Patent Description:
It is commonplace for a well that produces hydrocarbons trapped in tight reservoirs to be partitioned into a number of intervals (also referred to as stages or zones) spaced along the length of the well. Short sections of unperforated production tubing (such as liner or casing sections) can be located between intervals to support isolation of the respective intervals. During well completion, hydraulic fracturing operations can be carried out over the intervals of the well. The hydraulic fracturing operations direct fracturing fluid under high pressure through fracturing sleeves or liner/casing perforations into the adjacent formation, which causes fracturing of the reservoir rock of the adjacent formation that is intended to release oil or gas trapped in the reservoir rock such that it flows into the well for easier production. The fracturing fluid typically contains a proppant (such as sand) that aids in holding the fractures open after the fracturing application has been completed.

Note that not all intervals of the well can contribute equally to the production of hydrocarbons from the well as the petrophysical and geomechanical properties of the reservoir can vary along the length of the well. Current workflows used to evaluate the productivity of individual intervals of the well are based on two main techniques. The first technique, commonly described as production logging, is based on the downhole measurements of fluid rates using spinners and pressure measurement. This first technique requires a production logging tool to be run in the well, thus increasing the cost of the well. The second technique is based on the measurement of tracer concentration. Different tracers are injected into the reservoir with the fracturing fluid over the intervals of the well. The tracers are produced from well with the fracturing fluid and/or hydrocarbons during the initial production of the well. The amount of each given tracer that is produced is a function of the flow contribution of the respective interval in which the given tracer was placed. The use of the multiple different tracers allows for the evaluation of the flow contributions over the number of intervals of the well. Beyond the limitation inherent to the interpretation of the produced fluids (including the tracers, the fracturing fluid and/or hydrocarbons), this second technique has a limitation in the number of tracers that can be placed into the intervals of a single well as well as the detection of the tracers in the produced fluids. <CIT> discloses a mathematical modelling method utilizing pressure and flow rate measurements obtained downhole. <CIT> is concerned with mathematical modelling utilising borehole and separator data. <CIT> discloses a production well control system in which down hole tools are controlled automatically based on input from downhole sensors. <CIT>, <CIT>, <CIT>, <CIT>, <CIT> and <CIT> describe a system and method to measure a characteristic of a produced fluid using a sensor/flowmeter and deriving properties of the fluid. In <CIT>, measurement of the fluid characteristic may be obtained with a downhole flowmeter.

The present disclosure provides a method for characterizing a hydraulically-fractured hydrocarbon-bearing formation that is traversed by a well partitioned into a number of intervals from which production tubing gives fluid communication to a surface-located facility. The method comprises:.

characterized in that the flow characteristics of produced fluid are surface flow characteristics of the produced fluid that flows from the well back to the surface-located facility, and in that the surface flow characteristics of the produced fluid include flow rates for different phases of the produced fluid and are measured by a surface-located multiphase flow meter. Thus the method can characterize local formation properties for one or more intervals (or other sections) of the well.

A method may employ a downhole tool to open (or close) a set of one or more fracturing sleeves of the well. After opening or closing the set of one or more fracturing sleeves of the well, surface flow characteristics of produced fluid that flows from the well back to a surface-located facility can be analyzed. At least one local formation property that characterizes the hydraulically-fractured formation adjacent the set of one or more fracturing sleeves of the well can be derived based on such surface flow characteristics.

In embodiments, the surface flow characteristics of the produced fluid can be analyzed to determine at least one flow contribution that flows through the set of one or more fracturing sleeves of the well, and such flow contribution can be used to derive the at least one local formation property that characterizes the hydraulically-fractured formation adjacent the set of one or more fracturing sleeves of the well.

In further embodiments, the surface flow characteristics of the produced fluid can be analyzed together with downhole pressure measurements of the produced fluid in order to determine at least one flow contribution that flows through the set of one or more fracturing sleeves of the well. Modeling and nodal analysis can be used to analyze the surface flow characteristics of the produced fluid and the downhole pressure measurements of the produced fluid in order to determine the at least one flow contribution that flows through the set of one or more fracturing sleeves of the well.

In yet further embodiments, the at least one local formation property that characterizes the hydraulically-fractured formation adjacent the set of one or more fracturing sleeves of the well can be evaluated in order to determine whether to selectively close (or open) the set of one or more fracturing sleeves of the well. In the event that the at least one local formation property that characterizes the hydraulically-fractured formation adjacent the set of one or more fracturing sleeves of the well provides an indication of a depleted formation or formation or well damage or other suitable condition, the set of one or more fracturing sleeves of the well can be closed if open or remain closed if closed. Otherwise, the set of one or more fracturing sleeves of the well can be opened if closed or remain open if opened.

The operations may be repeated for at least one additional set of one or more fracturing sleeves of the well in order to derive at least one local formation property that characterizes the hydraulically-fractured formation adjacent the at least one additional set of one or more fracturing sleeves of the well.

A method may employ a downhole packer to isolate a set of one or more well intervals that are upstream from the packer from one or more well intervals that are downstream from the packer. In this configuration, the set of one or more well intervals that are upstream from the packer are in fluid communication with a surface facility, while the one or more well intervals downstream from the packer are fluidly isolated and decoupled from the surface facility. After isolating the set of one or more well intervals that are upstream from the packer, surface flow characteristics of produced fluid that flows from the well back to the surface-located facility can be analyzed, and at least one local formation property that characterize the hydraulically-fractured formation adjacent the set of one or more well intervals that are upstream from the packer can be derived based on such surface flow characteristics.

In embodiments, the surface flow characteristics of the produced fluid can be analyzed to determine at least one flow contribution that flows through the set of one or more well intervals that are upstream from the packer, and such flow contribution can be used to derive the at least one local formation property that characterizes the hydraulically-fractured formation adjacent the set of one or more well intervals that are upstream from the packer.

In further embodiments, the surface flow characteristics of the produced fluid can be analyzed together with downhole pressure measurements of the produced fluid in order to determine at least one flow contribution that flows through the set of one or more well intervals that upstream from the packer. Modeling and nodal analysis can be used to analyze the surface flow characteristics of the produced fluid and the downhole pressure measurements of the produced fluid in order to determine the at least one flow contribution that flows through the set of one or more well intervals that are upstream from the packer.

In yet further embodiments, the at least one local formation property that characterizes the hydraulically-fractured formation adjacent the set of one or more well intervals that are upstream from the packer can be evaluated in order to determine whether to selectively seal the set of one or more well intervals that upstream from the packer by the application of a sealing agent.

The operations can be repeated to isolate at least one additional set of one or more well intervals in order to derive at least one local formation property that characterizes the hydraulically-fractured formation adjacent the at least one additional set of one or more well intervals.

A method may employ a data analyzer that analyzes surface flow characteristics of produced fluid that flows from the well to the surface-located facility over time in order to detect slug flow in the produced fluid and determine properties of such slug flow. The data analyzer can analyze the properties of the flow (such as amplitude, frequency and period characteristic of the slug flow) or the surface flow characteristics of produced fluid over time to determine one or more well intervals that contribute to such slug flow. The data analyzer can store data in computer memory that identifies the one or more well intervals that contribute to such slug flow.

In one embodiment, the data analyzer can be a transient multiphase wellbore flow simulator that analyzes the properties of such slug flow or the surface flow characteristics of produced fluid over time to determine one or more well intervals that contribute to such flow.

In further embodiments, the transient multiphase wellbore flow simulator can derive a solution using properties of the flow (including individual phase flowrates observed at the surface) as input data, calculate a wellbore volume from the solution, and estimate properties (such as location, cross-section and the total length) of the well interval that contributes to the flow based on the wellbore volume.

In still further embodiments, the transient multiphase wellbore flow simulator can determine individual phase flow rates at the surface together with other determined parameters (such as downhole pressure(s), well-head pressure(s)), other fluid properties, etc.) for varying geometrical properties of the well, compare these determined parameters for the varying geometrical properties of the well to corresponding measured parameters to determine whether a sufficient match is obtained, estimate the geometry of the well when the sufficient match is obtained, and estimate properties (such as location, cross-section and the total length) of the well interval that contributes to the slug flow based on the estimated geometry of the well.

In some embodiments a method may include locating a downhole tool in a particular well interval where the downhole tool circulates fluid for clean out of the particular well interval. Surface flow characteristics of produced fluid that flows from the well back to a surface-located facility are analyzed. At least one property that characterize solids production from the particular well interval is derived based on such surface flow characteristics.

The at least one property can characterize solids production from fractures that are in fluid communication with a particular sliding sleeve. The at least one property can further characterize a profile of solids production from fractures that are in fluid communication with a number of sliding sleeves of the well.

The at least one property can also characterize deposited solids that are near a particular sliding sleeve. The at least one property can further characterize a profile of deposited solids that are near a number of sliding sleeves of the well.

In these methods the surface flow characteristics of the produced fluid are measured by a surface-located multiphase flow meter. The surface flow characteristics of the produce fluid can include flow rates for different phases of the produced fluid. The different phases of the produced fluid can be selected from the group consisting of: an oil phase, a gas phase, a water phase and a solid phase.

Certain examples are shown in the above-identified figures and described in detail below. In describing these examples, like or identical reference numbers are used to identify common or similar elements. The figures are not necessarily to scale and certain features and certain views of the figures may be shown exaggerated in scale or in schematic for clarity and/or conciseness.

"Above", "upper", "upstream", "heel" and like terms in reference to a well, wellbore, tool, or formation refer to the relative direction or location near or going toward or on the surface side of the device, item, flow or other reference point, whereas "below", "lower", "downstream", "toe" and like terms refer to the relative direction or location near or going toward or on the bottom hole side of the device, item, flow or other reference point, regardless of the actual physical orientation of the well or wellbore, e.g., in vertical, horizontal, downwardly and/or upwardly sloped sections thereof.

As used herein, an open interval or open well interval refers to a section of a well with at least one perforation, perforation cluster, a jetted hole in the casing, a slot, at least one sliding sleeve or wellbore casing valve, or any other opening in the production tubing that provides communication between the formation and the wellbore.

As used herein, a fracture shall be understood as one or more cracks or surfaces of breakage within rock. Fractures can enhance permeability of rocks greatly by connecting pores together, and for that reason, fractures are induced hydraulically in some reservoirs in order to boost hydrocarbon flow. Fractures may also be referred to as natural fractures to distinguish them from fractures induced as part of a reservoir stimulation.

The term "fracturing" refers to the process and methods of breaking down a geological formation and creating a fracture, i.e. the rock formation around a well bore, by pumping fluid at very high pressures (pressure above the determined closure pressure of the formation), in order to increase production rates from a hydrocarbon reservoir. The fracturing applications described herein otherwise use conventional techniques known in the art.

