Patent Application
20130245947
After a wellbore has been drilled, the wellbore typically is cased by inserting lengths of steel pipe (“casing sections”) connected end-to-end into the wellbore. Threaded exterior rings called couplings or collars are typically used to connect adjacent ends of the casing sections at casing joints. The result is a “casing string” including casing sections and connecting collars that extends from the surface to a bottom of the wellbore. The casing string is then cemented in place to complete the casing operation. After a wellbore is cased, the casing is often perforated to provide access to one or more desired formations, e.g., to enable fluid from the formation(s) to enter the wellbore.
Hydraulic fracturing is an operating technique where a fracturing fluid, typically water with selected additives, is pumped into a completed well under high pressure. The high pressure fracturing fluid causes fractures to form and propagate within the surrounding geological formation, making it easier for formation fluids to reach the wellbore. After the fracturing is complete, the pressure is reduced, allowing most of the fracturing fluid to flow back into the well. Some residual amount of the fracturing fluid may be expected to remain in the surrounding formation and perhaps flow back to the well over time as other fluids are produced from the formation. The volume and return rate of the fracturing fluid is indicative of the physical structure of the created fractures as well as the effective permeability for the newly-fractured completion zone.
During normal operations, the well produces a combination of fluids, typically including a desired hydrocarbon fluid (e.g., oil or gas) and water (i.e., “produced water”). The produced water can originate from multiple sources such as connate water from different formation layers, fracturing fluid, water injected from a remote well and/or steam injected from a remote well. These latter examples are typical of a steam or water flooding operation designed to force hydrocarbons to flow to the producing well.
In order to monitor and optimize hydraulic fracturing operations, and to better understand the relative permeabilities and physical structures of fractures resulting from hydraulic fracturing, it would be beneficial to determine the sources of water produced from each completion zone. For steam operations such as Steam-Assisted Gravity Drainage (SAGD) and water flooding operations, there is likewise a need to assess steam and water sweep areas. Despite these apparent benefits, there exists a need for improved systems or methods for such determinations.
Accordingly, there are disclosed in the drawings and the following description specific examples of downhole systems and methods for water source determination. In the drawings:
It should be understood, however, that the specific embodiments given in the drawings and detailed description thereof do not limit the disclosure. On the contrary, they provide the foundation for one of ordinary skill to discern the alternative forms, equivalents, and modifications that are encompassed together with one or more of the given embodiments in the scope of the appended claims.
Turning now to the figures,
The well 10 is adapted to guide a desired fluid (e.g., oil or gas) from a bottom of the borehole 16 to the surface of the earth 18. Perforations 26 have been formed at a bottom of the borehole 16 to facilitate the flow of a fluid 28 from a surrounding formation (i.e., a “formation fluid”) into the borehole and thence to the surface via an opening 30 at the bottom of the production tubing string 24. Though only one perforated zone is shown, many production wells may have multiple such zones, e.g., to produce fluids from different formations.
The fluid 28 produced by the well includes the desired fluid (e.g., oil or gas) along with water (i.e., “produced water”) originating from one or more sources. For example, the water in the produced fluid 28 may be a mixture of water from the surrounding formation (i.e., “formation water” such as connate water) and fracturing fluid previously pumped into the surrounding formation under high pressure via the production tubing string 24. Alternately, or in addition, the produced water may include water from other formations, or injected water from injection wells (e.g., flood fluid from a remote well). It is noted that the configuration of well 10 in
As described in more detail below, the downhole optical sensor system 12 is adapted to detect concentration(s) of one or more chemical species in the produced fluid 28. In some embodiments, the detected chemical species are known to be present in one or more sources of water contributing to the produced water in the fluid 28. In these embodiments, the downhole optical sensor system 12 makes it possible to determine a portion of the produced water originating from a given one of multiple potential sources of water. For example, the downhole optical sensor system 12 may be adapted to determine a portion of the produced water originating from fracturing fluid. This information can advantageously be used to monitor and optimize hydraulic fracturing operations, and to better understand the relative permeabilities and physical structures of fractures resulting from hydraulic fracturing.
In the embodiment of
In the embodiment of
In at least some embodiments, the fiber optic cable 44 terminates at surface interface 42 with an optical port adapted for coupling the fiber optic cable to a light source and a detector. The light source transmits light along the fiber optic cable to the optical sensor 40, which alters the light to provide some indication of a given chemical species concentration. The optical sensor 40 returns light along the fiber optic cable to the surface interface 42 where the optical port communicates it to the detector. The detector responsively produces an electrical output signal indicative of the concentration of the given chemical species in the produced fluid 28. The optical port may be configured to communicate the down-going light signal along one or more optical fibers that are different from the optical fibers carrying the return light signal, or may be configured to use the same optical fibers for communicating both light signals.
