Patent Application
20240401470
Hydrocarbon fluids are often found in hydrocarbon reservoirs located in porous rock formations below the surface of the Earth. Wells are drilled into the reservoirs to access and produce the hydrocarbon fluids. To monitor the well or reservoir condition and the hydrocarbon fluids extracted from the well, a permanent downhole measurement system (PDHMS) may be installed in the well. The PDHMS system may, generally, measure the pressure or temperature of the well or of the reservoirs. Other parameters to measure are flow rate and water cut (WC). However, traditionally, systems other than PDHMS, such as flow meters, may be used to measure flow rate and WC.
This summary is provided to introduce a selection of concepts that are further described below in the detailed description. This summary is not intended to identify key or essential features of the claimed subject matter, nor it is intended to be used as an aid in limiting the scope of the claimed subject matter.
This disclosure presents, in accordance with one or more embodiments, a method to measure flow rate and water cut (WC) of a well. The method includes: from a data set, for depths of two pressure gauges installed in the well, acquiring simulated pressures and corresponding simulated flow rates and simulated WCs; measuring pressures at the depths of the two pressure gauges via the two pressure gauges; comparing the measured pressures with the acquired simulated pressures, by calculating error values for the measured pressures with respect to the acquired simulated pressures; obtaining simulated flow rates and simulated WCs that correspond to the calculated error values not greater than a threshold; and averaging the simulated flow rates and simulated WCs that correspond to the simulated pressures that have the error values not greater than the threshold, to acquire an estimated flow rate and an estimated WC at the depths of the two pressure gauges. The method accordingly to one or more embodiments disclosed herein can estimate the flow rate and WC, in real time, using the pressure gauges or permanent downhole measurement system(s) (PDHMS).
In another aspect, this disclosure also presents, in accordance with one or more embodiments, a non-transitory computer readable medium (CRM) storing instructions for performing operation that measures flow rate and WC of a well. The operation includes: from a data set, for depths of two pressure gauges installed in the well, acquiring simulated pressures and corresponding simulated flow rates and simulated WCs; measuring pressures at the depths of the two pressure gauges via the two pressure gauges; comparing the measured pressures with the acquired simulated pressures, by calculating error values for the measured pressures with respect to the acquired simulated pressures; obtaining simulated flow rates and simulated WCs that correspond to the calculated error values not greater than a threshold; and averaging the simulated flow rates and simulated WCs that correspond to the simulated pressures that have the error values not greater than the threshold, to acquire an estimated flow rate and an estimated WC at the depths of the two pressure gauges.
Other aspects and advantages of the invention will be apparent from the following description and the appended claims.
Specific embodiments of the disclosed technology will now be described in detail with reference to the accompanying figures. Like elements in the various figures are denoted by like reference numerals for consistency. The sizes and relative positions of elements in the drawings are not necessarily drawn to scale. For example, the shapes of various elements and angles are not necessarily drawn to scale, and some of these elements may be arbitrarily enlarged and positioned to improve drawing legibility. Further, the particular shapes of the elements as drawn are not necessarily intended to convey any information regarding the actual shape of the particular elements and have been solely selected for ease of recognition in the drawing.
In the following detailed description of embodiments of the disclosure, numerous specific details are set forth in order to provide a more thorough understanding of the disclosure. However, it will be apparent to one of ordinary skill in the art that the disclosure may be practiced without these specific details. In other instances, well-known features have not been described in detail to avoid unnecessarily complicating the description.
Throughout the disclosure, ordinal numbers (e.g., first, second, third, etc.) may be used as an adjective for an element (i.e., any noun in the application). The use of ordinal numbers is not to imply or create any particular ordering of the elements nor to limit any element to being only a single element unless expressly disclosed, such as using the terms “before”, “after”, “single”, and other such terminology. Rather, the use of ordinal numbers is to distinguish between the elements. By way of an example, a first element is distinct from a second element, and the first element may encompass more than one element and succeed (or precede) the second element in an ordering of elements. In addition, throughout the disclosure, “or” is interpreted as “and/or,” unless stated otherwise.
