US20150322775A1

US20150322775A1 - Systems and methods for monitoring wellbore fluids using microanalysis of real-time pumping data

Info

Publication number: US20150322775A1
Application number: US14/763,404
Authority: US
Inventors: Christopher Marland; Ian Mitchell; James Randolph Lovorn
Original assignee: Halliburton Energy Services Inc
Current assignee: Halliburton Energy Services Inc
Priority date: 2013-01-28
Filing date: 2013-01-28
Publication date: 2015-11-12
Also published as: MX2015007613A; EP2920412A1; MX365398B; WO2014116249A1; BR112015015307A2; EP2920412B1

Abstract

Systems and methods for obtaining information about one or more fluids in a wellbore in a subterranean formation are disclosed herein. A fluid monitoring system comprises a fluid measurement device and a data system that receives a first and second set of data. A first set of data and second set of data may be obtained and compared to determine the location of one or more fluids in a wellbore in real time.

Description

BACKGROUND

The present disclosure relates to subterranean operations and, more particularly, to an apparatus and methods for monitoring and characterizing fluids in a subterranean formation.
Many subterranean operations require introducing one or more fluids into the subterranean formation. For instance, drilling operations play an important role when developing hydrocarbon wells. During the drilling operations, a drill bit passes through various layers of earth strata as it descends to a desired depth. Drilling fluids are commonly employed during the drilling operations and perform several important functions including, but not limited to, removing the cuttings from the well to the surface, controlling formation pressures, sealing permeable formations, minimizing formation damage, and cooling and lubricating the drill bit.
Maintaining fluid pressure in the wellbore is often critical to these and other subterranean operations in a wellbore. When performing subterranean operations such as drilling or completing wells, it is often desirable to monitor, locate, and image deformations in the well casing and/or the tubing used. It is also desirable to monitor the integrity of the cement layer around the well to detect any problems in the cement or changes in the formation during hydrocarbon production near the well or well flooding. Fluids placed in a wellbore may migrate or flow into another portion of the subterranean formation other than their intended location, for example, in an area of the formation that is more porous or permeable. Fluid loss may result in, among other problems, incomplete or ineffective treatment of the formation, increased cost due to increased volumes of fluid to complete a treatment, and/or environmental contamination of the formation. While treatment fluids are often formulated and wells are often constructed so as to reduce the likelihood or amount of fluid loss into the formation, fluid loss still may occur, particularly in damaged or highly permeable areas of a subterranean formation or wellbore.
Conventional methods of detecting fluid loss typically involve measuring the amount of fluid pumped into the wellbore and comparing that with the amount of fluid circulated out of the wellbore. However, such methods are usually only performed after the operation using the fluid has been completed, and do not provide enough information during the operation to make adjustments to attempt to compensate for the fluid loss or otherwise remedy whatever is causing the loss of fluid. This may require performing the same treatment or operation on the same wellbore multiple times until it can be performed without significant fluid loss. Moreover, such methods typically are not capable of identifying the specific fluid that was lost into the formation, the identity of which may be important in order to compensate for the lost fluid and/or remedy or prevent additional problems (e.g., formation damage, environmental problems, etc.) that may result from the loss of particular fluids into the formation.
Additionally, well logging instruments may be used to probe subsurface formations to determine formation characteristics. Sonic tools are an example of well logging tools that may be used to provide information regarding subsurface acoustic properties that can be used to analyze the formation. During a typical sonic logging of a formation, an acoustic logging instrument or tool is lowered into a wellbore that transverses a formation of interest. The acoustic logging tool may be mounted to the drill collar or other devices and directed downhole.
However, the receiver(s) of the acoustic logging tool are typically sensitive to undesired acoustic noise that may result from normal drilling operations. For instance, the undesired acoustic noise may radiate with reduced attenuation through a hard steel drill collar. The acoustic noise may then couple to the receiver of the acoustic logging tool and be converted into electrical noise along with the desired signal. This background noise may be a result of the downhole operations or produced by other acoustic sources and therefore may introduce an error in the measurements by the acoustic logging tool. Additionally, traditional logging tools often involve complex downhole equipment and sensors which may be expensive to operate and maintain.
It is therefore desirable to detect the level of fluids from the surface and in real time.

