Patent Grant
7448448
The invention generally relates to a system and method for facilitating the treatment of wells. For example, a well treatment may comprise the stimulation of an oilfield reservoir by injecting fluids into the reservoir. A variety of other well treatments also involve the flowing of fluids downhole.
In treating wells, a treatment fluid is routed downhole through a tubing and then expelled to the formation through a bottom hole assembly. However, a latency often exists between changes made by an operator at the surface and corresponding changes occurring downhole, particularly when those changes relate to changes in the fluids pumped through the tubing. Because the tubing is already full of fluid, any new fluid must be added above the column of fluid already existing in the tubing. For example, if sensors indicate a need for additional pre-flush acid before injection of stimulation acid, there is no convenient action that can be taken because the tubing has already been filled with the desired amount of well stimulation acid disposed above the pre-flush acid.
Additionally, the extreme length of the tubing in some applications creates substantial time delay between entrance of the fluid into the tubing at a surface location and exit of the fluid downhole. This substantial distance and time delay can create difficulties for the well operator in determining flow characteristics of the fluid or fluids as the fluid or fluids flow downhole and into the wellbore.
The present invention comprises a system and method used for optimization of well treatments. A series of staged fluids can be disposed within a tubing, such as coiled tubing, which is deployed in a wellbore. In at least some applications, a sensor system is used to detect one or more parameters related to the fluids moved downhole through the tubing. The technique facilitates improved control over the inflow of fluids into the well and optimization of the well treatment, both in amount and placement of fluid.
Certain embodiments of the invention will hereafter be described with reference to the accompanying drawings, wherein like reference numerals denote like elements, and:
In the following description, numerous details are set forth to provide an understanding of the present invention. However, it will be understood by those of ordinary skill in the art that the present invention may be practiced without these details and that numerous variations or modifications from the described embodiments may be possible.
The present invention relates to a system and methodology for optimizing treatment of a well. In one aspect, the latency effects of fluids pumped downhole are reduced by stacking or layering relatively small amounts of different fluids in sub-treatments or series within a tubing used to deliver the fluids to a desired location in a well. One or more series of fluid stages are selected for injection into a surrounding formation. After injecting the series of fluids, real-time data can be used through modeling for analysis to determine whether another series, e.g. a different series of fluids, is needed. This process can be repeated until adequate treatment of the well is completed. According to another aspect of the invention, well parameters, such as flow related data, are collected from one or more sensor locations in real time, and that data is used in modeling fluid flow to better enable optimization of the well treatment.
Referring generally to
Completion 22 is located within the interior of casing 30 and comprises a tubing 42 and a plurality of completion components, such as a bottom hole assembly 44 through which fluids can be injected from tubing 42 into wellbore 26 and the surrounding formation, as indicated by arrows 46. In this embodiment, well completion 22 also may comprise one or more packers 48 which can be set between tubing 42 and the surrounding casing 30 to isolate specific well zones for injection of fluid.
Various well parameters, such as a fluid flow parameters, can be detected by a sensor system 50 having one or more sensors 52 positioned at selected locations of well system 20. In the example illustrated, sensors 52 are deployed downhole, and data from the sensors is transmitted by a transmitting device 54 to a control system 56. Control system 56 may comprise a surface data acquisition system to receive and demodulate the transmitted data for use in, for example, a software interpretation product run on control system 56. The data can be transmitted via a communication line 58, such as a fiber optic line, wireline cable or other transmission line. Additionally, data signals can be transmitted wirelessly by device 54 via, for example, pressure pulses through the fluid or modulated electromagnetic waves sent upwards through the rock of reservoir 28. Sensors 52 can be used to detect a variety of well parameters that can be used to evaluate, for example, fluid flow and/or well conditions. Examples of parameters detected by sensors 52 include pressure, flow, temperature, resistivity and fluid density.
As discussed above, embodiments of the present invention are directed to injecting one or more series of fluid stages into the formation. Accordingly, control system 56 may include a visualization system to assist the user in identifying which fluid is exiting the tubing 42 at any given time, as well as advisor software, to recommend pump rates and rates at which the tubing 42 is moved. For example, in many applications it may be important to coordinate the motion of the tubing 42 along with the rate at which the fluid is pumped, so that a certain fluid stage reaches the end of the tubing not just at a specific time, but also at a specific location within the wellbore 26. This advisor software accounts for the fact that some of the fluid stages may be compressible, in which case the volume they take up within the tubing 42 varies with pressure. Downhole sensors 52 can convey the bottom hole data needed to perform this calculation. In addition to needing to estimate pressure along the tubing 42, the advisor software can account for the friction of the fluid stage as it passes along the tubing 42. This is often very difficult to determine in real-time because it can vary with the history of the use of the tubing 42 (what fluids were pumped before the job, how smooth is the interior of the tubing, etc). Consequently additional measurements may be required to determine which particular stage of fluid is exiting the tubing 42 at any given time. That information transmitted back to the advisor software can then be used to aid in the forecast of the arrival of subsequent stages to the end of the tubing.