The well (100) has three strings of casing: conductor casing (114), surface casing (116), and production casing (118). The casing strings are made of a plurality of long high-diameter tubulars threaded together. The tubulars may be made out of any durable material known in the art, such as steel. The casing strings are cemented in place within the well (100). The casing strings may be fully or partially cemented in place without departing from the scope of the disclosure herein.
Each string of casing, starting with the conductor casing (114) and ending with the production casing (118), decreases in both outer diameter and inner diameter such that the surface casing (116) is nested within the conductor casing (114) and the production casing (118) is nested within the surface casing (116). Upon completion of the well (100), the inner circumferential surface (120) of the production casing (118) and the space located within the production casing (118), make up the interior of the well (100).
The majority of the length of the conductor casing (114), surface casing (116), and production casing (118) are located underground. However, the surface-extending portion of each casing string is housed in the casing head (108), also known as a wellhead, located at the surface location (110). The surface-extending portion of each casing string may include a casing hanger (not pictured) that is specially machined to be set and hung within the casing head (108). There may be multiple casing heads (108) depending on the number of casing strings without departing from the scope of the disclosure herein.
Production tubing (122) is deployed within the production casing (118). The production tubing (122) may include a plurality of tubulars connected together and may be interspersed with various pieces of equipment such as artificial lift equipment, packers, etc. The space formed between the outer circumferential surface (124) of the production tubing (122) and the inner circumferential surface (120) of the production casing (118) is called the tubing-casing annulus (126).
The majority of the length of the production tubing (122) is located in the interior of the well (100) underground. However, the surface-extending portion of the production tubing (122) is housed in the tubing head (106) which is installed on top of the casing head (108). The surface-extending portion of the production tubing (122) may include a tubing hanger (not pictured) that is specially machined to be set and hung within the tubing head (106). The tree (102) is connected to the top of the tubing head (106) using the tubing bonnet (104). The tubing bonnet (104) is an adapter comprising one or more seals (not pictured).
In accordance with one or more embodiments, the production casing (118) may comprise a portion made of slotted casing or screen such that production fluids may flow into the production casing (118) from the formation. In other embodiments, the production casing (118) may include perforations made through the production casing (118), cement, and wellbore in order to provide a pathway for the production fluids (112) to flow from the production zone into the interior of the well (100).
The production fluids (112) may travel from the interior of the well (100) to the surface location (110) through the production tubing (122). A pipeline (not pictured) may be connected to the tree (102) to transport the production fluids (112) away from the well (100). The well (100) depicted in
In one or more embodiments, permanent downhole measurement systems (PDHMS) may be used for downhole measurement of oil wells. Traditionally, a PDHMS may include downhole gauges (i.e., sensors) that are connected to above-surface equipment, to monitor downhole well conditions. Communication between the downhole gauges and the above-surface equipment may be via wires, cables, optical fibers, etc. The downhole gauges of the PDHMS can measure downhole properties of the well. For example, the downhole gauges may be pressure gauges that can measure the pressure of the well or the pressure of the reservoirs. In another example, the downhole gauges may be optical fibers that can measure well or reservoir temperature.
One or more embodiments disclosed herein describe using two pressure gauges to estimate the total flow rate (hereinafter, will be referred to as “flow rate”) or water cut (WC) of oil wells. WC is the ratio of the water produced in the well to the volume of the total liquids produced. The two pressure gauges are installed in the well in a place for which the flow rate or WC is intended to be estimated. The two pressure gauges may belong to one or more PDHMSs, or may be standalone pressure gauges. In
In one or more embodiments, a hydraulic simulation model for the well is developed and calibrated to the characteristics of the well. The hydraulic simulation model uses a numerical method, such as finite element method (FEM), and some initial values for parameters such as well diameter, well layers, and earth layers to numerically simulate characteristics of the well such as pressure, WC, flow rate, temperature, etc., inside the well. The calibrated hydraulic simulation model may capture the current completion, the reservoir depth, flow rate, and WC, at the target depths where the two pressure gauges are installed in the well. The calibrated hydraulic simulation model also reflects the pressures at the location of the two pressure gauges.