BRIEF DESCRIPTION OF THE DRAWING(S)

The present disclosure will be more fully understood by reference to the following detailed description of the preferred embodiments of the present disclosure when read in conjunction with the accompanying drawings, in which like reference numbers refer to like parts throughout the views, wherein:

FIG. 1A depicts a wellbore drilling environment in accordance with an illustrative embodiment of the present disclosure;

FIGS. 1B and 1C depict various views of a retention pit in accordance with an embodiment of the present disclosure; and

FIG. 2 depicts an arrangement of a device in accordance with an illustrative embodiment of the present disclosure.

The disclosure may be embodied in other specific forms without departing from the spirit or essential characteristics thereof. The present embodiments are therefore to be considered in all respects as illustrative and not restrictive, the scope of the disclosure being indicated by the appended claims rather than by the foregoing description, and all changes which come within the meaning and range of equivalency of the claims are therefore intended to be embraced therein.

DETAILED DESCRIPTION OF THE DISCLOSURE

Illustrative embodiments of the present disclosure are described in detail herein. In the interest of clarity, not all features of an actual implementation may be described in this specification. It will of course be appreciated that in the development of any such actual embodiment, numerous implementation-specific decisions may be made to achieve the specific implementation goals, which may vary from one implementation to another. Moreover, it will be appreciated that such a development effort might be complex and time-consuming, but would nevertheless be a routine undertaking for those of ordinary skill in the art having the benefit of the present disclosure.
The terms “couple” or “couples” as used herein are intended to mean either an indirect or a direct connection. Thus, if a first device couples to a second device, that connection may be through a direct connection, or through an indirect electrical or mechanical connection via other devices and connections. The term “upstream” as used herein means along a flow path towards the source of the flow, and the term “downstream” as used herein means along a flow path away from the source of the flow. The term “uphole” as used herein means along the drillstring or the hole from the distal end towards the surface, and “downhole” as used herein means along the drillstring or the hole from the surface towards the distal end.
It will be understood that the term “oil well drilling equipment” or “oil well drilling system” is not intended to limit the use of the equipment and processes described with those terms to drilling an oil well. The terms also encompass drilling natural gas wells or hydrocarbon wells in general. Further, such wells can be used for production, monitoring, or injection in relation to the recovery of hydrocarbons or other materials from the subsurface. This could also include geothermal wells intended to provide a source of heat energy instead of hydrocarbons.
For purposes of this disclosure, an “information handling system” may include any instrumentality or aggregate of instrumentalities operable to compute, classify, process, transmit, receive, retrieve, originate, switch, store, display, manifest, detect, record, reproduce, handle, or utilize any form of information, intelligence, or data for business, scientific, control, or other purposes. For example, an information handling system may be a personal computer or tablet device, a cellular telephone, a network storage device, or any other suitable device and may vary in size, shape, performance, functionality, and price. The information handling system may include random access memory (RAM), one or more processing resources such as a central processing unit (CPU) or hardware or software control logic, ROM, and/or other types of nonvolatile memory. Additional components of the information handling system may include one or more disk drives, one or more network ports for communication with external devices as well as various input and output (I/O) devices, such as a keyboard, a mouse, and a video display. The information handling system may also include one or more buses operable to transmit communications between the various hardware components.
For the purposes of this disclosure, computer-readable media may include any instrumentality or aggregation of instrumentalities that may retain data and/or instructions for a period of time. Computer-readable media may include, for example, without limitation, storage media such as a direct access storage device (e.g., a hard disk drive or floppy disk drive), a sequential access storage device (e.g., a tape disk drive), compact disk, CD-ROM, DVD, RAM, ROM, electrically erasable programmable read-only memory (EEPROM), and/or flash memory; as well as communications media such wires, optical fibers, microwaves, radio waves, and other electromagnetic and/or optical carriers; and/or any combination of the foregoing.