<FIG> shows an example well <NUM> that has undergone hydraulic fracturing applications. In this well, a platform and derrick <NUM> is positioned over a wellbore <NUM> that may be formed in the hydrocarbon-bearing reservoir <NUM> by rotary drilling. While certain elements of the well <NUM> are illustrated in <FIG> and <FIG>, other elements of the well (e.g., blow-out preventers, wellhead, wellhead "tree", etc.) have been omitted for clarity of illustration. The well <NUM> also includes vertical casing <NUM> cemented to the wellbore <NUM>, a transition <NUM>, and production tubing <NUM> that extends along the horizontal section of the well <NUM> and is cemented to the wellbore <NUM>. The production tubing <NUM> includes a number of fracturing sleeves <NUM> that are offset from one another along the horizontal section. The production tubing <NUM> can include horizontal casing and/or production liner sections disposed between the fracturing sleeves <NUM> and cemented to wellbore <NUM>. The vertical casing <NUM> terminates at a casing head (not shown) at or near the platform and derrick <NUM> and the surface facility (<FIG>) at the surface <NUM>. The fracturing sleeves <NUM> have radial openings or ports <NUM> that can be configured in an open configuration or a closed configuration. The open configuration of a respective port <NUM> allows fluid communication between the hydraulically fractured hydrocarbon-bearing reservoir or formation <NUM> and the interior space of the fracturing sleeve <NUM>. The closed configuration of a respective port <NUM> occludes or blocks fluid communication between the hydraulically-fractured hydrocarbon-bearing formation <NUM> and the interior space of the fracturing sleeve <NUM>. The fracturing sleeves <NUM> can be located as part of predetermined well intervals that correspond to desired production zones of the hydrocarbon-bearing formation <NUM>. The number of fracturing sleeves <NUM> for the respective well intervals can be the same or vary over the respective well intervals. For example, a first well interval having one or more fracturing sleeves can traverse one production zone of the hydrocarbon-bearing formation <NUM> while a second well interval having one or more fracturing sleeves can traverse another production zone of the hydrocarbon-bearing formation <NUM>. The number of fracturing sleeves for the first and second well intervals can be the same or be different from one another.

A bottom hole assembly ("BHA") <NUM> may be run inside the casing <NUM> and production tubing <NUM> (including the fracturing sleeves <NUM>) by tubing <NUM> (which can be coiled tubing or drill pipe). The means for conveying the tubing <NUM> and the BHA <NUM> inside the casing <NUM> and the production tubing can be provided at the surface <NUM> or by a downhole mechanism (such as a downhole tractor) as is well known. The BHA <NUM> is a shifting tool that can conveyed within the production tubing <NUM> and configured to engage any one of the fracturing sleeves <NUM>. In the engaged configuration, the shifting tool can be operated to configure the ports of the engaged fracturing sleeve in the open configuration or closed configuration as needed.

<FIG> illustrate an embodiment of one fracturing sleeve <NUM>. Turning to <FIG>, the fracturing sleeve <NUM> has a substantially elongate cylindrical outer casing <NUM> extending between first and second ends <NUM> and <NUM>, respectively and having a central passage <NUM> therethrough. The first and second ends <NUM>, <NUM> of the outer casing <NUM> have threaded interfaces for connection to an adjacent casing/liner section or to the outer casing <NUM> of another fracturing sleeve <NUM>. The fracturing sleeve <NUM> further includes a central portion <NUM> having a plurality of raised sections <NUM> (for example, three raised sections) extending parallel to the central axis <NUM> of the outer casing <NUM> along the lengthwise extent of the central portion <NUM>. The raised sections <NUM> are spaced radially from one another about the outer circumference of the central portion <NUM> with elongate channels <NUM> disposed therebetween. Each raised section <NUM> supports a port body <NUM> having an aperture <NUM> extending therethrough. The aperture <NUM> extends from the exterior to the interior central passage <NUM> of the fracturing sleeve <NUM>. Additionally, the port body <NUM> is radially extendable from central portion <NUM> so as to center the fracturing sleeve <NUM> within the wellbore <NUM> and engage the wellbore <NUM>. The port bodies <NUM> and apertures <NUM> of the fracturing sleeve <NUM> correspond to the ports <NUM> of the fracturing sleeve <NUM> of <FIG>.

Turning now to <FIG> and <FIG>, a sliding sleeve <NUM> is supported within the central passage <NUM> of the outer casing <NUM> at an axial location corresponding to port bodies <NUM>. The sliding sleeve <NUM> can slide axially within the central passage <NUM> between two positions: a closed position as shown in <FIG> and an open position as shown in <FIG>. In the closed position, the sliding sleeve <NUM> sealably covers the apertures <NUM> of the port bodies <NUM> so as to hydraulically isolate the interior central passage <NUM> from the exterior of the fracturing sleeve <NUM>. In the open position, the sliding sleeve <NUM> leaves open the apertures <NUM> of the port bodies <NUM> so as to provide a fluid passageway between the interior central passage <NUM> and the exterior of the fracturing sleeve <NUM>. The sliding sleeve <NUM> can include annular seals <NUM> that maintain a fluid tight seal between the sliding sleeve <NUM> and the interior of the outer casing <NUM> in the closed configuration where the sliding sleeve sealably covers the apertures <NUM> of the port bodies <NUM>. A snap ring <NUM> can be disposed in an annular groove <NUM> disposed on the outer surface of the sliding sleeve <NUM> and facing the inner surface of the outer casing <NUM>. The snap ring <NUM> engages a first annular groove <NUM> formed in the inner surface of the outer casing <NUM> in the open position and engages a second annular groove <NUM> formed in the inner surface of the outer casing <NUM> in the closed position. The second annular groove <NUM> is offset from the first annular groove <NUM> in a position closer to the apertures <NUM>.

Turning now to <FIG>, a shifting tool <NUM> is illustrated within the central passage <NUM> of the outer casing <NUM> of the fracturing sleeve <NUM>. The shifting tool <NUM> is adapted to engage the sliding sleeve <NUM> and shift it between the closed position as illustrated in <FIG> and <FIG> and the open position illustrated in <FIG>. The shifting tool <NUM> comprises a substantially cylindrical elongate tubular body <NUM> that defines a central bore therethrough to receive an actuator or to permit the passage of fluids and other tools therethrough. The shifting tool <NUM> includes at least one sleeve engaging member radially extendable from the tubular body <NUM> so as to be selectably engageable with the sliding sleeve <NUM> and shift the position of the sliding sleeve <NUM>. In operation, a fluid pressure applied to the central bore of the shifting tool can extend the sleeve engaging member(s) for engagement with the sliding sleeve <NUM>. With the sleeve engaging member(s) engaged with the sliding sleeve <NUM>, axial movement of the shifting tool <NUM> can move the sliding sleeve <NUM> from the open to closed position or vice versa. The uphole end of the tubular body <NUM> of the shifting tool <NUM> can include threaded interface for connection to the tubing <NUM> or other upstream tools. The downhole end of the tubular body <NUM> of the shifting tool <NUM> can include threaded interface for connection to other downstream tools.

Additional details of the fracturing sleeve <NUM> and shifting tool <NUM> of Figures IB - IE are described in U. Patent Publ. No. <CIT> to Grant, commonly assigned to assignee of the present application.

As shown in <FIG>, the surface facility <NUM> includes a well-head choke <NUM>, a multiphase flow meter <NUM>, fluid separation and storage stage <NUM>, and a data analyzer <NUM>. One or more optional downhole pressure sensor(s) <NUM> may also be included. The downhole pressure sensor(s) <NUM> can be integral to the shifting tool BHA <NUM>, the tubing <NUM> that is used to run in the shifting tool BHA <NUM>, the production tubing <NUM>, the fracturing sleeves <NUM>, or some other part of the well completion. Produced fluid <NUM> can flow from the production tubing <NUM> of the horizontal section uphole through the annulus between the tubing <NUM> and the vertical casing <NUM> (or possibly through a return flowpath provided by the tubing <NUM> itself). At the surface, the produced fluid <NUM> flows from the platform <NUM> through the multiphase flow meter <NUM> for separation into various phases (solids, oil, gas, water) and storage by the fluid separation and storage stage <NUM>. The multiphase flow meter <NUM> can be configured to measure the flow rates of different phases (e.g., oil, gas, water, solids) that make up the produced fluid <NUM> that returns to the surface. The oil and gas phases of the produced fluid <NUM> can originate from hydrocarbons that flow from the hydraulically-fractured formation <NUM> through open ports <NUM> of the fracturing sleeves <NUM> and back to the surface as part of the produced fluid <NUM>. The water phase of the produced fluid <NUM> can originate from water-based fracturing fluid or connate water that flows from the hydraulically-fractured formation <NUM> through open ports <NUM> of the fracturing sleeves <NUM> back to the surface as part of the produced fluid <NUM>. The solid phase of the produced fluid <NUM> can originate from proppant (e.g., sand) or possibly rock fragments flows from the hydraulically-fractured formation <NUM> through open ports <NUM> of the fracturing sleeves <NUM> (or that has settled in the production tubing itself and flows) back to the surface as part of the produced fluid <NUM>. The produced fluid <NUM> can be generated as part of a flowback process that follows the hydraulic fracturing treatment of the well using the fracturing sleeves <NUM> preparation for cleanup and starting production from the well. Alternatively, the produced fluid <NUM> can be generated as part of a workover process in preparation for returning the well to production.

The data analyzer <NUM> interfaces to the multiphase flow meter <NUM> and possibly the downhole pressure sensor(s) <NUM> via suitable data communication links (such as wired electrical communication links, wireless RF communication links, or optical communication links). The surface-located multiphase flow meter <NUM> can be configured to measure flow rates of the various phases (oil/gas/water/solid) of the stream of produced fluid <NUM> produced from the well in real time. In one embodiment, the multiphase flow meter <NUM> may be a Model Vx Spectra multiphase flow meter supplied by Schlumberger Limited of Sugarland, Texas. The data analyzer <NUM> can be configured to process the multiphase flow rate measurements of the produced fluid <NUM> carried out by the surface-located multiphase flow meter <NUM> and pressure measurements carried out by the downhole pressure sensor(s) <NUM> after opening (or closing) the ports <NUM> of a set of one or more fracturing sleeves <NUM> in order to characterize the flow contributions of one or more different fluid phases that flow through the ports <NUM> of the set of one or more fracturing sleeves <NUM> in their open configuration. Such flow contributions can characterize the flow rates of fracturing fluid and/or connate water, oil, gas and/or solids (e.g., proppants) that flows through the ports <NUM> of the set of one or more fracturing sleeves <NUM> in their open configuration. The data analyzer <NUM> can determine such flow contributions using nodal analysis and modeling of the multiphase flow rate measurements of the produced fluid <NUM> carried out by the multiphase flow meter <NUM> and optional downhole pressure measurements carried out by the downhole pressure sensor(s) <NUM>. The flow contributions of one or more different fluid phases that flow through the ports <NUM> of the set of one or more fracturing sleeves <NUM> in their open configuration can be used to characterize local properties of the formation <NUM> adjacent the set of one or more fracturing sleeves <NUM> for reservoir analysis and/or planning. For example, such local formation properties can include fracture area and/or fracture conductivity, or sand production rate of the formation adjacent the set of one or more fracturing sleeves <NUM>. This process can be repeated in conjunction with opening (or closing) additional sets of one or more fracturing sleeves in order to characterize local formation properties adjacent the additional sets of one or more fracturing sleeves along the length of the well.