Hydraulic simulation models are software that use multiple flow correlations to determine system parameters based on boundary conditions. As an example, a hydraulic simulation model of a well can be built by specifying the well total depth, type of completion, well tubing size, casing size, reservoir pressure and temperature, production index (P1), and surface equipment such as the choke and flowline size. The boundary conditions can be the parameters of the system at both ends of the flow. The flow starts from the well (starting point) and goes to the gas oil separation plant (GOSP). An example of the boundary conditions can be specifying well reservoir pressure and GOSP operating pressure. The output of the hydraulic simulation model can be simulated pressures across all points and flow rates (oil, water, and gas) based on the boundary conditions, the physical equipment (inside the well and above the earth surface), and the type of correlation chosen.
For calibrating a hydraulic simulation model based on a specific well, initially several parameters of the well will be entered in the hydraulic simulation model, such as the physical equipment installed in the well (tubing, casing, wellhead, etc.) in addition to the type of the well (e.g., horizontal or vertical) and other parameters. In addition, surface parameters such as flowline size and choke size are added to the hydraulic simulation model. Once these steps are completed, data is collected from the well to be used for calibrating the hydraulic simulation model. The data may include the flow rate of the well (oil, gas, and water) and wellhead pressure. Based on the collected data, the production index (P1) of the well can be estimated. This can be one way of calibrating the hydraulic simulation model based on a specific well, in accordance with one or more embodiments disclosed herein.
In one or more embodiments, by using two pressure gauges (or PDHMS gauges), the calibrated hydraulic simulation model, and Equation 1, which is Bernoulli equation, the flow rate and WC can be estimated.
In Equation 1, p is fluid density, g is acceleration (e.g., due to gravity), P1 is pressure of the fluid at elevation 1, v1 is velocity of the fluid at elevation 1, h1 is height of elevation 1, P2 is pressure of the fluid at elevation 2, v2 is velocity of the fluid at elevation 2, and h2 is height at elevation 2.
In one or more embodiments, the estimation of the flow rate and WC is for the condition when the pressure of the hydrocarbon fluid is above the bubble point pressure of the hydrocarbon fluid. The bubble point pressure is the pressure at which the first bubble of gas comes out from the hydrocarbon fluid, at a given temperature. In one or more embodiments, the bubble point pressure is the pressure at the bubble point depth (132) discussed above with respect to
In one or more embodiments, it is assumed that the two pressures, P1 and P2, are comparable, and both phases, namely water and oil, have low compressibility. The low compressibility may be considered as v1≈v2. In one or more embodiments, Equation 1 can be simplified based on conservation of energy between energies at two points (point 1 corresponding to P1 and point 2 corresponding to P2). Specifically, P1 is the pressure at one depth while P2 is the pressure at another depth. The total energy (including pressure, kinetic, and hydrostatic) at point 1 should be equal to the total energy at point 2 plus some friction losses. Because water and oil have low compressibility in fluid form (especially that the two pressure points are not too high), the density term ρ can be considered constant at both points. The other assumption is that at the two points the cross sectional area of the well tubing is the same (this is usually the case in oil wells). Mass conservation principle dictates that whatever mass flows through point 1 must also flow through point 2. Otherwise, there will be an accumulation of matter. Because the density is the same at both points, the flow rate can be considered equal at both points and the velocity can also be considered equal at both points. Therefore, based on these assumptions, Equation 1 can be simplified to Equation 2.
In one or more embodiments, the losses in the pipe (losses (ρ,v)) may be divided into two components: hydraulic losses; and frictional losses. The hydraulic losses are a function of the fluid density (or pressure gradient), and the frictional losses are a function of the fluid density and velocity. The hydraulic and frictional losses can be determined via the calibrated hydraulic simulation model.