The present disclosure generally relates to subterranean operations. More particularly, the present disclosure relates to continuous or substantially continuous monitoring of fluids in well casing and/or tubing, fluid distribution inside and around a well, and/or cement layer integrity around a well. The present disclosure may be used to calculate the position of fluids in any subterranean pumping operation. For example, the disclosure may be applied in primary cementing, stimulation, remedial, and/or drilling operations.
Turning now to FIG. 1A, oil well drilling equipment used in an illustrative drilling environment is shown. A drilling platform 102 supports a derrick 104 having a traveling block 106 for raising and lowering a drill string 108. A kelly 110 supports the drill string 108 as it is lowered through a rotary table 112. A drill bit 114 is driven by a downhole motor and/or rotation of the drill string 108. As drill bit 114 rotates, it creates a wellbore 116 that passes through an earth formation 13Q. A pump 120 may circulate drilling fluid through a feed pipe 122 to kelly 110, downhole through the interior of drill string 108, through orifices in drill bit 114, back to the surface via the annulus between the drill string 108 and the wellbore wall, and into a retention pit 124. The drilling fluid may transport cuttings from the borehole into the retention pit 124 and aids in maintaining the borehole integrity. The drilling fluid may also serve to lubricate the drill bit. The volume of drilling fluid pumped into the wellbore 116 may be measured in advance off-site or at the rig location. Alternatively, the volume of drilling fluid pumped into the wellbore 116 may be measured by one or more fluid measurement devices as it is being pumped downhole.
Turning now to FIGS. 1B and 1C, the retention pit 124 may contain one or more fluid measurement devices 136 and 138. Fluid measurement devices may be located on a conduit 140 leading into the retention pit 124 or on the retention pit 124 itself. Fluid measurement devices may include, but are not limited to, sensors and flow meters. Sensors may be acoustic, level height, or any type appropriate to determine the height of fluid within the retention pit 124. Sensors and other surface collection equipment may be calibrated to convert the height of fluid within the retention pit 124 to fluid volume. Flow meters may include acoustic sensors, nuclear sensors, coriolis meters, Doppler radar, vortex flow meters or sensors, calorimetric flow meters or sensors, magnetic flow meters or sensors, electromagnetic flow meters or sensors, differential pressure meters or sensors, open channel meters or sensors, or any appropriate flow meter without departing from the spirit of this disclosure. The density of a fluid may be captured by a flow meter that includes nuclear, sonic, or similar devices. Similar measurements for fluid pumped into the wellbore may be collected.
Referring now to FIG. 2, a cross-sectional view of a wellbore 216 that has been drilled with casing 228 and tubing 226 in accordance with certain embodiments of the present disclosure is denoted generally with reference numeral 200. The casing 228 and tubing 226 may be concentric tubes inside the wellbore 216. An annulus 232 is formed between the casing 228 and the formation 230. Cement 218 is pumped down the wellbore 216, e.g., through the interior of the casing 228 and up through the annulus 232 in order to hold the casing 228 in place. The cement 218 may be directed downhole using a cement pumping unit (not shown) or other types of rig pumping equipment (not shown), as appropriate. This equipment may include fluid measurement devices to measure the amount of cement being pumped downhole. Alternatively, the volume of cement to be directed downhole may be pre-measured based on the volume of the annulus to be filled.
After the wellbore 116 is drilled, a filling material 214 may be directed downhole. Filling material 214 may be used fill the space in between casing 228 and tubing 226. The filling material 214 may be a mud, for example, but is not intended to be limited to such.
Additionally, one or more spacing fluids may be directed downhole. A spacing fluid (not shown) may be directed downhole before and/or after the cement 218 is pumped. Spacing fluid may act as a barrier between the cement 218 and the filling material 214 to prevent contamination of the two fluids. An operator may detect how much cement 218 returned to the annulus after being pumped downhole by measuring the amount of spacing fluid that was displaced from the annulus and returned to the retention pit 124. If spacing fluid is not used, any fluid directed downhole immediately prior to the cement 218 may serve this purpose.