The characterization of each interval can allow the determination of the number of intervals contributing to production as well as the magnitude of their respective contribution, which is a key information for further optimization. It can be used to optimize the subsequent flowback program, generate safe pressure/flowrate windows for early production (e.g. without excessive proppant flowback or early near wellbore fracture closure), as this operation requires the knowledge of the producing rate per fracture. Stages associated with significant solids production but limited hydrocarbon flow can also be closed off. Such information can also provide a measure of the variability of fracture production along the well so that it can be mitigated by changing the design of subsequent wells. Subsequent to the sleeve opening and flowback period, the characterization of the intervals can provide a first estimate of the well productivity and will serve as the basis for evaluating the need for artificial lift and its design. In the extreme case of very poor stimulation, the need for immediate re-stimulation or remedial stimulation may be flagged by an unfavorable characterization of the intervals. One of the major issues is determining potential re-fracturing candidate zones. If one stage is found not to be producing and yet we determine that it is well connected to an adjacent productive zone, then we can possibly assume that the reservoir behind the casing is actually producing, and may not necessarily be a good re-fracturing candidate. If we should that an interval is not producing, and is not well connected to neighboring stages, then it may be a very good re-fracturing target. Furthermore, if stages are found to be placed in parts of the reservoirs that are depleted, e.g. if the analysis shows that cross-flow exists between stages, those stages taking fluid from the other producing stages can be closed off.

<FIG> shows an example computing system <NUM> that can be used to implement the data analyzer <NUM> or parts thereof. The computing system <NUM> can be an individual computer system 301A or an arrangement of distributed computer systems. The computer system 301A includes one or more analysis modules <NUM> (a program of computer-executable instructions and associated data) that can be configured to perform various tasks according to some embodiments, such as the tasks described herein. To perform these various tasks, an analysis module <NUM> executes on one or more processors <NUM>, which is (or are) connected to one or more storage media <NUM>. The processor(s) <NUM> is (or are) also connected to a network interface <NUM> to allow the computer system 301A to communicate over a data network <NUM> with one or more additional computer systems and/or computing systems, such as 301B, 301C, and/or 301D. Note that computer systems 301B, 301C and/or 301D may or may not share the same architecture as computer system 301A, and may be located in different physical locations.

The processor <NUM> can include at least a microprocessor, microcontroller, processor module or subsystem, programmable integrated circuit, programmable gate array, digital signal processor (DSP), or another control or computing device.

The storage media <NUM> can be implemented as one or more non-transitory computer-readable or machine-readable storage media. Note that while in the embodiment of <FIG>, the storage media <NUM> is depicted as within computer system 301A, in some embodiments, storage media <NUM> may be distributed within and/or across multiple internal and/or external enclosures of computing system 301A and/or additional computing systems. Storage media <NUM> may include one or more different forms of memory including semiconductor memory devices such as dynamic or static random access memories (DRAMs or SRAMs), erasable and programmable read-only memories (EPROMs), electrically erasable and programmable read-only memories (EEPROMs) and flash memories; magnetic disks such as fixed, floppy and removable disks; other magnetic media including tape; optical media such as compact disks (CDs) or digital video disks (DVDs); or other types of storage devices. Note that the computer-executable instructions and associated data of the analysis module(s) <NUM> can be provided on one computer-readable or machine-readable storage medium of the storage media <NUM>, or alternatively, can be provided on multiple computer-readable or machine-readable storage media distributed in a large system having possibly plural nodes. Such computer-readable or machine-readable storage medium or media is (are) considered to be part of an article (or article of manufacture). The storage medium or media can be located either in the machine running the machine-readable instructions, or located at a remote site from which machine-readable instructions can be downloaded over a network for execution.

It should be appreciated that computing system <NUM> is only one example of a computing system, and that computing system <NUM> may have more or fewer components than shown, may combine additional components not depicted in the embodiment of <FIG>, and/or computing system <NUM> may have a different configuration or arrangement of the components depicted in <FIG>. The various components shown in <FIG> may be implemented in hardware, software, or a combination of both hardware and software, including one or more signal processing and/or application specific integrated circuits.

Further, the operations of the data analyzer <NUM> as described herein may be implemented by running one or more functional modules in an information processing apparatus such as general purpose processors or application specific chips, such as ASICs, FPGAs, PLDs, SOCs, or other appropriate devices. These modules, combinations of these modules, and/or their combination with general hardware are all included within the scope of the disclosure.

<FIG> illustrates a workflow that opens a set of one or more fracturing sleeves and analyzes produced fluid that flows from the well to the surface facility of <FIG> after opening the set of one or more fracturing sleeves in order to characterize local properties of the formation adjacent the set of one or more fracturing sleeves <NUM>. The ports <NUM> for all of the fracturing sleeves <NUM> of the well can be initially configured in their closed configuration, which effects bottomhole shut-in of the well. The workflow begins in block <NUM> where the shifting tool BHA <NUM> is positioned and operated such that it opens the port(s) <NUM> of a set of one or more fracturing sleeves <NUM>. Such operations permit the flow of produced fluid <NUM> from the fractures and formation adjacent the set of one or more fracturing sleeves <NUM> and through the open port(s) <NUM> of the set of one or more fracturing sleeves <NUM> to the surface facility <NUM> (<FIG>).

In block <NUM>, the data analyzer <NUM> is used to process the surface flow rate measurements output by the multiphase flow meter <NUM> and the downhole pressure measurements output by the downhole pressure sensor(s) <NUM> in order to analyze the produced fluid <NUM> and characterize one or more local formation properties of the formation adjacent the set of one or more fracturing sleeves <NUM> (whose ports <NUM> were opened in block <NUM>).

In block <NUM>, the data analyzers <NUM> stores in computer memory data representing the local formation properties of the formation adjacent the set of one or more fracturing sleeves <NUM> as determined in block <NUM> for reservoir analysis and planning.

In block <NUM>, it is determined whether one or more local formation properties indicate depleted formation or well damage/fracture collapse or other condition(s) that can be remedied by closing the ports of the set of one or more fracturing sleeves. The determination of block <NUM> can be performed in an automated manner by computer evaluation of one or more predefined conditions, in a manual manner by human analysis of the data or in a semi-automated manner involving both computer evaluation and human analysis. If so, the workflow continues to block <NUM> where the shifting tool is operated such that it closes the port(s) <NUM> of the set of one or more fracturing sleeves <NUM>. In other embodiments, the port(s) <NUM> of the set of one or more fracturing sleeves <NUM> can remain closed if closed. This operation blocks flow of produced fluid from the fractures and formation adjacent the set of one or more fracturing sleeves <NUM> into the well, and the operations continue to block <NUM>. Otherwise (it is determined that one or more local formation properties do not indicate depleted formation or well damage/fracture collapse or other condition(s) that can be remedied by closing the ports of the set of one or more fracturing sleeves), the set of one or more fracturing sleeves of the well can remain open and the workflow continues to block <NUM>. In other embodiments, the port(s) <NUM> of the set of one or more fracturing sleeves <NUM> can be opened if initially closed.

In block <NUM>, it is determined whether to repeat the operations of blocks <NUM> to <NUM> for an additional set of one or more fracturing sleeves. The determination of block <NUM> can be performed in an automated manner by computer evaluation of one or more predefined conditions, in a manual manner by human analysis of the data or in a semi-automated manner involving both computer evaluation and human analysis. If so, the workflow reverts back to block <NUM> in order to repeat the operations of blocks <NUM> to <NUM>. Otherwise, the workflow continues to block <NUM> where the shifting tool BHA <NUM> is removed from the well and the workflow ends.

Note that the sequence of fracturing sleeves whose ports are opened by the workflow can be varied as desired. For example, the ports of individual fracturing sleeves can be opened from the heel to the toe of the well (or from the toe to the heel of the well) in order to analyze the produced fluid and characterize one or more local formation properties of the formation adjacent each individual fracturing sleeve of the formation and remedy certain condition(s) that are detected for specific well intervals by closing the ports of the fracturing sleeves for the specific well intervals. In another embodiment, the ports of other combinations or sets of fracturing sleeves can be opened in sequence in order to analyze the produced fluid and characterize one or more local formation properties of the formation adjacent the combinations or sets of fracturing sleeves and remedy certain condition(s) that are detected for specific well intervals by closing the ports of the fracturing sleeves for the specific well intervals.

Also note that workflow can be adapted such that the ports of combinations or sets of fracturing sleeves are closed from an initial open configuration in order to analyze the produced fluid and characterize one or more local formation properties of the formation adjacent the combinations or sets of fracturing sleeves and remedy certain condition(s) that are detected for specific well intervals by closing the ports of the fracturing sleeves for the specific well intervals.

In one embodiment shown in <FIG>, the analysis begins in block <NUM> by using the shifting tool BHA to open a fracturing sleeve of the well. In block <NUM>, flowing well status is established with the BHA located across the open fracturing sleeve. In block <NUM>, once flow is established, the data analyzer <NUM> can be used to process the surface flow rate measurements output by the multiphase flow meter <NUM> and the downhole pressure measurements output by the downhole pressure sensor(s) <NUM> in order to analyze the produced fluid <NUM> and characterize the outflow of return fluid to the surface over time. In block <NUM>, the return fluid measurements of block <NUM> can be used to calculate and model the downhole contributions from all open intervals. Note that the model of block <NUM> is a combination or convolution of the return outflow from all open intervals (including the newly-opened interval) of the well, and these open intervals are different over the sequence of well intervals whose fracturing sleeves are opened by the operations. In block <NUM>, the data analyzer <NUM> calculates the return outflow of the newly-opened interval by isolating the contribution of return outflow for the newly-opened interval from the previous model (derived from the last iteration of block <NUM>). The calculations of block <NUM> can involve subtracting the return outflow from the previous model (derived from the last iteration of block <NUM>) from the return outflow of the model derived in block <NUM>. Furthermore, in block <NUM>, the data analyzer <NUM> derives local formation properties of the newly-opened interval based on the return outflow for the newly-opened interval, for example, by correlation, modeling or other suitable techniques.