In accordance with one or more embodiments, when the calibrated hydraulic simulation model is developed or acquired, a sensitivity analysis is run using the calibrated hydraulic simulation model to capture flow rates and WCs at the location of the two pressure gauges. To summarize, in accordance with one or more embodiments, the sensitivity analysis is conducted as follows. A calibrated hydraulic simulation model is acquired. The calibration is done at one flow rate corresponding to one choke. After adjusting the choke, the flow rate from the well will change. At this point the sensitivity analysis can be conducted. For this, new PDHMS pressure data is collected. The calibrated hydraulic simulation model can be used to generate many cases of flow parameters of the well. The calibrated hydraulic simulation model is given flow rate in different range (e.g., 1000, 1100, 1200, or 2000 barrel per day (bbl/d)). In addition, the WC can be varied as a range of for example 0, 10%, 20%, to 90%. The two ranges of flow rate and WCs are crossed. For example, if 10 cases of flow rates and 10 cases of WCs are given, the crossing result would be 10×10=100 simulated cases. The number of these cases are referred to as N. The result from the model are simulated pressures at the depths of the two PDHMS gauges. The difference between the simulated and measured (actual) pressures are used in the error formula given further below in Equation 3. Each of the simulated cases (e.g., 100 cases) is given an error value with respect to the measured pressures and are sorted based on the lowest error value. Further, the top n simulated cases are considered for the final estimated flow rate and WC. This may be done by taking the mean or median of the n cases. The size of n can be chosen relative to the size of the simulated cases N. This process is described below in more detail.
The simulated pressures include pairs of pressure data with respect to the two pressure gauges. The sensitivity analysis, in general, may determine how different values of one or more independent variables affect one or more dependent variables under predetermined conditions. In one or more embodiments, the sensitivity analysis may be augmented by interpolating between the points of the simulated pressures, simulated flow rates, and/or simulated WCs. The interpolation allows for higher coverage for these parameters, and more accurate predictions of the flow rate and WC.
In one or more embodiments, a stream of pressure data at the two pressure gauges, which is measured by the two pressure gauges, is acquired. The measurement may occur when hydrocarbon flow in the well is stabilized. The measuring and acquiring of the stream of pressure data may be in real-time. Then, the measured pressures are compared against the simulated pressures obtained from the calibrated hydraulic simulation model, to find the simulated pressures that are closer, in values, to the measured pressures. The comparison may be done by calculating an error value for each pair of simulated pressures (for the two pressure gauges) with respect to the pair of measured pressures, at different simulated flow rates and simulated WCs. For the comparison, as one example, following Equation 3 may be used. In Equation 3, the lesser the value of error, the closer the pair of simulated pressures (P1 and P2) to the pair of measured pressures (Pmes1 and Pmes2).
In Equation 3, Pmes1 and Pmes2 are the measured pressures at pressure gauge 1 and pressure gauge 2, respectively, among the two pressure gauges (104 and 106). And P1 and P2 are the simulated pressures at the locations of pressure gauge 1 and pressure gauge 2, respectively.
In one or more embodiments, the simulated pressures and their corresponding simulated flow rates and simulated WCs may be sorted based on the value of the error. For example, the simulated pressures and their corresponding simulated flow rates and simulated WCs may be sorted in a table from top to bottom based on the error values corresponding to the simulated pressures and their corresponding simulated flow rates and simulated WCs being smaller toward the top. In one or more embodiments, the best n points for the simulated flow rates and simulated WCs, that correspond to the smallest error values, may be averaged to obtain estimated flow rate and WC. In one or more embodiments, n may depend on the size of the sensitivity analysis conducted.