The illustrative downhole optical sensor system 12 of
In some embodiments, the optical sensor 40 alters incoming light to provide an indication of a concentration of one or more selected chemical species (i.e., one or more selected analytes) known to be present in the produced water. As described above, the flow of fluid from the formation may include water from multiple sources. The computer 60 stores known concentration ranges of the one or more selected chemical species for each of the multiple possible sources of water (i.e., “analyte concentration characteristics”). The computer 60 receives the electrical output signal produced by the surface interface 42, uses the output signal to calculate a measured concentration of each of the selected analytes in the produced water, and uses the measured concentration of each of the selected analytes and the stored analyte concentration characteristics to determine a fraction of at least one source of water in the produced water. The computer 60 also uses a measured quantity of the produced fluid and the determined fraction of the at least one source of water to calculate an amount of water from the at least one source in the produced water.
For example, the produced water present in the fluid 28 may include a mixture of formation water and fracturing fluid. The optical sensor 40 may be configured to alter incoming light to provide an indication of a concentration of a selected analyte known to be present to a greater degree in the fracturing fluid, and to a lesser degree in the formation water. The computer 60 may store the analyte concentration characteristics for the fracturing fluid (i.e., the known concentration of the selected analyte in the fracturing fluid), and the analyte concentration characteristics for the formation water (i.e., the known concentration of the selected analyte in the formation water). The computer 60 may be adapted to receive the electrical output signal produced by the surface interface 42, to use the output signal to calculate a measured concentration of the selected analyte in the produced water, and to use the measured concentration of the selected analyte and the stored analyte concentration characteristics to determine a fraction of the fracturing fluid in the produced water. The computer 60 may also adapted to use a measured quantity of the produced fluid and the determined fraction of the fracturing fluid in the produced water to calculate an amount of the fracturing fluid produced.
In some embodiments, the information storage media 68 stores a software program for execution by computer 60. The instructions of the software program may cause the computer 60 to collect information regarding downhole conditions including selected analyte concentration(s) derived from the electrical signal from surface interface 42 and, based at least in part thereon, to determine an amount of produced water originating from at least one source. In addition to deriving the fraction of produced water from a given source, the computer may acquire a flow volume or a flow rate measurement that, when combined with the derived fraction, provides the flow volume or flow rate of produced water from the given source. To that end, the computer may be coupled to a downhole or surface fluid flow sensor to monitor, as a function of time, the flow rate and/or cumulative flow volume of produced fluids from the well. In some systems, fluid phase separators may be employed to separate gas, oil, and water components of the produced fluid, with separate flow sensor measurements being made for each phase.
As part of deriving the fraction or amount of produced water from a given source, the computer 60 may, for example, interpolate within the stored analyte concentration characteristics for multiple potential sources. The instructions of the software program may also cause the computer 60 to communicate to a user the amount (e.g., the relative fraction, the flow rate, or the accumulated flow volume) of produced water originating from at least one source. Note that the amount of produced water originating from the at least one source can be communicated via a graphical output device, via email or SMS text, via an audible or visual alarm indicator, or indeed by any suitable output technique.
In some embodiments, the amount of produced water originating from at least one source is determined as a difference or ratio between water amounts from different sources. The computer 60 may determine and display the amount of produced water originating from each of multiple sources as a function of time. The computer 60 may also determine and display the amount of produced water originating from each of multiple sources as a function of position in the borehole.
The software program executed by the computer 60 may, for example, embody a model for determining a fraction or amount of at least one source of water in produced water. Several suitable models are known in the oil and gas production industry. See, for example, “Returns Matching Reveals New Tools for Fracture/Reservoir Evaluation” by R. D. Gdanski et. al., Society of Petroleum Engineers (SPE) Paper No. 133806, Tight Gas Completions Conference, 2-3 Nov. 2010, San Antonio, Tex., USA, included herein by reference in its entirety. The model employed by the software program may, for example, use the measurements of the concentrations of one or more selected analytes in the produced fluid 28, along with measurements of temperatures and/or pressures of the produced fluid 28 along its flow path, to predict a fraction or amount of at least one source of water in the produced water.