Note that the operations of blocks <NUM> to <NUM> can be performed iteratively over a sequence of fracturing sleeves of the well in order to derive local formation properties for each newly-opened interval. As each given fracturing sleeve of the sequence is opened, the new measurements of surface flow characteristics and downhole pressure measurements are used to update the calculations and model of block <NUM>. Changes to the model between before and after opening the given fracturing sleeve can be used to isolate the contribution of return outflow for the newly-opened interval and derive local formation properties based thereon in block <NUM>. The well intervals that correspond to the sequence of fracturing sleeves that are opened by the operations of <FIG> can be varied as desired. For example, fracturing sleeves and corresponding intervals can be opened and characterized interval-by-interval from the heel to the toe of the well (or from the toe to the heel of the well).

In other embodiments, the operations of <FIG> and <FIG> can be adapted to close a sequence of fracturing sleeves of the well in order to derive local formation properties for each newly-closed interval. In this case, as each given fracturing sleeve of the sequence is closed, the new measurements of surface flow characteristics and downhole pressure measurements are used to update the calculations and model. Changes to the model between before and after closing the given fracturing sleeve can be used to isolate the contribution of return outflow for the newly-closed interval and derive local formation properties based thereon. The well intervals that correspond to the sequence of fracturing sleeves that are closed by the operations of the workflow can be varied as desired. For example, fracturing sleeves and corresponding intervals can be closed and characterized interval-by-interval from the heel to the toe of the well (or from the toe to the heel of the well).

<FIG> shows the horizontal section <NUM> of an example well that has undergone hydraulic fracturing applications. The well includes a surface-located platform and derrick and vertical casing similar to the well of <FIG> that are not shown for the sake of simplicity of description. The horizontal section <NUM> includes production tubing <NUM> that extends along the horizontal section and is cemented to the wellbore <NUM>. The production tubing <NUM> includes a number of perforated production liners or casing <NUM> that offset from one another along the horizontal section. The perforated production liners or casing <NUM> have perforation zones or ports <NUM> that are fixed open and allow fluid communication between the hydraulically-fractured hydrocarbon-bearing formation <NUM> and the interior space of the perforated production liners or casing <NUM>. The perforation zones or ports <NUM> can be formed by bullet gun, abrasives, water jets, shaped charge or other suitable perforating methodologies used to initiate a hole from the wellbore through the production liners or casing <NUM> and any cement sheath into the hydrocarbon-bearing formation <NUM>. The production tubing <NUM> can also include non-perforated horizontal casing and/or production liner sections that are disposed between the perforated production liners or casing <NUM> and cemented to wellbore <NUM>. The perforated production liners or casing <NUM> can be located as part of predetermined well intervals that correspond to desired production zones of the hydrocarbon-bearing formation <NUM>. The number of perforated production liners <NUM> for the respective well intervals can be the same or vary over the respective well intervals. For example, a first well interval having one or more perforated production liners or casing <NUM> can traverse one production zone of the hydrocarbon-bearing formation <NUM> while a second well interval having one or more perforated production liners or casing <NUM> can traverse another production zone of the hydrocarbon-bearing formation <NUM>. The number of perforated production liners or casing <NUM> for the first and second well intervals can be the same or be different from one another.

A bottom hole assembly ("BHA") <NUM> may be run inside the production tubing <NUM> of the horizontal section <NUM> (including the perforated production liners or casing <NUM>) by tubing <NUM> (which can be coiled tubing or drill pipe). The means for conveying the tubing <NUM> and the BHA <NUM> inside the production tubing <NUM> can be provided at the surface or by a downhole mechanism (such as a downhole tractor) as is well known. The BHA <NUM> is a resettable packer that can be conveyed within the production tubing <NUM> to a desired location and set to engage and form a sealed interface to the production tubing <NUM>. The sealed interface provided by the packer <NUM> isolates a set of one or more intervals of the horizontal section <NUM> that are upstream from the packer <NUM> from one or more intervals of the horizontal section <NUM> that are downstream from the packer <NUM>. In this set configuration, the set of one or more intervals that are upstream from the packer <NUM> are in fluid communication with the surface facility, while the one or more intervals downstream from the packer <NUM> are fluidly isolated and decoupled from the surface facility (<FIG>). The packer <NUM> can also be configured such that the sealed interface between the packer <NUM> and the production tubing <NUM> can be released, which allows the resettable packer <NUM> to be conveyed to another desired location and set to engage and form another sealed interface to the production tubing <NUM> at the new location.

<FIG> illustrate an embodiment of a resettable packer <NUM>. Turning to <FIG>, the packer <NUM> has a first end <NUM> disposed opposite a second end <NUM>, and is formed around a central tubular member or mandrel <NUM>. The central mandrel <NUM> includes the second end <NUM> which can be connected to conveyance tubing or other downstream tools using known mechanisms such as threading and the like. As illustrated, the packer <NUM> includes an assembly of collet arms <NUM> disposed near the second end <NUM>, a release section <NUM> disposed near the first end <NUM>, at least one expandable seal element <NUM> disposed near the release section <NUM>, and slip <NUM> disposed between the seal element(s) <NUM> and the collet arms <NUM>.

The collet arms <NUM> extend longitudinally along the exterior surface of the packer <NUM>. Each collet arm <NUM> includes a radially extended contact surface <NUM> that is flared radially from the packer <NUM> as best shown in <FIG> so as to cause the contact surface <NUM> to engage upon production tubing (e.g., the production liner or casing) of the well and cause drag therewith.

The slip <NUM> includes a plurality of pivot arms <NUM> that extend along the exterior surface of the packer <NUM> in a direction generally towards the first end <NUM>. The pivot arms <NUM> are supported by a moveable housing <NUM> that can slide longitudinally relative to the central mandrel <NUM>. The pivot arms <NUM> pivot between a retracted configuration (where the arms <NUM> extend in a direction substantially parallel to the central axis of the mandrel <NUM>) and an extended configuration (where the arms <NUM> extend at angle away from the central axis of the mandrel <NUM>) by sliding movement of the moveable housing <NUM> toward a cone <NUM>. The cone <NUM> is a frusto-conical tubular body that is located around the central mandrel <NUM> as best shown in <FIG>. The cone <NUM> includes an angled surface that interfaces to the bottom surface of the pivot arms <NUM> and pivots the arms <NUM> into their extended configuration by the sliding movement of the moveable housing <NUM> toward the cone <NUM>. In the extended configuration, the arms <NUM> can engage the production tubing (e.g., liner or casing) of the well in order to fix the packer <NUM> at a desired location in the well.

Tool pressure can be applied to the central mandrel <NUM> toward the second end <NUM>, which can compress the one or more seal elements <NUM> such that the seal element(s) <NUM> deform and expand radially to provide a seal interface between the production tubing <NUM> (such as liner or casing) of the well and the packer <NUM>. This seal interface can be used for well interval isolation purposes as described herein. As illustrated in <FIG> and <FIG>, the packer may include three seal elements <NUM>; however, it will be appreciated that more or less than three may also be utilized.

The release section <NUM> of the packer <NUM> includes a top collar <NUM> forming the first end <NUM>. The top collar <NUM> can be connected to the conveyance tubing <NUM> using known mechanisms such as threading and the like. The release section <NUM> further includes a bypass mandrel <NUM> secured to the top collar <NUM> with first and second bypass plugs, respectively. The first and second bypass plugs can be adapted to sequentially permit an increasing amount of material past the packer. In order to release the packer <NUM>, the top collar <NUM> is retracted in a direction generally indicated at <NUM>, which pulls the top collar <NUM> and the bypass mandrel <NUM> with it drawing the first bypass plug so as to disengage it from the second bypass plug thereby permitting flow of material through the packer <NUM>. Further retracting movement of the top collar <NUM> and bypass mandrel <NUM> will also draw the second bypass plug so as to disengage it from the central mandrel <NUM> thereby permitting full flow of material through the packer <NUM>. The retracting movement of the top collar <NUM> and the bypass mandrel <NUM> can also cause retraction movement of the central mandrel <NUM>, which will cause the cone <NUM> to be pulled away from the arms <NUM> thereby permitting the arms <NUM> to disengage from the surrounding production tubing as well as decompressing the seal element(s) <NUM> so as to release the seal interface between the production tubing <NUM> (such as liner or casing) of the well and the packer <NUM>. Thereafter the entire packer <NUM> may be removed or repositioned as desired. If the packer <NUM> is desired to be repositioned, it may be positioned at the desired location and reset to define a seal interface between the production tubing <NUM> (such as liner or casing) of the well and the packer <NUM> at the new location in the well as described above.

The surface facility <NUM> of <FIG> can be configured to analyze produced fluid that flows from the horizontal section <NUM> with the resettable packer <NUM> set at position in the horizontal section <NUM>. In this set configuration, the set of one or more intervals that are upstream from the packer <NUM> are in fluid communication with the surface facility <NUM>, while the one or more intervals downstream from the packer <NUM> are fluidly isolated and decoupled from the surface facility <NUM>. One or more optional downhole pressure sensor(s) <NUM> may also be included. The downhole pressure sensor(s) <NUM> can be integral to the packer <NUM>, the tubing <NUM> that is used to run in the packer <NUM>, the production tubing <NUM>, or some other part of the well completion. Produced fluid <NUM> can flow from the production tubing <NUM> of the horizontal section uphole through the annulus between the conveyance tubing <NUM> and the vertical casing (or possibly through a return flowpath provided by the conveyance tubing <NUM>). At the surface, the produced fluid <NUM> flows from the platform <NUM> through the multiphase flow meter <NUM> for separation into various phases (solids, oil, gas, water) and storage by the fluid separation and storage stage <NUM>. The multiphase flow meter <NUM> can be configured to measure the flow rates of different phases (e.g., oil, gas, water, solids) that make up the produced fluid <NUM> that returns to the surface. The oil and gas phases of the produced fluid <NUM> can originate from hydrocarbons that flow from the hydraulically-fractured formation <NUM> through the perforation zones <NUM> of the perforated liner(s) or casing <NUM> that are part of the set of isolated well interval(s) located upstream of the packer <NUM>. The water phase of the produced fluid <NUM> can originate from water-based fracturing fluid or connate water that flows from the hydraulically-fractured formation <NUM> through the perforation zones <NUM> of the perforated liner(s) or casing <NUM> that are part of the set of isolated well interval(s) located upstream of the packer <NUM>. The solid phase of the produced fluid <NUM> can originate from proppant (e.g., sand) or possibly rock fragments that flow from the hydraulically-fractured formation <NUM> through the perforation zones <NUM> of the perforated liner(s) or casing <NUM> that are part of the set of isolated well interval(s) located upstream of the packer <NUM>. The produced fluid <NUM> can be generated as part of a flowback process that follows the hydraulic fracturing treatment of the well in preparation for cleanup and starting production from the well. Alternatively, the produced fluid <NUM> can be generated as part of a workover process in preparation for returning the well to production.