In one or more embodiments, using the above approach, the flow rate and WC could be estimated, via the pressure gauges and the calibrated hydraulic simulation model, with high accuracy even after adding temperature noise at the locations of the pressure gauges. For example, following Table 1 shows the result of running the above-described analysis on flow rate of 3000 and WC of 45%. Table 1 is sorted based on the least error value corresponding to the first row of the table.
In Step 200, two pressure gauges are installed inside the well, both at depths below (i.e., deeper than) the bubble point depth of the hydrocarbon fluid. The pressure gauges may be standalone gauges, or may be gauges of a PDHMS. The PDHMS may include other gauges to measure other characteristics of the well, such as temperature. Installation of the pressure gauges are described above with reference to
In Step 210, a calibrated hydraulic simulation model is developed or acquired for the well. From the calibrated hydraulic simulation model, a data set including completion, reservoir depths, simulated flow rates, simulated WCs, and simulated pressures that correspond to the simulated flow rates and simulated WCs are acquired. The data set of the calibrated hydraulic simulation model is calibrated to criteria of the well, to for example, capture current completion, reservoir depth, and flow rate and WC at the depths of the two pressure gauges. For example, the hydraulic simulation model is calibrated to reflect simulated pressures at the locations of the two pressure gauges at various simulated flow rates and simulated WCs.
In Step 220, from the data set, and for the depths of the two pressure gauges, simulated pressures and corresponding simulated flow rates or simulated WCs are acquired. For example, as described above, a sensitivity analysis may be run using the calibrated hydraulic simulation model to capture the simulated pressures at the gauges at different simulated flow rates and simulated WCs.
In Step 230, the acquired simulated pressures, at the depths of the two pressure gauges, and/or the corresponding simulated flow rates and simulated WCs may be interpolated. This allows higher coverage of data points for the simulated pressures, simulated flow rate, and simulated WC.
In Step 240, the pressures at the depths of the two pressure gauges are measured via the two pressure gauges.
In Step 250, the measured pressures are compared with the acquired simulated pressures. For this, error values for the measured pressures may be calculated with respect to the acquired simulated pressures (i.e., simulated pressure values), at the depths of the pressure gauges, that correspond to the simulated flow rates and simulated WCs. For example, the error values may be calculated as described above with reference to Equation 3. Specifically, the two pressure gauges include a first pressure gauge and a second pressure gauge. For example, the first pressure gauge and the second pressure gauge may respectively be the pressure gauges (128, 130) described above with respect to
In Step 260, the acquired simulated flow rates and simulated WCs are sorted based on the calculated error values. Because each of the simulated pairs of pressures, which corresponds to the pressures at the two pressure gauges, corresponds to a simulated flow rate and to a simulated WC, the simulated flow rates or the simulated WCs can be sorted based on the calculated error values. Table 1, which is shown above, shows an example of the sorting step. In one or more embodiments, the acquired simulated pressures may be sorted based on the calculated error values.
In Step 270, the simulated flow rates and simulated WCs that correspond to the error values not greater than a threshold are obtained.
In Step 280, the simulated flow rates and simulated WCs that correspond to the error values not greater than the threshold are averaged, to acquire an estimated flow rate and an estimated WC at the depths of the two pressure gauges. To this end, the best n points, which correspond to the least calculated error values, of the sorted simulated flow rates and simulated WCs may be selected. Then, the best n points of the sorted simulated flow rates and simulated WCs may be averaged to acquire the estimated flow rate and estimated WC at the locations of the two pressure gauges.
One or more embodiments disclosed herein for estimating the flow rate or WC, for example with reference to
An example of the computer system is described with reference to
The computer (302) can serve in a role as a client, network component, a server, a database or other persistency, or any other component (or a combination of roles) of a computer system for performing the subject matter described in the instant disclosure. The illustrated computer (302) is communicably coupled with a network (330). In some implementations, one or more components of the computer (302) may be configured to operate within environments, including cloud-computing-based, local, global, or other environment (or a combination of environments).