In some embodiments, the software program executed by the computer 60 embodies the following equation model (from the above cited SPE Paper No. 133806) for determining a fraction of fracturing fluid (Ffrac) in a produced fluid consisting substantially of a mixture of formation water and fracturing fluid:
where Cmeas is the measured concentration of a selected analyte in the produced water, Cform is the concentration of the selected analyte in the formation water (i.e., the analyte concentration characteristic for the formation water), and Cfrac is the concentration of the selected analyte in the fracturing fluid (i.e., the analyte concentration characteristic for the fracturing fluid). It is noted that the fraction of the fracturing fluid (Ffrac) in the produced water ranges from 0.0 when the measured concentration of the selected analyte in the produced water (Cmeas) is equal to the concentration of the selected analyte in the formation water (Cform), to 1.0 when the measured concentration of the selected analyte in the produced water (Cmeas) is equal to the concentration of the selected analyte in the fracturing fluid (Cfrac.) As the difference between the concentrations of the selected analyte in the fracturing fluid (Cfrac) and the formation water (Cform) is in the denominator, it is desirable that the difference between the concentrations of the selected analtyes in the fracturing fluid (Cfrac) and the formation water (Cform) be as large as possible. In an ideal situation, the concentration of the selected analtye in the fracturing fluid is relatively large, and the selected analyte is absent in the produced fluid (Cform=0).
Potentially suitable analytes include chemical species such as ions containing sodium, potassium, boron, calcium, magnesium, iron, barium, strontium, chloride, sulfur, and/or carbon. Examples of potentially suitable ionic analytes include containing sodium, potassium, boron, calcium, magnesium, iron, barium, strontium, chloride, sulfate, and bicarbonate. In some embodiments, multiple analyte concentrations are measured. The fraction of equation (1) may be calculated individually for each selected analyte, and the results combined with a weighted average to obtain an overall result.
It is possible to extend the above equation model to determine the fractions of produced water from each of multiple possible sources by solving a system of simultaneous equations where there is one equation for each possible source:
where the number of selected analytes is T, the number of potential water sources is S, CIJ is the concentration of the Jth selected analyte (T≧J≧1) in the water from the Ith source (S≧I≧1), FI is the fraction of the water from the Ith source in the produced water (1.0≧FI≧0.0), and MJ is the measured concentration of the Jth selected analytes in the produced water. This set of equations can be extended to include a fraction of produced fluid represented by non-water (e.g., hydrocarbon) sources by adding the appropriate terms for the analyte characteristics of such sources.
The software program executed by the computer 60 may alternatively embody a neural network or a support vector machine that has been programmed to estimate fractions FI when provided with measured analyte concentrations MJ. The term neural network has evolved to describe a new paradigm for computing based on the highly parallel architecture of neurons in animal brains. Neural networks are particularly useful for processing data from complex processes where an algorithm is not known, or has a relatively large number of variables. A neural network is an adaptive system that responds to inputs by producing outputs, and (at least in the training phase) changes its structure based on information flowing through the network. Neural networks learn input/output relationships through training. In supervised learning, a neural network user assembles a set of training data that contains examples of inputs together with the corresponding correct or desired outputs. During training, the training data is used to adjust weights and/or thresholds within the network so as to minimize an error between the outputs generated by the network and the correct or desired outputs of the training set. A properly trained neural network “models” the relationship or function between the inputs and the outputs, and can subsequently be used to generate outputs for inputs where the corresponding outputs are not known.
The optical fiber 80 is provided with a sensing region 88 that, at least in some embodiments, is an exposed portion of the cladding layer 84 that may be further enhanced with a reagent designed to complex with a given chemical species in solution. The reagent region 88 of the optical sensor 40 surrounds the inner core 82 (i.e., the waveguide) and is in direct contact with both the waveguide and the produced fluid 28 (see
Within the optical sensor 40, a portion of the light passing through the inner core 82 (i.e., the waveguide) of the optical sensor 40 expectedly interacts with the reagent region 88. When the reagent complexes with a chemical species in the produced fluid 28, the complexes may more strongly or more weakly absorb the particular wavelength of light traveling through the reagent region 88. As a result, the intensity of the light exiting the optical sensor 40 may be reduced dependent upon the concentration of the chemical species in the produced fluid 28. Again, the chemical species may be selected based on its known presence in water from at least one source contributing to the produced water.
In at least some embodiments of the downhole optical sensor system 12, the light source in the surface interface 42 provides pulses of light via the optical port to the optical fiber 80 of the fiber optic cable 44. The light has, or includes, one or more wavelengths that are absorbed in the reagent region 88 of the optical sensor 40 when the reagent complexes with a selected analyte in the produced fluid 28. The light may be or include, for example, near infrared light. When a light pulse reaches the optical sensor 40, the light passes through the optical sensor 40 and is altered (e.g., attenuated) within the reagent region 88 by an amount dependent on the concentration of the selected analyte in the produced fluid 28.