In many applications, tubing 42 comprises coiled tubing deployed into wellbore 26 by a coiled tubing rig. Additionally, a fluid control system 60 is used to control the specific stages of fluids deployed into the coiled tubing 42. Fluid control system 60 can be a manual system run by an operator connecting appropriate hoses to dispense the desired fluids into tubing 42. However, the control system 60 also can be an automated system, such as a computer controlled system, that controls valving for dispensing the desired fluids into tubing 42 in a desired order, desired rate and in the desired amounts. For example, fluid control system 60 can be controlled by computer control system 56.
For each target treatment formation, the fluids may be loaded in sequence into the coiled tubing with an adequate amount of each stage, e.g. a pre-flush acid, a stimulation acid and a post-flush acid. Alternatively, the fluids may be loaded into tubing 42 in relatively small amounts in a specific order to carry out the desired well treatment, e.g. a reservoir stimulation. For example, instead of loading the coiled tubing 42 with the entire amount of pre-flush acid, followed by the entire amount of stimulation acid, followed by the entire amount of post-flush acid, the coiled tubing 42 may be loaded with consecutive series of the treatment fluids in much smaller amounts. This enables adjustment of the well treatment based on sensed parameters. If the sensors indicate a need for further treatment, additional series of the layered fluids can be injected as required to optimize the specific well treatment.
As illustrated in
The number of fluid stages 62 in each series 64 and the types of fluids used depends on the specific well treatment conducted. By way of example only, each series 64 may be designed for a well stimulation treatment and comprise a pre-flush acid (e.g. HCL in stage C), a stimulation acid (e.g. HF/HCL mix in stage B), a post-flush acid (e.g. HCL in stage A) and a spacer fluid (e.g. foam or brine in stage X). The spacer fluid generally does not affect the treatment operation but provides a “clean” interruption stage for stopping flow while well parameters are detected to determine whether additional series 64 are to be injected. The sensor system 50 also can be used to detect when fluid flowing through bottom hole assembly 44 is a spacer stage, thus providing an indication to the well operator of an opportune time to temporarily suspend the injection process. In some applications, fluid flow from the formation can be allowed at this time to facilitate detection of well related parameters by sensors 52, e.g. distribution of temperature along the wellbore. The sensor data aids in determining whether injection of additional series 64 is desired to optimize results of the well treatment. Upon receiving indication of optimal stimulation, the coiled tubing 42 can be pulled to another zone for repetition of the treatment.
An example of the treatment methodology is described with reference to the flowchart of
Following injection of the estimated number of series of fluid stages into the desired wellbore zone, sensors 52 can again be used to detect well related parameters indicative of whether the well treatment process has been optimized, as indicated by block 76. Well related parameters can be measured by stopping injection of fluid stages 62 at a spacer stage X to enable flow from the surrounding formation 38. However, other well parameters can be measured during flow of the fluid stages. The data obtained is again transmitted to control system 56 for analysis to determine the appropriate subsequent action, as indicated by block 78. The appropriate subsequent action can include, for example, injection of a single additional series 64 or further injection of a plurality of series 64 or simply increasing the pump rate. If the one or more packers 48 are not used in the bottom hole assembly, or if the one or more packers 48 are not set, the appropriate action may further include varying the velocity (speed and running direction) of coiled tubing 42. Alternately, the procedure can be concluded at that wellbore location, and bottom hole assembly 44 can be moved to the next formation, e.g. formation 40, for repetition of the treatment procedure. If the one or more packers 48 are used in the bottom hole assembly, movement of bottom hole assembly 44 may involve releasing the packer or packers 48 and lifting bottom hole assembly 44 via coiled tubing 42 to the desired location. However, other applications may not require packers 48. Upon completion of the injection procedures at all desired wellbore locations, system 22 can be removed from wellbore 26.
Referring generally to
In certain applications, e.g. wellbore cleaning applications, additional types of treating fluids can be pumped through coiled tubing 42. For example, a first type of fluid can be used for circulation purposes, while other types of fluids can be pumped downhole for cleaning purposes to remove different types of sand, scale or other contaminants. In such procedures, at least some of the fluid is returned upwardly through an annulus 84 surrounding tubing 42. Efficiency of the treatment procedure is improved by real time tracking of well parameters, such as parameters related to movement of fluids down through coiled tubing 42 and/or up through annulus 84. Efficiency of the treatment can also be improved by coordinating the movement of coiled tubing 42 and the flow of stage fluids 62 such that the desired fluids exit coiled tubing 42 at the desired well depth interval. A variety of other well applications also can benefit from real time tracking of staged fluids, including reservoir stimulation, hydraulic fracturing, coiled tubing drilling and other procedures involving the injected flow of fluids.