At a high level, the computer (302) is an electronic computing device operable to receive, transmit, process, store, or manage data and information associated with the described subject matter. According to some implementations, the computer (302) may also include or be communicably coupled with an application server, e-mail server, web server, caching server, streaming data server, business intelligence (BI) server, or other server (or a combination of servers).
The computer (302) can receive requests over network (330) from a client application (for example, executing on another computer (302)) and responding to the received requests by processing the said requests in an appropriate software application. In addition, requests may also be sent to the computer (302) from internal users (for example, from a command console or by other appropriate access method), external or third-parties, other automated applications, as well as any other appropriate entities, individuals, systems, or computers.
Each of the components of the computer (302) can communicate using a system bus (303). In some implementations, any or all of the components of the computer (302), both hardware or software (or a combination of hardware and software), may interface with each other or the interface (304) (or a combination of both) over the system bus (303) using an application programming interface (API) (312) or a service layer (313) (or a combination of the API (312) and service layer (313)). The API (312) may include specifications for routines, data structures, and object classes. The API (312) may be either computer-language independent or dependent and refer to a complete interface, a single function, or even a set of APIs. The service layer (313) provides software services to the computer (302) or other components (whether or not illustrated) that are communicably coupled to the computer (302). The functionality of the computer (302) may be accessible for all service consumers using this service layer (313). Software services, such as those provided by the service layer (313), provide reusable, defined business functionalities through a defined interface. For example, the interface may be software written in JAVA, C++, Python, or other suitable language providing data in extensible markup language (XML) format or another suitable format. While illustrated as an integrated component of the computer (302), alternative implementations may illustrate the API (312) or the service layer (313) as stand-alone components in relation to other components of the computer (302) or other components (whether or not illustrated) that are communicably coupled to the computer (302). Moreover, any or all parts of the API (312) or the service layer (313) may be implemented as child or sub-modules of another software module, enterprise application, or hardware module without departing from the scope of this disclosure.
The computer (302) includes an interface (304). Although illustrated as a single interface (304) in
The computer (302) includes at least one computer processor (305). Although illustrated as a single computer processor (305) in
The computer (302) also includes a memory (306) that holds data for the computer (302) or other components (or a combination of both) that can be connected to the network (330). For example, memory (306) can be a database storing data consistent with this disclosure. In one example, memory (306) may store the calibrated hydraulic simulation model described above in accordance with one or more embodiments. In other examples, memory (306) may store algorithms required for performing sensitivity analysis with respect to Equation 1, Equation 2, and Equation 3 described above in accordance with one or more embodiments. Although illustrated as a single memory (306) in
The application (307) is an algorithmic software engine providing functionality according to particular needs, desires, or particular implementations of the computer (302), particularly with respect to functionality described in this disclosure. For example, the application (307) can serve as one or more components, modules, applications, etc. In one example, the application (307) may include the calibrated hydraulic simulation model described above in accordance with one or more embodiments. In other examples, the application (307) may include algorithms to perform sensitivity analysis with respect to Equation 1, Equation 2, and Equation 3 described above in accordance with one or more embodiments. Further, although illustrated as a single application (307), the application (307) may be implemented as multiple applications (307) on the computer (302). In addition, although illustrated as integral to the computer (302), in alternative implementations, the application (307) can be external to the computer (302). In one example, the method described with reference to
There may be any number of computers (302) associated with, or external to, a computer system containing computer (302), each computer (302) communicating over network (330). Further, the term “client,” “user,” and other appropriate terminology may be used interchangeably as appropriate without departing from the scope of this disclosure. Moreover, this disclosure contemplates that many users may use one computer (302), or that one user may use multiple computers (302). Furthermore, in one or more embodiments, the computer (302) is a non-transitory computer readable medium (CRM).
Although only a few example embodiments have been described in detail above, those skilled in the art will readily appreciate that many modifications are possible in the example embodiments without materially departing from this invention. Accordingly, all such modifications are intended to be included within the scope of this disclosure as defined in the following claims.