The data analyzer <NUM> interfaces to the multiphase flow meter <NUM> and possibly the downhole pressure sensor(s) <NUM> via suitable data communication links (such as wired electrical communication links, wireless RF communication links, or optical communication links). The surface-located multiphase flow meter <NUM> can be configured to measure flow rates of the various phases (oil/gas/water/solid) of the stream of produced fluid <NUM> produced from the well in real time. In one embodiment, the multiphase flow meter <NUM> may be a Model Vx Spectra multiphase flow meter supplied by Schlumberger Limited of Sugarland, Texas. The data analyzer <NUM> can be configured to process the multiphase flow rate measurements of the produced fluid <NUM> carried out by the surface-located multiphase flow meter <NUM> and the downhole pressure measurements carried out by the downhole pressure sensor(s) <NUM> after setting the packer <NUM> to isolate a set of isolated well interval(s) located upstream of the packer <NUM> in order to characterize the flow contributions of one or more different fluid phases that flow through the perforation zones <NUM> of the perforated liner(s) or casing <NUM> that are part of the set of isolated well interval(s) located upstream of the packer <NUM>. Such flow contributions can characterize the flow rates of fracturing fluid and/or connate water, oil, gas and/or solids (e.g., proppants) that flows through the perforation zones <NUM> of the perforated liner(s) or casing <NUM> that are part of the set of isolated well interval(s) located upstream of the packer <NUM>. The data analyzer <NUM> can determine such flow contributions using nodal analysis and modeling of the multiphase flow rate measurements of the produced fluid <NUM> carried out by the multiphase flow meter <NUM> and the downhole pressure measurements carried out by the downhole pressure sensor(s) <NUM>. The flow contributions of one or more different fluid phases that flow through the perforation zones <NUM> of the perforated liner(s) or casing <NUM> that are part of the set of isolated well interval(s) located upstream of the packer <NUM> can be used to characterize local properties of the formation <NUM> adjacent the set of isolated well interval(s) located upstream of the packer <NUM>. For example, such local formation properties can include fracture area and/or fracture conductivity of the formation adjacent the set of isolated well interval(s) located upstream of the packer <NUM>. This process can be repeated in conjunction with isolating additional sets of well intervals located upstream of the packer <NUM> in order to characterize local formation properties adjacent these additional sets of well intervals along the length of the well.

The characterization of each interval can allow the determination of the number of intervals contributing to production as well as the magnitude of their respective contribution. In turn, such information can be used to optimize the subsequent flowback program, generate safe pressure/flowrate windows for early production (e.g., without excessive proppant flowback or early near wellbore fracture closure). Such information can also provide a measure of the variability of fracture production along the well so that it can be mitigated by changing the design of subsequent wells. Subsequent to the sleeve opening and flowback period, the characterization of the intervals can provide a first estimate of the well productivity and can serve as the basis for evaluating the need for artificial lift and its design. In the extreme case of very poor stimulation, the need for immediate re-stimulation or remedial stimulation may be flagged by an unfavorable characterization of the intervals. One of the major issues is determining potential re-fracturing candidate zones. If one stage is found not to be producing and yet we determine that it is well connected to an adjacent productive zone, then we can possibly assume that the reservoir behind the casing is actually producing, and may not necessarily be a good re-fracturing candidate. If we should that an interval is not producing, and is not well connected to neighboring stages, then it may be a very good re-fracturing target.

<FIG> illustrates a workflow that sets the resettable packer <NUM> at a position in the horizontal section <NUM> of <FIG>. In this set configuration, the set of one or more intervals that are upstream from the packer <NUM> are in fluid communication with the surface facility <NUM>, while the one or more intervals downstream from the packer <NUM> are fluidly isolated and decoupled from the surface facility <NUM>. After setting the packer, the produced fluid <NUM> that flows from the well to the surface facility of <FIG> is analyzed in order to characterize local properties of the formation adjacent the set of one or more well intervals that are positioned upstream of the resettable packer <NUM>. The workflow begins in block <NUM>, where the resettable packer <NUM> is located at a desired position in the horizontal section <NUM> that is suitable for isolating a set of one or more well intervals in fluid communication with the surface facility <NUM>.

In block <NUM>, the resettable packer <NUM> is set at the desired position of block <NUM>. In this set configuration, the set of one or more intervals that are upstream from the packer <NUM> are in fluid communication with the surface facility <NUM>, while the one or more intervals downstream from the packer <NUM> are fluidly isolated and decoupled from the surface facility <NUM>. This permits flow of produced fluid <NUM> from the fractures and formation <NUM> adjacent the set of one of more well intervals that are upstream from the packer <NUM> to the surface facility <NUM>.

In block <NUM>, the data analyzer <NUM> is used to process the surface flow rate measurements output by the multiphase flow meter <NUM> and possibly the downhole pressure measurements output by the downhole pressure sensor(s) <NUM> over time in order to analyze the produced fluid <NUM> and characterize one or more local formation properties of the formation <NUM> adjacent the set of one or more well intervals that are upstream from the packer <NUM>.

In block <NUM>, the data analyzers <NUM> stores in computer memory data representing the local formation properties of the formation <NUM> adjacent the set of one or more well intervals that are upstream from the packer <NUM> as determined in block <NUM> for reservoir analysis and planning.

In block <NUM>, it is determined whether one or more local formation properties indicate depleted formation or well damage/fracture collapse or other condition(s) that can be remedied by sealing one or more intervals located upstream of the packer <NUM>. The determination of block <NUM> can be performed in an automated manner by computer evaluation of one or more predefined conditions, in a manual manner by human analysis of the data or in a semi-automated manner involving both computer evaluation and human analysis. If so, the workflow continues to block <NUM>. Otherwise, the workflow continues to block <NUM>.

In block <NUM>, a sealing agent can be pumped downhole such that the sealing agent blocks the flow of produced fluid from the fractures and formation <NUM> into one or more intervals of the set of well intervals that are located upstream of the packer <NUM>, and the operations continue to block <NUM>. The sealing agent can be pumped downhole via a fluid pathway that is part of the conveyance tubing <NUM> or via some other suitable means. Other zones opened to the wellbore may be isolated prior to placement of the sealing agent. In one specific example, it can be done by using a dual packer system that enables injection of the sealing material into the zone that is planned to be sealed or by isolating other open interval by any other mean (e.g. by closing sleeves on such intervals if such sleeves are available).

The sealing agent can include a solid removable sealing agent that is placed in the perforation zones <NUM> and/or in the space between the formation <NUM> and the perforated liner(s) and/or casing <NUM>. In one or more embodiments, the solid removable sealing agent may be a dissolvable material, which may comprise acid soluble cement, calcium and/or magnesium carbonate, polyesters including esters of lactic hydroxycarbonic acids and copolymers thereof, active metals such as magnesium, aluminum, zinc, and their alloys, hydrocarbons with greater than <NUM> carbon atoms including, for example, paraffins and waxes, and carboxylic acids such as benzoic acid and its derivatives. Further, in one or more embodiments, the dissolvable solid removable sealing agent may be slightly soluble in a wellbore fluid at certain conditions and would have a long dissolution time in said fluid. Examples of combinations of removable sealing agents and wellbore fluids that result in slightly soluble dissolvable removable sealing agents are benzoic acid with a water-based wellbore fluid and rock salt with a brine in the wellbore fluid. The solid removable sealing agent may be in any size and form: grains, powder, spheres, balls, beads, fibers, or other forms known in the art. In order to facilitate the delivery of the solid composition to the desired zone for sealing, the solid composition may be suspended in liquids such as gelled water, viscoelastic surfactant fluids, cross-linked fluids, slick-water, foams, emulsions, brines, water, and sea-water.

The sealing agent can also be a viscous fluid that reduces the permeability of the formation rock or fracture. In one or more embodiments, the viscous fluids may comprise at least one of viscoelastic surfactant fluids, cross-linked polymer solutions, slick-water, foams, emulsions, dispersions of acid soluble particulate carbonates, dispersions of oil soluble resins, or any other viscosified fluid that may be subsequently dissolved or otherwise removed (such as by breaking of the viscosification).

The sealing agent can also include a removable sealing agent, which may be any material, such as solid materials (including, for example, degradable solids) that can be removed from their sealing location. In some embodiments, the removal may be assisted or accelerated by a wash containing an appropriate reactant (for example, capable of reacting with one or more molecules of the sealing agent to cleave a bond in one or more molecules in the sealing agent), and/or solvent (for example, capable of causing a sealing agent molecule to transition from the solid phase to being dispersed and/or dissolved in a liquid phase), such as a component that changes the pH and/or salinity. The removal may also be assisted by an increase in temperature, for example, when the treatment is performed before steam flooding, and/or a change in pressure. In some embodiments, the removable sealing agents may be a degradable material. A degradable material refers to a material that will at least partially degrade (for example, by cleavage of a chemical bond) within a desired period of time such that no additional intervention is used to remove the seal. The degradation of the material may be triggered by a temperature change, and/or by chemical reaction between the material and another reactant. Degradation may include dissolution of the material.

Additional details of exemplary sealing agents are described in <CIT>, <CIT>, <CIT> and <CIT>.

In block <NUM>, it is determined whether to repeat the operations of blocks <NUM> to <NUM> for an additional set of one or more well intervals. The determination of block <NUM> can be performed in an automated manner by computer evaluation of one or more predefined conditions, in a manual manner by human analysis of the data or in a semi-automated manner involving both computer evaluation and human analysis. If so, the operations continue to block <NUM> where the resettable packer <NUM> is deactivated (in order to break the seal interface and allow the packer <NUM> to move within the horizontal section <NUM>) and the workflow reverts back to block <NUM> in order to repeat the operations of blocks <NUM> to <NUM>. Otherwise, the workflow continues to block <NUM> where the resettable packer <NUM> is removed from the well and the workflow ends.

Note that the sequence of isolated well intervals can be varied as desired. For example, individual well intervals can be isolated from the heel to the toe of the well (or from the toe to the heel of the well) in order to analyze the produced fluid and characterize one or more local formation properties of the formation adjacent each individual well interval and remedy certain condition(s) that are detected for specific well intervals by sealing the specific well intervals.