A data system 202 may be coupled to the pump 120 using a hard-wired, digital, or wireless connection. However, the data system 202 and the pump 120 may be coupled by any known means without departing from the spirit of this disclosure. In some embodiments, the data system may be coupled to fluid measurement devices that are located within the retention pit 124. Fluid measurement devices may include, but are not limited to, sensors and flow meters. In other embodiments, fluid measurement devices may be coupled to the pump 120, and the pump 120 may be coupled to the data system 202 as shown in FIG. 2. In other embodiments, the data system 202 may be coupled to fluid measurement devices, which are operable to measure fluid pressure, density, and volume, and are mounted in piping systems located downstream from the pump 120. The data system 202 functions to receive information about various fluids in the wellbore, such as cement 218, filling material 214, or spacing fluid. It may receive information about the volume of a fluid that is directed into and pumped out of the wellbore 116 via the pump 120.
In certain embodiments, the data system 202 may be communicatively coupled to an external communications interface (not shown). The external communications interface may permit the data from the data system 202 to be remotely accessible by any remote information handling system communicatively coupled to the external communications interface via, for example, a satellite, a modem or wireless connections. In one embodiment, the external communications interface may include a router.
A first set and a second set of data may be received at the data system 202 over a period of time in short intervals, or in real time. The short intervals may be periods of minutes or substantially continuously. The first set of data may relate to one or more fluids directed into the wellbore 116 via the pump 120, and the second set of data may relate to one or more fluids pumped out of the wellbore 116 via the pump 120. Data parameters may include, but are not limited to, fluid volume, fluid flow rate, fluid pressure, and fluid density. These data parameters may be received with respect to cement 218, filling material 214, one or more spacing fluids, and any other fluid that may be directed downhole during drilling operations. In this embodiment, the first and second sets of data both may be actual, or measured, data sets, rather than theoretical data sets. The first set of data may be compared to the second set of data to determine the location of a fluid in the wellbore 116 at any point in time. For example, the first and second sets of data may be compared using a time-track or by performing a regression. However, any known method of comparison may be used to compare the data sets without departing from the scope of this disclosure.
In accordance with another embodiment of the present disclosure, a first set of data may be modeled based on a model wellbore that may have similar features to the wellbore 116. Before any fluids are actually directed downhole, the first set of data, which may relate to fluids expected to be directed into the wellbore 116, may be modeled based on an expected fluid volume to be pumped into the wellbore 116 with respect to time. The first set of data may be modeled over a period of time in short intervals. The short intervals may be periods of minutes or substantially continuously. The model may be based on a planned schedule of fluids to be directed into the wellbore 116. Thus, the first set of data may be a theoretical data set. A second set of data may relate to one or more fluids pumped out of the wellbore 116 via the pump 120. The second set of data may be an actual, measured data set, received at the data system 202. As in the previous embodiment, data parameters may include, but are not limited to, fluid volume, fluid flow rate, fluid pressure, and fluid density. These data parameters may be received with respect to cement 218, filling material 214, one or more spacing fluids, and any other fluid that may be directed downhole during drilling operations. As in the previous embodiment, the first set of data may be compared to the second set of data to determine the location of a fluid in the wellbore 116 at any point in time. For example, the first and second sets of data may be compared using a time-track or by performing a regression. However, any known method of comparison may be used to compare the data sets without departing from the scope of this disclosure.
In accordance with another embodiment of the present disclosure, a first set of data may relate to one or more fluids expected to exit the wellbore 116 over a period of time in short intervals. The short intervals may be periods of minutes or substantially continuously. Using the information relating to fluids expected to be directed into the wellbore 116, a user may be able to predict a data set of fluids expected to exit the wellbore 116. Additionally, as fluids are actually directed into the wellbore 116, a user may be able to collect or model a data set of fluids expected to exit the wellbore 116. Thus, the first data set may relate to fluids expected to exit the wellbore and may be a theoretical data set. A second set of data may relate to one or more fluids pumped out of the wellbore 116 via the pump 120. The second set of data may be an actual, measured data set, received at the data system 202. As in previous embodiments, data parameters may include, but are not limited to, fluid volume, fluid flow rate, fluid pressure, and fluid density. These data parameters may be received with respect to cement 218, filling material 214, one or more spacing fluids, and any other fluid that may be directed downhole during drilling operations. As in previous embodiments, the first set of data may be compared to the second set of data to determine the location of a fluid in the wellbore 116 at any point in time. For example, the first and second sets of data may be compared using a time-track or by performing a regression. However, any known method of comparison may be used to compare the data sets without departing from the scope of this disclosure.
