION 
       [0017]    Despite many contributions in the art, there is still a need for a system to locate lost-circulation zones, allowing a quick and efficient treatment and thereby preserving the well and maximizing its productivity. Some embodiments of the invention fulfills this need. 
         [0018]    In an aspect, embodiments relate to methods for identifying the depth and/or severity of loss zones while drilling a well. 
         [0019]    In a further aspect, embodiments relate to methods for treating lost circulation in a subterranean well. 
         [0020]    In yet a further aspect, embodiments relate to a well-treatment apparatus. 
     
    
     
       BRIEF DESCRIPTION OF THE DRAWINGS 
         [0021]    For a more complete understanding of some embodiments, and the advantages thereof, reference is now made to the following descriptions taken in conjunction with the accompanying figures, in which: 
           [0022]      FIG. 1  displays a wellbore drilled through various geological formations, using a hollow drill string. 
           [0023]      FIG. 2A  shows an arrangement of several fluid-velocity sensors placed around a tubular body. 
           [0024]      FIG. 2B  shows an arrangement of one sensor placed on a rotating pipe. 
       
    
    
     DETAILED DESCRIPTION 
       [0025]    Some embodiments may be described in terms of treatment of vertical wells, but is equally applicable to wells of any orientation. Embodiments may be described for hydrocarbon production wells, but it is to be understood that the invention may be used for wells for production of other fluids, such as water or carbon dioxide or, for example, for injection or storage wells. Embodiments may also be described for offshore and land wells. It should also be understood that throughout this specification, when a concentration or amount range is described as being useful, or suitable, or the like, it is intended that any and every concentration or amount within the range, including the end points, is to be considered as having been stated. Furthermore, each numerical value should be read once as modified by the term “about” (unless already expressly so modified) and then read again as not to be so modified unless otherwise stated in context. For example, “a range of from 1 to 10” is to be read as indicating each and every possible number along the continuum between about 1 and about 10. In other words, when a certain range is expressed, even if only a few specific data points are explicitly identified or referred to within the range, or even when no data points are referred to within the range, it is to be understood that the inventor appreciates and understands that any and all data points within the range are to be considered to have been specified, and that the inventor has possession of the entire range and all points within the range. 
         [0026]    Embodiments relate to simple and cost-effective means for locating the depth of lost-circulation zones and the severity of the fluid losses while drilling. One calculates the fluid-loss rate from in-situ drilling-fluid-flow measurements in the annular portion of the well. The differentiation of the flow rate with respect to the depth provides the depth of the lost-circulation zones and their respective fluid-loss rates. This knowledge allows one to design treatments adapted to the severity of the losses, and placing the optimal treatments at the optimal depths. 
         [0027]    One embodiment involves inserting a tubular body equipped with a drill-bit into the wellbore. The drill bit is equipped with at least one nozzle. Drilling of the wellbore commences, drilling fluid is circulated through the interior of the tubular body, through the drill-bit nozzle(s), and then through the annulus between the outer surface of the tubular body and the wellbore wall. At least one sensor is attached to the outer surface of the tubular body, the sensor being able to record a parameter and transmit the parameter to surface. 
         [0028]    The sensor attached to the outer surface is preferably located at least a few meters above the drill bit, preferably about 10 m. Preferably, the tubular is equipped with a plurality of sensors, allowing the user to have a means for detecting lost-circulation zones all along the tubular. Moreover, as the lost circulation may occur during the drilling operations, e.g., if a fracture is created due to excessive pressure, such a configuration would allow real-time monitoring. 
         [0029]    The drilling fluid may be any drilling fluid known in the art such as water-base mud, oil-base mud or synthetic-base mud. 
         [0030]    The tubular body is preferably sectioned pipe wherein the sections may be joined by any means (welds, threaded fittings, flanged fittings, combinations thereof, and the like). 
         [0031]    The parameter to be recorded in the present invention is preferably a parameter that can enable the operator to detect lost-circulation zones, preferably the parameter is fluid velocity. 