In other embodiment, other combinations or sets of well intervals can be opened in sequence in order to analyze the produced fluid and characterize one or more local formation properties of the formation adjacent the combinations or sets of well intervals and remedy certain condition(s) that are detected for specific well intervals by sealing the specific well intervals.

In one embodiment shown in <FIG>, the analysis begins in block <NUM> by moving and activating the resettable packer <NUM> such that it isolates one or more well intervals downstream of the resettable packer. In block <NUM>, flowing well status is established with the resettable packer <NUM> isolating one or more well intervals downstream of the resettable packer <NUM>. In block <NUM>, once flow is established, the data analyzer <NUM> can be used to process the surface flow rate measurements output by the multiphase flow meter <NUM> and the downhole pressure measurements output by the downhole pressure sensor(s) <NUM> in order to analyze the produced fluid <NUM> and characterize the outflow of return fluid to the surface over time. In block <NUM>, the return fluid measurements of block <NUM> can be used to calculate and model the downhole contributions from all open intervals (i.e., the intervals upstream of the resettable packer <NUM>). Note that the model of block <NUM> is a combination or convolution of the return outflow from all open intervals (including the newly-opened interval) of the well, and these open intervals are different over the sequence of well intervals that are opened by the operations of the workflow. In block <NUM>, the data analyzer <NUM> calculates the return outflow of the newly-opened interval (i.e., the interval upstream of the resettable packer <NUM>) by isolating the contribution of return outflow from the previous model (derived from the last iteration of block <NUM>). The calculations of block <NUM> can involve subtracting the return outflow from the previous model (derived from the last iteration of block <NUM>) from the return outflow of the model derived in block <NUM>. Furthermore, in block <NUM>, the data analyzer <NUM> derives local formation properties of the newly-opened interval (i.e., the interval upstream of the resettable packer <NUM>) based on the return outflow for the newly-opened interval, for example, by correlation, modeling or other suitable techniques.

Note that the operations of blocks <NUM> to <NUM> can be performed iteratively over a sequence of well intervals in order to derive local formation properties for each newly-opened interval. As each interval of the sequence is opened by movement and activation of the resettable packer, the new measurements of surface flow characteristics and downhole pressure measurements are used to update the calculations and model of block <NUM>. Changes to the model between before and after opening the given interval can be used to isolate the contribution of return outflow for the newly-opened interval and derive local formation properties based thereon in block <NUM>. The sequence of well intervals that are opened by the operations of <FIG> can be varied as desired. For example, the well intervals can be opened and characterized interval-by-interval from the heel to the toe of the well.

<FIG> illustrates a workflow that employs a choking packer that can be located at a desired position in the horizontal section <NUM> of <FIG>. The choking packer is similar to the resettable packer <NUM> of <FIG> with one or more seal element(s) that are configured to have a choking effect on the produced fluid coming from below the choking packer (instead of providing an isolating seal interface between well intervals above and below the packer <NUM> as described above). Specifically, the seal element(s) can be configured with an outside diameter that is close to but less than the internal diameter of the production tubing (e.g., liner/casing) of the horizontal section <NUM>. With the choking packer set in place, the seal element(s) of the choking packer will have a choking effect on the produced fluid coming from below the packer. In this configuration, downhole pressure sensors can measure differential pressure of the produced fluid across the choking packer. After setting the choking packer in place, the produced fluid that flows from the well to the surface facility can be analyzed together with the pressure measurements of the differential pressure of the produced fluid across the choking packer by the surface facility <NUM> of <FIG> in order to characterize local properties of the formation adjacent the particular well interval/choking packer. The workflow begins in block <NUM>, where the choking packer is located and set at a desired position in a particular well interval that is in fluid communication with the surface facility <NUM>.

In block <NUM>, the data analyzer <NUM> can be used to process the surface flow rate measurements output by the multiphase flow meter <NUM> and the pressure measurements of the differential pressure of the produced fluid across the choking packer output by the downhole pressure sensors <NUM> in order to analyze the produced fluid and characterize one or more local formation properties (e.g., reservoir pressure, productivity index or skin) of the formation <NUM> adjacent the particular well interval/choking packer.

In block <NUM>, the data analyzer <NUM> stores in computer memory data representing the one or more local formation properties of the formation adjacent the particular well interval/choking packer for reservoir analysis and/or planning.

In block <NUM>, it is determined whether to repeat the operations of blocks <NUM> to <NUM> for another well interval. The determination of block <NUM> can be performed in an automated manner by computer evaluation of one or more predefined conditions, in a manual manner by human analysis of the data or in a semi-automated manner involving both computer evaluation and human analysis. If so, the operations revert back to block <NUM> in order to repeat the operations of blocks <NUM> to <NUM>. Otherwise, the workflow continues to block <NUM> where the choking packer is removed from the well and the workflow ends.

In one embodiment shown in <FIG>, the analysis begins in block <NUM> by moving the choking packer over one or more well intervals thereby un-choking one or more intervals upstream of the choking packer. In block <NUM>, flowing well status is established. In block <NUM>, once flow is established, the data analyzer <NUM> can be used to process the surface flow rate measurements output by the multiphase flow meter <NUM> and the downhole pressure measurements output by the downhole pressure sensor(s) <NUM> in order to analyze the produced fluid <NUM> and characterize the outflow of return fluid to the surface over time. In block <NUM>, the return fluid measurements of block <NUM> can be used to calculate and model the downhole contributions from all intervals of the well. Note that the model of block <NUM> is a combination or convolution of the return outflow from all intervals of the well. Once the choking packer is moved below a given interval, the interval upstream of the choking packer (now un-choked) will provide an incremental gain to the fluid flow behavior of the well, which will affect the surface returns in terms of rate and pressure. In block <NUM>, the data analyzer <NUM> calculates the return outflow of the interval(s) upstream of the choking packer (now un-choked) by isolating the incremental production gain of the newly un-choked interval(s) from the previous model (derived from the last iteration of block <NUM>). The calculations of block <NUM> can involve subtracting the return outflow from the previous model (derived from the last iteration of block <NUM>) from the return outflow of the model derived in block <NUM>. Furthermore, in block <NUM>, the data analyzer <NUM> derives local formation properties of the interval(s) upstream of the choking packer (now un-choked) based on the return outflow for the interval(s) upstream of the choking packer, for example, by correlation, modeling or other suitable techniques.

Note that the operations of blocks <NUM> to <NUM> can be performed iteratively over a sequence of well intervals in order to derive local formation properties for each newly un-choked interval. An initial model can be derived from the surface flow characteristics and downhole pressure measurements with the choking packer located upstream of the top well interval of the sequence. As each interval of the sequence is un-choked by movement of the choking packer, the new measurements of surface flow characteristics and downhole pressure measurements are used to update the calculations and model of block <NUM>. Changes to the model between before and after un-choking the given interval can be used to isolate the contribution of return outflow for the un-choked interval and derive local formation properties based thereon in block <NUM>. The sequence of well intervals that are un-choked by the operations of <FIG> can be varied as desired. For example, the well intervals can be un-choked and characterized interval-by-interval from the heel to the toe of the well.

<FIG> illustrates a surface facility <NUM> that analyzes flow characteristics of produced fluid that flows from a well traversing a hydraulically-fractured hydrocarbon-bearing formation (for example, the well of <FIG> or <FIG>) to the surface in order to detect and characterize slug flow originating from one or more well intervals and store in computer memory data related to such analysis for reservoir analysis and planning. The surface facility <NUM> includes a well-head choke and pressure sensor(s) <NUM>, a multiphase flow meter <NUM>, and a transient multiphase wellbore flow simulator <NUM>. Optional equipment <NUM> for fluid sampling and analysis can be provided. One or more optional downhole pressure sensors <NUM> can also be provided. Produced fluid <NUM> can flow uphole through the production tubing of the well. At the surface, the produced fluid <NUM> flows from the platform through the well-head choke <NUM> and through the multiphase flow meter <NUM> for separation into various phases (solids, oil, gas, water) and storage by the fluid separation and storage stage <NUM>. The produced fluid <NUM> can be supplied to the equipment <NUM> for fluid sampling and analysis. The multiphase flow meter <NUM> can be configured to measure the flow rates of different phases (e.g., oil, gas, water, solids) that make up the produced fluid <NUM> that returns to the surface. The oil and gas phases of the produced fluid <NUM> can originate from hydrocarbons that flow from the hydraulically-fractured formation into the production tubing of the well. The water phase of the produced fluid <NUM> can originate from water-based fracturing fluid or connate water that flows from the hydraulically-fractured formation into the production tubing of the well. The solid phase of the produced fluid <NUM> can originate from remnant proppant (e.g., sand) or possibly rock fragments flows from the hydraulically-fractured formation into the production tubing of the well. The produced fluid <NUM> can be generated as part of a flowback process that follows the hydraulic fracturing treatment of the well in preparation for cleanup and starting production from the well. Alternatively, the produced fluid <NUM> can be generated as part of a workover process in preparation for returning the well to production.

The choke <NUM> may include a variable sized aperture or orifice that is used to control fluid flow rate or downstream system pressure. As an example, the choke <NUM> may be provided in any of a variety of configurations (e.g., for fixed and/or adjustable modes of operation). As an example, an adjustable choke <NUM> may enable fluid flow and pressure parameters to be changed to suit process or production requirements. The choke <NUM> may be electrically or pneumatically operated.

The simulator <NUM> can interface to the well-head choke and pressure sensor(s) <NUM>, the multiphase flow meter <NUM> and possibly the downhole pressure sensor(s) <NUM> via suitable data communication links (such as wired electrical communication links, wireless RF communication links, or optical communication links). The well-head pressure sensor(s) <NUM> can be configured to measure pressure of the produced fluid <NUM> at the well-head in real time (for example, pressure of the produced fluid <NUM> on both the upstream and downstream sides of the well-head choke). The surface-located multiphase flow meter <NUM> can be configured to measure flow rates of the various phases (oil/gas/water/solid) of the stream of produced fluid <NUM> produced from the well in real time. In one embodiment, the multiphase flow meter <NUM> may be a Model Vx Spectra multiphase flow meter supplied by Schlumberger Limited of Sugarland, Texas. The equipment <NUM> for fluid sampling and analysis can be configured to sample the produced fluid <NUM> produced from the well for chemical analysis. Such chemical analysis may include PVT analysis; electrical conductivity measurements using capacitive type devices; pH detection using ion selective electrodes, solid state detectors, or spectrophometric methods; flowthrough spectrophotometric and infra-red spectroscopy cells; ion selective electrodes for specific ions, gas chromatography, gas detectors. The chemical analysis can generate data characterizing chemical properties of the produced fluid <NUM> or components thereof, such as conductivity, total dissolved solids (TDS), pH, temperature, total hardness, and total alkalinity. The chemical analysis can be carried out by the equipment <NUM> or by a local or remote testing laboratory.