Based on the first and second sets of data, which may be theoretical data or measured data depending on the embodiment, the operator may be able to determine the location of each fluid in the wellbore 116 at any point in time. Comparisons may be used to deduce further information about the fluids in the wellbore 116 and about the stability of the casing 228 and formation 130. The theoretical data sets may include a time track of the volume of fluid being pumped into the wellbore 116 against the volume being displaced out of the wellbore 116. If there are no cracks in the casing 228 or formation 130, the actual data set should match the theoretical data set. Deviations from the theoretical data set may indicate that fluid loss to the formation 130 due to cracks is occurring or that fluids from the wellbore 116 (i.e., hydrocarbons) are entering the fluid path. Additionally, regression models may be run to compare the data of the fluid expected to be directed into the wellbore 116, directed into the wellbore 116, or expected to exit the wellbore 116 with that of the fluid exiting the wellbore 116. Any other type of known modeling and analysis may be done on the data without departing from the scope of this disclosure.
If the comparisons between any two sets of data indicate that a different volume of fluid was returned to the surface than was expected, there may be a crack in the casing 228 or formation 130. The crack may be located at the bottom of the wellbore 116, where the highest wellbore pressure is located. Pressure modeling may be performed to model the pressure variation along the wellbore 116. This information may be used to determine where fluid loss may be occurring. Additionally, other knowledge such as zones of weakness in the formation 130, may be applied to locate areas of potential fluid loss. The rate of pumping may be decreased in order to decrease the level of pressure in the wellbore 116 and prevent the crack in the casing 228 or formation 130 from spreading. Further, if the decreased pressure does not adequately address the crack in the casing 228 or formation 130, a well operator may be able to repair the crack in the casing 228 or formation 130 during drilling or cementing operations and before the crack creates additional problems.
Further, using the first and second sets of data, the height and/or relative position of each fluid in the wellbore 116 may be calculated as a function of the available volume between multiple components or between one or more components and the wellbore wall 234. The volume available can be calculated at any interval using the following formula:
Fluid volume(bbls/ft)=(OD²−ID²)/1029.4,
where OD represents the Outer Diameter of a larger component in which fluid may be placed and ID represents the inner diameter of a smaller component in which fluid may be placed. For annular volumes, the larger component may be the wellbore 116, and the smaller component may be the casing 228. The diameters of these components may be measured before they are inserted into the wellbore 116. The constant 1029.4 represents a constant derived from volumetric calculations to convert the difference in diameters between two pipes into a volumetric area.
The fluid volume available for any given interval will determine the top and bottom of each fluid as pumped. The top and bottom of any fluid will form a vertical height of a fluid column component, which will determine the addition to the overall hydrostatic column of all fluids. Fluids of discrete density can be converted into a pressure as a result of pressure gradient calculations. Each fluid therefore applies a pressure over its column height. The pressure at any point in the wellbore 116 is derived from a sum of all the pressures acting on it. Therefore, an overall pressure may be calculated at any depth. Based on that depth, the effective fluid density of all the individual columns may be calculated using the following formula:
Density=Pressure(psi)/(Vertical Depth(ft)×0.052)
Therefore, at any given point in time, the operator may calculate the height, density, and pressure of each fluid column. Density data may be added into the model as well. For example, a fluid with higher density may be added into the wellbore 116 after a fluid of lower density. Even without pumping, the higher density fluid will naturally surpass the lower density fluid due to gravity until the pressures inside and outside the casing 228 are balanced. Due to this natural phenomenon, an operator may calculate how much fluid is being returned to the surface as a result of pumping and how much is being returned as a result of fluid density. This data may be added into the model to determine more information about the location of any cracks in the casing 228 or formation 130.