         [0032]    The sensor useful in the context of the present invention may be any sensor capable of measuring suitable parameters. Examples of suitable sensors include (but are not limited to) flowmeters, spinners, electromagnetic flowmeters, optical-fluid sensors, ultrasonic-flow-velocity sensors and differential-pressure-flow sensors. Such devices can measure flow rate directly, without having to employ mathematical algorithms. Such devices are also not affected by variations in the fluid&#39;s rheological properties. 
         [0033]    Embodiments may comprise a plurality of sensors capable of detecting—in real time—fluid flow at the outlet of the tubular body and up the annulus between the tubular body and the wellbore. The sensors may be programmable both downhole and at the surface. This may be accomplished by using one or more algorithms to allow rapid, real-time interpretation of downhole data, allowing adjustments to be made at the surface and/or downhole for effective treatment. 
         [0034]    Embodiments also include an apparatus comprising a tubular body having at its bottom end a drill bit, the drill bit being equipped with nozzles through which fluids may flow. The tubular body is equipped at its outer surface with a least one sensor able to record a parameter useful for identifying the depth and severity of lost-circulation zones. The apparatus is further equipped with means for transmitting the parameter values to the surface. 
         [0035]    In the present context, a lost-circulation zone will be identified if an annular-fluid-flow difference is measured by the sensor(s) placed along the tubular body. Basically, with the methods and apparatus of the present embodiments, one compares, in real time, the mud-flow rate that is pumped downhole with the mud-flow rate returning upstream through the annulus. The mud-flow rate is calculated from the measurement of the hole size, the knowledge of the external dimensions of the tubular body, and the measurement of the fluid velocity. The hole size can be determined using standard techniques such as acoustic measurements. 
         [0036]    The mud-flow rate, in the present context, may be calculated at various depths while drilling or during trips. 
         [0037]    Accordingly, as soon as a flow-rate reduction is detected, the information will be transferred to the surface, and the operator will thus be able to immediately react. The preferred next step will then be to pump a lost-circulation treatment. As the flow-rate will generally be proportional to the severity, the present invention will also allow the operator to tailor the treatment. 
         [0038]    Another improvement is the reduction of risks attached with lost-circulation treatments. Indeed, some extremely efficient lost-circulation treatments have recently been developed. These are based on fluids that crosslink in-situ, forming an extremely strong mass. One of the risks associated with these fluids is that, if not placed properly, they may stick the drill pipe, rendering any subsequent job highly difficult. The present embodiments will allow precise fluid placement directly into the voids, thereby reducing the risks. In a preferred embodiment, once the lost-circulation-zone depth and severity have been determined, a lost-circulation treatment will be pumped at the required depth, the treatment having delayed activation. The activation trigger may be (but would not be limited to) pH, temperature or even the stress encountered while the fluid passes through the drill-bit nozzles. 
         [0039]    The apparatus and methods according to the present embodiments may include surface/tool communication through one or more communication links, including (but not limited to) hard wire, optical fiber, wireless, radio, mud-pulse telemetry, electromagnetic telemetry, wired drill pipe and microwave transmission. The sensors and communication systems may be powered locally by battery, fuel cell, fluid flow, or other local power sources. 
         [0040]    Systems and methods of the embodiments may use information from one or more sensors in real-time to evaluate and change, if necessary, the treatment. 
         [0041]    In a further aspect, embodiments allow the identification of lost-circulation events that are so severe that there is no returning annular flow. In this case, the first sensor placed above the depth of the loss zone will not detect any returning flow. Under these circumstances, pumping a strong lost-circulation-treatment fluid would be very useful. 
         [0042]    The system and methods may also be used as a diagnostic tool to determine whether the lost-circulation treatment has been successful or not. In this case, once the lost-circulation treatment fluid has been pumped, and normal operations are restarting, the real-time measurement of the returning flow-rate will tell immediately to the operator if the treatment was successful. 