The simulator <NUM> can control the operation of the choke <NUM> (e.g., vary the aperture size of the choke) to induce slug flow in the produce fluid <NUM>. Alternatively, the produced fluid <NUM> can exhibit slug flow behavior without being induced by controlled behavior of the choke <NUM> but due to the downhole conditions of the well. In either case, the simulator <NUM> can process the multiphase flow rate measurements of the produced fluid <NUM> carried out by the surface-located multiphase flow meter <NUM> and possibly other measurements (such as the well-head pressure measurements carried out by the well-head pressure sensors <NUM>, the downhole pressure measurements carried out by the optional downhole pressure sensor(s) <NUM>, and the chemical analysis measurements of the produced fluid) in order to detect slug flow and characterize properties of the such slug flow (such as amplitude/frequency/period of slugs) over time and determine one or more intervals (e.g., zones) of the well that contribute to the slug flow. The simulator <NUM> can store in computer memory data that identifies the one or more intervals of the well that contribute to the slug flow and the underlying cause of the slug flow for reservoir analysis and planning (such as intervention or re-fracturing).

The simulator <NUM> can employ a model representing a system of equations that predict transient pressure distributions along the well and along hydraulic fractures in the reservoir and that predict distributions of oil/gas/water saturations along the well and along the hydraulic fractures. The model can determine the predicted pressure distributions and oil/gas/water saturation distributions over time in response to choke control operations that dictate the aperture size of the well head choke <NUM> over time. The predicted pressure distributions and oil/gas/water saturation distributions can be used to calculate determined production flow rates at the surface for oil/water/gas over time. The model can also possibly determine solid concentration and other properties in fractures and along the well. The model can also possibly be used to characterize the bottomhole pressure and associated drawdown pressure of the well over time.

In one embodiment, the model can solve for pressure drop (e.g., pressure differential) in the well, for example, through use of momentum equations. Such momentum equations, for example, may account for factors such as fluid potential energy (e.g., hydrostatic pressure), friction (e.g., shear stress between conduit wall and fluid), and acceleration (e.g., change in fluid velocity). As an example, one or more equations may be expressed in terms of static reservoir pressure, a flowing bottomhole pressure, wellhead pressure, and flowrates for different phases of produced fluids at the surface. As an example, equations may account for vertical, horizontal or angled arrangements of equipment. In another example, the model may implement equations that include dynamic conservation equations for momentum, mass and energy. As an example, pressure and momentum can be solved implicitly and simultaneously and, for example, conservation of mass and energy (e.g., temperature) may be solved in succeeding separate stages. Various examples of equations may be found in a dynamic multiphase flow simulator such as the simulator of the OLGA™ simulation framework (Schlumberger Limited, Houston, TX). OLGA, being a transient multi-phase wellbore flow simulator, can be used to calculate the bottomhole pressure at one or more bottomhole locations inside of the well. To do this, OLGA uses the three-fluid mathematical model that is originally developed and validated for the horizontal flow configurations. The mathematical model in OLGA simulator is summarized in <NPL>. Typically, the boundary and initial conditions are specified before the simulation. The initial conditions include the distribution of phase volume fractions, velocities, pressure and other variables inside of the well. The boundary conditions typically include the wellhead pressure specified at the outlet of the well and no-flow boundary condition at the bottom of the well. The wellhead pressure can change over in time (transient) and hence specified as a series of time steps. Once these conditions are specified, the simulation is launched. In course of the simulation, the system of conservation equations can be solved over a number of time steps to derive the distribution of volume fractions, velocities, pressure (and other variables) in the well. Details of exemplary fluid models that can be used by simulator <NUM> are set forth in International Patent Application No. <CIT>.

In one embodiment, the simulator <NUM> can be embodied by the computer system <NUM> as described above with respect to <FIG>.

During slug flow, the production flow rates at the surface for oil/water/gas over time together with other determined parameters (such as downhole pressure, well-head pressure(s)), and other fluid properties) as determined by the simulator <NUM> can be compared and matched to the corresponding actual measured values. For example, the predicted production flow rates at the surface for oil/water/gas over time as determined by the simulator <NUM> can be compared to the measured flow rates at the surface for oil/water/gas over time as output by the multiphase flow meter <NUM>. In another example, downhole pressure(s) over time as determined by the simulator <NUM> can be compared to the measured downhole pressure(s) over time as output by the downhole pressure sensor(s) <NUM>. In yet another example, well-head pressure(s) over time as determined by the simulator <NUM> can be compared to the measured well-head pressure(s) over time as output by the well-head pressure sensor(s) <NUM>. Such comparisons can be used to refine or tune the model employed by the simulator <NUM> until a desired matching condition is obtained. Once the desired matching condition is obtained, the output of the simulator <NUM> can be used to determine one or more intervals (e.g., zones) of the well that contribute to the slug flow and possibly the underlying cause of such slug flow. The simulator <NUM> can store in computer memory data that identifies one or more intervals of the well that contribute to slug flow and the underlying cause of the slug flow for reservoir analysis and planning (such as intervention or re-fracturing).

<FIG> illustrates a workflow carried out by the transient multiphase wellbore flow simulator <NUM> of <FIG> that analyzes flow characteristics of produced fluid at the surface in order to detect slug flow, characterize the slug flow originating from one or more well intervals, determine the underlying cause of such slug flow, and store in computer memory data related to such analysis for reservoir analysis and planning. The workflow begins in block <NUM> where the simulator <NUM> optionally controls the well-head choke <NUM> in order to induce slug flow in the produced fluid. Alternatively, the produced fluid can exhibit slug flow behavior without being induced by controlled behavior of the choke <NUM> but due to the downhole conditions of the well.

In block <NUM>, the simulator <NUM> analyzes the surface flow rate measurements for the phases of the produced fluid over time as output by the multiphase flow meter <NUM> in conjunction with other pressure measurements (e.g., pressure upstream and downstream of choke as measured by the well-head pressure sensor(s) <NUM>, and downhole pressure measurements as measured by the downhole pressure sensor(s) <NUM>) in order to detect slug flow in the produced fluid. For example, the slug flow can be detected by automatically checking for and detecting periodic oscillatory behavior in the surface flow rate measurements for the phases of the produced fluid over time and in the other pressure measurements over time.

In block <NUM>, the simulator <NUM> checks whether slug flow has been detected in the produced fluid in block <NUM>. If not, the operation returns back to block <NUM> to wait for the detection of slug flow. In the event that slug flow is detected, the operations continue to block <NUM>.

In block <NUM>, the simulator <NUM> analyzes the surface flow rate measurements for the phases of the produced fluid over time as output by the multiphase flow meter <NUM> in conjunction with other measurements (e.g., pressure upstream and downstream of choke as measured by the well-head pressure sensor(s) <NUM>, downhole pressure measurements as measured by the downhole pressure sensor(s) <NUM>, chemical analysis measurements, etc.) in order to characterize properties of the slug flow (such as amplitude/frequency/period of slugs) over time and determine one or more intervals (e.g., zones) of the well that contribute to the slug flow.

In one embodiment, as part of block <NUM>, the simulator <NUM> can derive the amplitude/frequency/period of slugs, individual phase flowrates and PVT properties observed at the surface, and use such data as input data for the solution. From the solution, the wellbore volume necessary to obtain the observed slug flow is calculated. The additional consideration of slip between phases allows to estimate the location, cross-section and the total length of the well interval that contributes to the slug flow. These properties can be computed for the transient flow using algorithms available in commercial software packages such as OLGA.

In another embodiment, as part of block <NUM>, the simulator <NUM> can determine production flow rates at the surface for oil/water/gas over time together with other determined parameters (such as downhole pressure(s), well-head pressure(s)), other fluid properties, etc.) for varying geometrical properties of the well. These determined parameters (e.g., simulated production flow rates, downhole pressure(s), well-head pressure(s), fluid properties, etc.) for the varying geometrical properties of the well as determined by the simulator <NUM> can be compared to corresponding measured parameters to determine whether a sufficient match is obtained. The geometry of the well can be estimated when the sufficient match is obtained. The location, cross-section and the total length of the well interval that contributes to the slug flow can be determined from the estimated geometry of the well. It is found that the amplitude and frequency of the slugs at surface is a strong function of the position along the well at which the slug originates, both because of the length it has to travel before reaching the surface and also the effect of the possible undulations of the lateral portion of the well, as those may act as a kind of separator, amplifying the amplitude of the slugs. Matching predicted slug amplitude and frequency at surface with measured surface amplitude and frequency for a given wellbore trajectory allows the determination of the location of origin of the slugs.

In block <NUM>, the simulator <NUM> can analyze the measurements over time in order to determine the underlying cause of the slug flow (such as depleted formation or well damage/fracture collapse). Given the PVT properties of the produced hydrocarbon, there is a minimum downhole pressure that is required to generate slugs. If it is predicted or measured that this pressure level is not reached inside the wellbore, then it has to be reached inside the fracture, indicating that the fracture is intersecting a depleted zone.

In block <NUM>, the simulator <NUM> stores in computer memory data that identifies the one or more intervals of the well that contribute to slug flow as determined in block <NUM> and the underlying cause of the slug flow as determined in block <NUM> for reservoir analysis and planning (such as intervention or re-fracturing).

In one embodiment shown in <FIG> and <FIG>, a BHA <NUM> can be moved along the sequence of intervals and associated sliding sleeves <NUM> of a well to clean out the intervals of the well. The well includes a surface-located platform and derrick and vertical casing similar to the well of <FIG> that are not shown for the sake of simplicity of description. As shown in <FIG>, the BHA <NUM> includes a top connection <NUM> for connection to the tubing <NUM> and may comprise a mechanical, or hydraulic disconnect as are commonly known. The BHA <NUM> includes one or more circulation and orifice subs (one shown as <NUM>) that provide a supply of fluid for the clean out operations as discussed further herein. The BHA <NUM> can optionally include the shifting tool <NUM> as described herein. The circulation and orifice sub may be provided on either side of the shifting tool <NUM>. The BHA <NUM> can also optionally include a jetting tool (not shown) below the shifting tool <NUM>, where the jetting tool includes jetting ports to provide a jet of high pressure liquid to puncture holes within the production tubing of the well. The BHA <NUM> may also optionally include a production packer (not shown) for engagement and sealing upon the casing during jetting operations. The BHA <NUM> may also optionally include a bull nose (not shown) at the end of the tool assembly although it will be appreciated that the bull nose may be omitted or replaced with other equipment as desired. Note that sand, proppant, rock fragments and/or other solid debris can be deposited in the wellbore of one or more intervals of the well prior to the clean out operations. The circulation and orifice sub(s) of the BHA <NUM> provides a supply of fluid that can mobilize such solids, and the mobilized solids can be carried in the return fluid that returns to the surface as shown in <FIG>. The return fluid can also carry solids (e.g., sand, proppants, and rock fragments) that are produced from the fractures (and possibly the adjacent formation) in fluid communication with open sliding sleeves that are upstream and possibly downstream of the BHA <NUM> as shown. As part of the clean out operations, one or more parameters that characterize solids production over the intervals and associated sliding sleeves of the well can be calculated as the BHA <NUM> is moved along the sequence of intervals during the workflow that cleans out the intervals of the well. The one or more parameters that characterize solids production of the intervals and associated sliding sleeves of the well can be used to dynamically control the operations and/or plan the next treatment of the well to reduces solids production of the well (if need be) and/or plan production strategies for the well that reduces solids production of the well (if need be).