Example

For example, in a wellbore that is 5000 feet deep, the following relationships apply.
Vertical Height Density Pressure

0-1000 ft 9 ppg 468 psi

1000-5000 ft 15 ppg 3120 psi

At 5000 ft, the total pressure in this example wellbore would be 3588 psi, i.e., the sum of the individual fluid columns in the well. The effective fluid density at a particular depth may be calculated according to the following equation:
Effective Fluid Density=Pressure/(Depth×0.052)
Thus, at 5000 ft, the effective fluid density in the example wellbore described in the above table is equivalent to a single fluid column of 13.8 ppg.
As the volume available for fluids changes as a result of changing dimensions of the wellbore 116 or components in the wellbore 116, the overall vertical height of each fluid component will change. As a result, the effect on the overall hydrostatic pressure can be calculated to then model pressure and pumping information to identify the location of fluid loss or gain to a system based on the changes, higher or lower, to the calculated fluid pressure for any given hydrostatic column of fluid or column of mixed density fluids. The pumping data may be measured and analyzed in real time. For purposes of this disclosure, real time may include time intervals of about one second between each data point. In some embodiments, the pumping data may be measured and analyzed substantially continuously. The calculations may also account for the reverse flow of fluids from the annulus 232 into the casing 228 without departing from the spirit of the present disclosure.
The systems and methods of the present disclosure may, among other benefits, provide a low-cost method of detecting fluid loss early in an operation based primarily on surface measurements that require little or no downhole intervention or measurements. The early detection of fluid loss also may increase the efficiency of certain subterranean operations by helping operators to correct fluid loss problems sooner, reducing the need to repeat unsuccessful operations or steps in those operations. Also, by permitting operators to identify the specific fluid being lost into a subterranean formation, the systems and methods of the present disclosure may facilitate more efficient remedial and/or clean-up operations.
If the fluid lost into the formation is identified as a cement, this may inform the operator of the reason why the cement did not cure or set in its intended location, and may, among other benefits, allow the operator to more efficiently correct the condition causing cement loss downhole so that the cementing operation may be performed properly.
In accordance with an exemplary embodiment of the present disclosure, once feeds from one or more sensors are obtained, they may be combined and used to identify various metrics.
For instance, if there is data that deviates from normal expectancy at the rig site, the combined system may show another reading of the data from another sensor that may help identify the type of deviation. As would be appreciated by those of ordinary skill in the art, with the benefit of this disclosure, a data acquisition and control interface may also receive data from multiple rigsites and wells to perform quality checks across a plurality of rigs.
As would be appreciated by those of ordinary skill in the art, with the benefit of this disclosure, one or more information handling systems may be used to implement the methods disclosed herein. In certain embodiments, the different information handling systems may be communicatively coupled through a wired or wireless system to facilitate data transmission between the different subsystems. Moreover, each information handling system may include a computer-readable media to store data generated by the subsystem as well as preset job performance requirements and standards.
The systems and methods of the present disclosure may be used to monitor fluids, characterize fluids, and/or detect fluid loss in conjunction any subterranean operation involving the applicable equipment. For example, the systems and methods of the present disclosure may be used in cementing operations, stimulation operations (e.g., fracturing, acidizing, etc.), completion operations, remedial operations, drilling operations, and the like. A person of skill in the art, with the benefit of this disclosure, will recognize how to apply or implement the systems and methods of the present disclosure as disclosed herein in a particular operation.
In certain embodiments, the systems and methods of the present disclosure also may be used to verify the placement and/or curing of cement in a wellbore. For example, the system and method disclosed herein may be used to monitor the volume, temperature, and pressure of fluids exiting the wellbore to detect exothermic curing of a cement downhole. In certain embodiments, a system or method of the present disclosure may be used to detect fluid loss in a particular wellbore and to identify the specific fluid that has been lost into the formation. That same system or another system may use data regarding the volume, temperature, and pressure of fluids exiting the wellbore to determine that a cement did not cure in its intended location. If the fluid lost into the formation is identified as a cement, this may inform the operator of the reason why the cement did not cure or set in its intended location, and may, among other benefits, allow the operator to more efficiently correct the condition causing cement loss downhole so that the cementing operation may be performed properly.