         [0043]      FIG. 1  displays a wellbore  101  drilled through various geological formations, using a hollow drill pipe  102 . A drilling fluid  103  is pumped down the tubular body. Once reaching the bottom of the tubular body, the fluid passes through a drill-bit (not represented), and then moves up the annulus usually to the surface  104 . In an ideal configuration, the fluid is recovered and recycled on surface. 
         [0044]    A first lost-circulation zone  105  is represented by a loss of fluid from the wellbore into the formation, decreasing the return-flow rate. The tubular body according is equipped with at least one annular-flow-rate sensor  106  that will immediately detect a lost-circulation zone and allow the operator to act accordingly. In a preferred embodiment, the present invention allows even the detection of multiple loss zones, as long as the first loss circulation zone does not create a situation of “total loss.” This is displayed in  FIG. 1 , where a second loss zone  107  is represented. When the drill pipe is equipped with several sensors at various depths, any fluid-velocity differences between various locations in the annulus would be detected. 
         [0045]    The location and severity of lost-circulation zones is then straightforward to detect. If no losses occur, the annular-flow rate is equal to the pump rate. The annular flow rate decreases at the depth of a lost-circulation zone. The identification of this flow-rate decrease provides two pieces of information: the depth of the loss zone and the severity of the losses. 
         [0046]      FIG. 2A  shows an arrangement of several fluid velocity sensors  301   a  placed around the tubular body  302 . Each sensor has a limited investigation area, but the set of several sensors allows covering the entire annular-flow area. Alternatively, a single sensor  301   b  placed on a rotating pipe ( FIG. 2B ) provides the same information. 
         [0047]    A typical application of the invention encompasses, for example, situations during which drilling is in progress, with the drilling fluid being pumped at a constant flow rate. At least one flow-rate sensor is measuring the annular flow rate at a given depth, and the measured flow rate is being compared in real-time with the pump rate. The measurement allows identifying potential losses in two zones—below or above the sensor. If several flow rate sensors (N) are placed at different depths along the drill string, these N measurements allow splitting the depth into N+1 depth zones while drilling. 
         [0048]    Another situation is when pumping is stopped, for instance during a connection. Any flow measured will be an indication of volume changes. Such changes are indications of losses or even gains. 
         [0049]    A further situation is when a tubular body is run into the wellbore, with no mud being pumped. As the tubular body is moving down, the measured flow rates should correspond to the drillstring velocity and metal volume being lowered in the hole. Deviation from this expected value will indicate losses due to, for instance, the surge pressure. 
         [0050]    In yet a further situation, the tubular body is pulled out of the hole and pumping is stopped. In this case, the measured flow rate should correspond to the pipe velocity and metal volume removed from the hole. Deviations from this behavior would be observed when a sensor goes crosses a loss zone or when formation fluids are entering the wellbore below the sensor, for instance because of transient swab pressure. 
         [0051]    The inventive methods and systems may be employed in any type of geologic formation, for example (but not limited to) reservoirs in carbonate and sandstone formations, and may be used to optimize the placement of treatment fluids, for example, to maximize wellbore coverage and diversion from high permeability and water/gas zones, to maximize their injection rate (such as to optimize Damkohler numbers and fluid-residence times in each layer), and their compatibility (such as ensuring correct sequence and optimal composition of fluids in each layer). 
         [0052]    The inventive method may also be useful for detecting leak locations in a tubular string, e.g., when there is a hole in an upper casing string when drilling fluid may flow into this annular space. Similarly, the inventive method might be used for detecting inflow (kicks, cross-flow) into the wellbore during drilling. 
         [0053]    As used herein, “oilfield” is a generic term including any hydrocarbon-bearing geologic formation, or formation thought to include hydrocarbons, including onshore and offshore. 
         [0054]    A “wellbore” may be any type of well, including, but not limited to, a producing well, a non-producing well, an experimental well, and exploratory well, and the like. Wellbores may be vertical, horizontal, some angle between vertical and horizontal, and combinations thereof, for example a vertical well with a non-vertical component.