As further illustrated in
Control system 56 may be a processor based control system able to process data received from the various sensors for use in both displaying relevant information to a well operator and modeling fluid flow or other well characteristics. As illustrated in
The use of sensor system 50 and control system 56 enables a real-time fluid tracking and automated treatment integration such that information related to fluid within coiled tubing 42 and/or within annulus 84 can be used for optimization of the well treatment. The real-time data is obtained from sensors 52 and utilized in a simulation model for predicting characteristics of the actual well treatment. Additionally, sensors located downhole can be used to calibrate and/or provide real-time updating of the well treatment modeling to further optimize the treatment procedure.
Referring generally to the flowchart of
The simulation modeling can be used, for example, to calculate fluid pressure and track fluid interfaces inside the coiled tubing as the fluids travel downward and exit the coiled tubing. The same simulation model also can be used to simulate the upward flow of fluid through the annulus before exiting the wellbore at wellhead 34. Optionally, sensors 98 can be installed at the wellhead to measure return fluid properties, such as flow rate, pressure, temperature, density and sand concentration, as illustrated by block 116. By comparing the amount of fluid pumped into coiled tubing 42 with the amount of fluid returned to the wellhead, an estimation can be made of the amount of fluid entering the surrounding formation or the amount of fluid entering the wellbore from the formation. This data can be incorporated into the simulation model to enhance the prediction of fluid movement through the wellbore annulus. Use of the simulation model and its prediction of well parameters downhole enables adjustments to be made with respect to the input of fluid into tubing 42, thereby optimizing the effects of the well treatment. Also, a variety of the well parameters and modeling predictions can be presented on output device 108, e.g. through a graphical user interface, for viewing and analysis by a well operator.
Additionally, downhole sensors 96 can be used to better calibrate a given simulation model and its predictive capabilities. As illustrated in the flowchart of
Another embodiment utilizes the addition of distributed sensors 100, e.g. distributed temperature sensors, deployed along the wellbore. As illustrated in the flowchart of
By way of further example, in coiled tubing drilling or wellbore clean out procedures, it is important to know the minimum fluid velocity along the coiled tubing and/or wellbore. In such operations, fluid velocity in the wellbore during normal circulation or in the coiled tubing during reverse circulation is closely related to the fluid's ability to carry sand or drilling cuttings out of the wellbore. If the fluid velocity becomes lower than a critical velocity, known as “settling velocity,” efficiency of the procedure is severely reduced because the sand or cuttings cannot be efficiently circulated out of the area. With the use of sensors 52 and an accurate fluid modeling program, a well operator can be alerted when the minimal fluid velocity is close to the critical velocity. At such time, the operator can increase the operation pressure, and thus the flow rate, to avoid settling.
In the present embodiment, adjustments to the well treatment procedure based on sensor data and/or well modeling can be adjusted automatically by control system 56. Referring to
As the critical thresholds are approached, control system 56 automatically adjusts the procedure to avoid inefficiencies in operation. If, for example, a critical minimal fluid velocity is needed to maintain operating efficiency, the automated control system 56 can be designed to automatically increase pump rate when critical velocity is approached, as illustrated in block 138. The increase in pump rate ensures that the minimal fluid velocity along the wellbore never drops below the critical fluid velocity. In other operations, e.g. a fracturing operation, the pump rate can be adjusted automatically to change the maximum fluid velocity inside the coiled tubing to ensure that it is kept below a critical erosion velocity. In other applications, the coiled tubing speed control can be adjusted automatically to ensure that a specific fluid stage exits the bottom hole assembly at the same time the bottom hole assembly reaches a target depth, as illustrated by block 140. In yet other applications, the coiled tubing speed control or surface pump control can be adjusted automatically to ensure the optimal placement of fluid, as in a uniform sweep, or placement of a predetermined stage fluid over a predetermined formation. In still other applications, the type of fluid or the amount of fluid in the fluid stages can be adjusted automatically by fluid control system 60 under the direction of overall control system 56, as illustrated by block 142. Depending on the specific well treatment application, other automated controls over the procedure can be utilized to aid in optimizing the procedure.
Accordingly, although only a few embodiments of the present invention have been described in detail above, those of ordinary skill in the art will readily appreciate that many modifications are possible without materially departing from the teachings of this invention. Such modifications are intended to be included within the scope of this invention as defined in the claims.
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