Additionally, in certain embodiments, the systems and methods of the present disclosure also may be used to, or in conjunction with certain systems and methods used to monitor hookload. In certain embodiments, a system or method of the present disclosure may be used to detect fluid loss in a particular wellbore and to identify the specific fluid that has been lost into the formation. That same system or another system may use data regarding the total effective weight of the apparatus attached to the hook (e.g., BHA, tubing, casing, etc.) to determine information about the volume, temperature, and pressure of fluids in the wellbore.
An embodiment of the present disclosure is a method for obtaining information about one or more fluids in a wellbore in a subterranean formation that includes obtaining a first set of data relating to one or more fluids directed into the wellbore over a period of time in short intervals, obtaining a second set of data relating to one or more fluids exiting the wellbore over a period of time in short intervals; and in real time, determining the location of a fluid in the wellbore based on the first and second sets of data. Optionally the first and second sets of data may be compared by performing a regression. Optionally the location of a fluid in the wellbore is determined based at least in part on the available volume of a plurality of components, wherein the plurality of components includes at least two of the following: a casing, a tubing, and the wellbore. Optionally the first and second sets of data include one or more of the following: fluid volume, fluid pressure, fluid density, and fluid flow rate. Optionally the method further directing two or more fluids downhole, wherein the two or more fluids are of different densities and wherein the second set of data includes fluid density data.
Another embodiment of the present disclosure is a method for obtaining information about one or more fluids in a wellbore in a subterranean formation that includes modeling a first set of data relating to one or more fluids expected to be directed into or expected to exit the wellbore over a period of time in short intervals, obtaining a second set of data relating to one or more fluids exiting the wellbore over a period of time in short intervals; and in real time, comparing the first and second sets of data to determine the location of a fluid in the wellbore. Optionally the first and second sets of data may be compared by performing a regression. Optionally the location of a fluid in the wellbore is calculated based on the available volume of a plurality of components, wherein the plurality of components includes at least two of the following: a casing, a tubing, and the wellbore. Optionally the first and second sets of data include one or more of the following: fluid volume, fluid pressure, fluid density, and fluid flow rate. Optionally the method further includes directing two or more fluids downhole, wherein the two or more fluids are of different densities, and wherein the second set of data includes fluid density data.
Another embodiment of the present disclosure is a fluid monitoring system that includes a data system, one or more fluid measurement devices communicatively coupled to the data system that are configured to detect amounts of fluids directed into or exiting the wellbore, wherein the data system receives a first set of data relating to one or more fluids directed into, expected to be directed into, or expected to exit the wellbore over a period of time, and a second set of data relating to one or more fluids exiting the wellbore over a period of time from the one or more fluid measurement devices, wherein the data system uses the first and second sets of data received to determine the location of one or more fluids in the wellbore in real time. Optionally the data system is coupled to an external communications interface that is remotely accessible. Optionally the first and second sets of data are compared by performing a regression. Optionally the location of a fluid in the wellbore is determined based at least in part on the available volume of a plurality of components, wherein the plurality of components includes at least two of the following: a casing, a tubing, and the wellbore. Optionally the first and second sets of data include one or more of the following: fluid volume, fluid pressure, fluid density, and fluid flow rate.
Therefore, the present disclosure is well-adapted to carry out the objects and attain the ends and advantages mentioned as well as those which are inherent therein. While the disclosure has been depicted and described by reference to exemplary embodiments of the disclosure, such a reference does not imply a limitation on the disclosure, and no such limitation is to be inferred. The disclosure is capable of considerable modification, alteration, and equivalents in form and function, as will occur to those ordinarily skilled in the pertinent arts and having the benefit of this disclosure. The depicted and described embodiments of the disclosure are exemplary only, and are not exhaustive of the scope of the disclosure. The terms in the claims have their plain, ordinary meaning unless otherwise explicitly and clearly defined by the patentee.