<FIG> illustrates a workflow carried out by the data analyzer <NUM> of <FIG> to analyze the flow characteristics of return fluid during clean out operations over one or more intervals of a well. The workflow begins in block <NUM> where the BHA <NUM> is moved past a particular sliding sleeve of the well with the supply of fluid to and from the BHA <NUM> established for clean out of solids above and/or below the particular sliding sleeve. In this block <NUM>, the supplied fluid can mobilize solids near the particular sliding sleeve, and the mobilized solids can be carried in the return fluid that returns to the surface. The return fluid can also carry solids that are produced from the fractures (and possibly the adjacent formation) that are in fluid communication with the open sliding sleeves upstream and downstream of the BHA tool position. In block <NUM>, the data analyzer <NUM> can measure the surface flow rate of solids that are part of return fluid over time and use the measure flow rate of solids to determine measured solid production for the intervals and associated slide sleeves of the well as a function of the location of the BHA <NUM>. The data analyzer <NUM> can optionally use downhole pressure measurements to correct measured flow rates in order to account for leakoff of the supplied fluid into the fractures and/or formation. In block <NUM>, the data analyzer <NUM> derives a model of solids production for the intervals and associated sliding sleeves of the well based on position (depth) of the BHA <NUM> in the well. In block <NUM>, the data analyzer <NUM> solves the model of solids production as derived in the block <NUM> for the current location of the BHA <NUM> using the measured solid production as determined in block <NUM> for the current location of the BHA <NUM> as a constraint in order to solve for parameters of the model. In block <NUM>, the data analyzer <NUM> can employ the model parameters solved in block <NUM> to derive parameters that characterize solids production for the particular sliding sleeve, such as volume of solids produced from fractures and/or the formation in fluid communication with the particular sliding sleeve.

Note that the operations of blocks <NUM> to <NUM> can be performed iteratively over a sequence of sliding sleeves for the intervals of the well order to derive the parameters that character solids production over the sliding sleeves and associated intervals of the well. For example, the parameters can be combined to determine a profile of solids production over the sequence of sliding sleeves and associated intervals of the well. For example, the profile of solids production can include volume of solids produced from fractures over well depths that encompass the sequence of sliding sleeves as well as a mass distribution of deposited solids over one or more intervals of the well. The sequence of sliding sleeves and corresponding intervals that are cleaned out can be varied as desired. For example, the well intervals and corresponding sliding sleeves can be cleaned out from the heel to the toe of the well or vice versa.

In one example where the BHA <NUM> supplies fluid to the wellbore in an underbalanced condition (i.e., less than the formation pressure) for clean out, the production of solids from fractures that are in communication with a sliding sleeve can be described by an exponentially decreasing function of the form: <MAT> where Usand is the rate of solids production (e.g., kg/min) from the i-th sliding sleeve of the well,.

Note that Eqn. (<NUM>) can also describe the production of solids from fractures that are in communication with a sliding sleeve located above the position of the BHA <NUM>.

We also assume that solids may be deposited in the wellbore next to each sleeve (or between sleeves), where such solids have a distribution described by an exponentially decreasing function of the form: <MAT> where msand is the solid distribution (e.g., kg/m) along the wellbore next to the i-th sliding sleeve,.

We can also assume that no solids production occurs from the sleeves below the BHA <NUM>, which is typically correct for slightly underbalanced types of clean out operations as well as balanced and overbalanced type of clean out operations.

Under these assumptions, a profile of solids concentration as the BHA <NUM> is moved along the sliding sleeves of the well can be described by the following parametric equation: <MAT> where Csolids is solids concentration (kg added to cubic meters) for a given location (depth) x of the BHA as the BHA is moved along the sliding sleeves of the well,.

In this Eqn. (<NUM>), the solids concentration Csolids represents the contribution of solids from all open sliding sleeves of the well. The first summation term is derived from the exponentially decreasing function of Eqn. (<NUM>) and represents the contribution of solids that are produced from the fractures that are in fluid communication with the open sliding sleeves of the well. The second summation term is derived from the exponentially decreasing function of Eqn. (<NUM>) and represents the contribution of deposited solids near (or between) the sliding sleeves of the well.

The parametric equation of Eqn. (<NUM>) can be used as the model of solid production of block <NUM> for the workflow of <FIG>. The measured solids concentration of block <NUM> can be used as a constraint to find a best-fit solution to the parametric equation of Eqn. (<NUM>) as the BHA <NUM> is moved along the sliding sleeves of the well. The solution provides values for the coefficients Ai, αi, Bi, βi, and xi of the parametric equation of Eqn. (<NUM>) for a sequence of sliding sleeves of the well. The solved-for values can be used to derive parameters that characterize the solids production from each sliding sleeve. In one example, these parameters can include a total volume of solids produced from the fractures of a given sliding sleeve, which can be calculated as: <MAT>.

The parameters Vsolidsi of Eqn. (<NUM>) for the sequence of sliding sleeves can be combined to determine a profile of solids production over the sequence of sliding sleeves of the well. For example, the profile of solids production can include the volume of solids produced from fractures and/or formation over well depths that encompass the sequence of sliding sleeves as derived from the parameters Vsolidsi for the sequence of sliding sleeves.

The parameters of the model can also provide a mass distribution of solids over one or more intervals of the well, which can be calculated as: <MAT>.

<FIG> and <FIG> are plots that illustrate the data processing operations of the data analyzer during an exemplary slightly underbalanced clean out operation according to the workflow of <FIG>. In this example, the clean out operation is performed on a well over a sequence of five sleeves at depths ranging from <NUM>-<NUM> with a pumping rate of fluid of <NUM>. The annulus volume capacity of the well was <NUM>. 07854m3/m which corresponds to internal wellbore diameter of <NUM> and tubing external diameter of <NUM>. (model data). The five perforation clusters are located at depths of <NUM>, <NUM>, <NUM>, <NUM> and <NUM>.

<FIG> show a plot of the measured solid concentration as derived in block <NUM> as function of BHA location (depth) in the well, which is labeled "measured sand conc. " It also shows a plot of the modeled sand concentration as derived in block <NUM> as a function of BHA location (depth) in the well, which is labeled "sand concentration. " It also shows a plot of total solids volume, labeled "total sand volume.

<FIG> shows a plots that represent a profile of solids production over the sequence of five sliding sleeves as derived from the model fitting and calculations of blocks <NUM> and <NUM>. The plots labeled "sand flowed back" represent the volume of solids (in kg) produced from fractures over well depths that encompass the sequence of five sliding sleeves as derived from the parameters Vsolidsi of the sequence of sliding sleeves. And the plots labeled "sand distribution" represent the mass distribution (in kg/meter) of deposited solids over well depths that encompass the sequence of five sliding sleeves as derived by the parameter Msolids of Eqn.

Note that the parameter(s) that characterize solids production of the intervals and associated sliding sleeves of the well can be used to dynamically control the operation of the clean out operation. For example, the parameter(s) that characterize the solids produced from fractures can be used to control the pumping rate of the fluid supplied downhole for balanced return where there is little or no solid produced from the fractures during the clean out operation.

In other cases, the return rate can be higher than the pumping rate of the fluid supplied downhole and spikes in the solid concentration in the return fluid can be attributed to both deposited solids from the wellbore and solid production from fractures. The maximum possible solid produced from a sliding sleeve can be computed as an excess between total local solid production and volumes of sand that can be accumulated in the wellbore. For example, for a wellbore section with length of <NUM> and internal diameter of <NUM> having one perforated cluster and produced sand volume of <NUM>, the potential maximum volume of sand with a specific gravity of <NUM> and bulk density of <NUM>/cm3 produced from such sliding sleeve can be estimated as <NUM>-<NUM>*(<NUM>^<NUM>/<NUM>/<NUM>* <NUM>=<NUM>. The maximum volume can be used as a constraint whereby measured solid volumes above this limit can be attributed to solids produced from fractures or the formation (and not from deposited sand in the wellbore).

There have been described and illustrated herein several embodiments of methods and systems for analysis of hydraulically-fractured reservoirs. While particular embodiments have been described, it is not intended that the disclosure be limited thereto, as it is intended that the disclosure be as broad in scope as the art will allow and that the specification be read likewise. For example, while particular types of well designs and well completions have been disclosed, it will be understood that other types of well designs (including vertical wells and multilateral horizontal wells) and other types of well completions (including different casing and liner configurations and different production tubing configurations and different perforation configurations) can be used. Multilateral wells include multi -branched wells, forked wells, wells with several laterals branching from one horizontal main wellbore, wells with several laterals branching from one vertical main wellbore, wells with stacked laterals, and wells with dual- opposing laterals. It will therefore be appreciated by those skilled in the art that yet other modifications could be made to the provided disclosure within the scope of the invention as claimed.

Claim 1:
A method for characterizing a hydraulically-fractured hydrocarbon-bearing formation that is traversed by a well that comprises a plurality of well intervals from which production tubing (<NUM>, <NUM>) gives fluid communication to a surface-located facility, the method comprising:
i) using a downhole tool (<NUM>, <NUM>, <NUM>, <NUM>) to isolate one or more of the well intervals from the surface-located facility while allowing fluid communication from one or more others of the well intervals to the surface-located facility;
ii) thereafter, analyzing flow characteristics of the produced fluid; and
iii) deriving at least one local formation property that characterize the hydraulically-fractured formation adjacent the well intervals which are in fluid communication with the surface-located facility based on such surface flow characteristics;
characterized in that the flow characteristics of produced fluid are surface flow characteristics of the produced fluid that flows from the well back to the surface-located facility, and in that the surface flow characteristics of the produced fluid include flow rates for different phases of the produced fluid and are measured by a surface-located multiphase flowmeter (<NUM>).