Claims

What is claimed is:

1. A method for obtaining information about one or more fluids in a wellbore in a subterranean formation, comprising:

obtaining a first set of data relating to one or more fluids directed into the wellbore over a period of time in short intervals;

obtaining a second set of data relating to one or more fluids exiting the wellbore over a period of time in short intervals; and

in real time, determining the location of a fluid in the wellbore based on the first and second sets of data.

2. The method of claim 1, wherein the first and second sets of data are compared by performing a regression.

3. The method of claim 1, wherein the location of a fluid in the wellbore is determined based at least in part on the available volume of a plurality of components, wherein the plurality of components includes at least two of the following: a casing, a tubing, and the wellbore.

4. The method of claim 1, wherein the first and second sets of data include one or more of the following: fluid volume, fluid pressure, fluid density, and fluid flow rate.

5. The method of claim 1, further comprising:

directing two or more fluids downhole, wherein the two or more fluids are of different densities;

and wherein the second set of data includes fluid density data.

6. A method for obtaining information about one or more fluids in a wellbore in a subterranean formation, comprising:

modeling a first set of data relating to one or more fluids expected to be directed into or expected to exit the wellbore over a period of time in short intervals;

in real time, comparing the first and second sets of data to determine the location of a fluid in the wellbore.

7. The method of claim 6, wherein the first and second sets of data are compared by performing a regression.

8. The method of claim 6, wherein the location of a fluid in the wellbore is calculated based on the available volume of a plurality of components, wherein the plurality of components includes at least two of the following: a casing, a tubing, and the wellbore.

9. The method of claim 6, wherein the first and second sets of data include one or more of the following: fluid volume, fluid pressure, fluid density, and fluid flow rate.

10. The method of claim 6, further comprising:

and wherein the second set of data includes fluid density data.

11. A fluid monitoring system comprising:

a data system;

one or more fluid measurement devices communicatively coupled to the data system that are configured to detect amounts of fluids directed into or exiting the wellbore;

wherein the data system receives

a first set of data relating to one or more fluids directed into, expected to be directed into, or expected to exit the wellbore over a period of time, and

a second set of data relating to one or more fluids exiting the wellbore over a period of time from the one or more fluid measurement devices;

wherein the data system uses the first and second sets of data received to determine the location of one or more fluids in the wellbore in real time.

12. The system of claim 11, wherein the data system is coupled to an external communications interface that is remotely accessible.

13. The system of claim 11, wherein the first and second sets of data are compared by performing a regression.

14. The system of claim 11, wherein the location of a fluid in the wellbore is determined based at least in part on the available volume of a plurality of components, wherein the plurality of components includes at least two of the following: a casing, a tubing, and the wellbore.

15. The system of claim 11, wherein the first and second sets of data include one or more of the following: fluid volume, fluid pressure, fluid density, and fluid flow rate.