The light traveling through the optical sensor 40 may be routed back to the surface along a different optical fiber in cable 44. In the illustrated embodiment, however, the light traveling through the optical sensor 40 reaches an end of the inner core 82, which is polished or mirrored to reflect a substantial portion of the light incident on it. The reflected light travels back through the optical sensor 40 on its way to the surface interface 42. During the return trip through the optical sensor, the light pulse is further altered (e.g., attenuated) within the reagent region 88 dependent upon the concentration of the selected chemical species in the produced fluid 28. The reflected pulse of light then travels back through the optical fiber 80 of the fiber optic cable 44 to the surface interface 42. A light detector in the surface interface 42 receives the reflected pulse of light and produces the electrical output signal indicative of the concentration of the selected chemical species in the produced fluid 28. For example, the detected intensity of the received light pulse at a given frequency may be proportional to the concentration of the given species. Alternatively, the detected intensity may be a nonlinear function of the transmitted light intensity and the concentration of the given species, but the surface interface or the computer is provided with sufficient information to derive the desired concentration measurement.
It is noted that multiple optical sensors can be co-located to sense multiple analytes to better characterize the produced fluid 28. Optical sensors can also be deployed in multiple zones to sense fluids from different formations.
In the embodiment of
Other alternative embodiments employ composite tubing with one or more optical fibers embedded in the wall of the tubing. The composite tubing can be employed as the casing and/or the production string. In either case, a coupling or terminator can be provided at the end of the composite tubing to couple an optical sensor 40 to the embedded optical fiber. In still other embodiments, the light source and/or light detector may be positioned downhole and coupled to the surface interface 42 via electrical conductors.
The well 10 illustrated in FIGS. 1 and 3-4 offers two potential flow paths for fluid to move between the surface and the bottom of the well. The first, and most commonly employed, is the interior of the production tubing. The second is the annular space between the production tubing and the casing. Usually the outermost annular space (outside the casing) is sealed by cement for a variety of reasons typically including the prevention of any fluid flow in this space. Usually, the point at which it is most desirable to measure concentrations of chemical species will be the point at which produced fluid enters the borehole, i.e., the completion zone, or points of potential constriction, e.g., where the fluid enters the flow path and any branches, chokes, or valves along the flow path. In some cases, one optical sensor 40 will be sufficient, and it can be located at the end of the fiber optic cable 44 in one of the deployments described previously.
However, other well configurations are known that have a substantial number of flow paths, particularly wells designed to produce from multiple completion zones. It may be desirable to provide multiple optical sensors 40 so as to be able to individually monitor each fluid flow. Moreover, it may be desirable to provide multiple optical sensors along a given fluid flow path, as such a well configuration may create atypical pressure and temperature changes along the flow path and, in some cases, mixing with other fluid flows. While it is possible to provide such sensors by providing a separate fiber optic cable for each optical sensor, it will be in many cases more efficient to provide a single fiber optic cable with multiple sensors.
In the embodiment of
Where the fiber optic cable 44 includes multiple optical fibers or multi-stranded optical fibers, the optical sensors 120A-120E can be directly coupled to different ones of the optical fibers or strands. The optical splitters would not be needed in this variation. The detector 124 can be coupled to measure the total light returned along the multiple fibers or strands, as the travel time difference to the various sensors will convert the transmitted light pulse into a series of reflected light pulses, with each pulse representing a corresponding optical sensor measurement.
In the embodiment of
The light source 122 may produce light having components in each of the wavelength ranges corresponding to the optical sensors 120. As the light propagates along the fiber optic cable and through the optical sensors 120, each of the optical sensors alter the light components within their associated wavelength range. In the illustrated embodiment, the light reflects from the end of the cable and propagates back to the surface, passing a second time through each of the sensors which further alter (e.g., attenuate) the light component in their associated wavelength range. When the reflected light reaches the surface interface, the optical circulator 126 directs the reflected light to the light detector 124, which analyzes each of the wavelength ranges associated with the various sensors 120 to determine a measurement for each sensor.
The embodiment shown in
In many cases, a temperature and pressure profile of the well may be predictable enough that a distributed temperature/pressure sensing system is deemed unnecessary, and in such cases it may be omitted. Where such a system is deemed useful, the downhole optical sensor system 12 may further operate as a distributed temperature and/or pressure measurement system. Such systems are commercially available and may be modified to provide the chemical species sensing described above without sacrificing their ability to obtain distributed temperature and/or pressure measurements. Such systems may operate based on measurements of backscattered light from impurities along the length of the fiber. Such backscattered light has properties indicative of temperature and stress at the scattering location. The surface interface transmits light pulses and measures the properties of the backscattered light as a function of time. Combined with knowledge of the light's propagation velocity in the fiber, such measurements can be readily converted to position-dependent measurements of pressure and temperature. These measurements may be made on the optical fibers coupling the surface interface to the downhole optical sensors, or they can be made on separate optical fibers provided within cable 44. Where separate fibers are used, an additional light source and detector can be employed, or the existing source and detector may be switched periodically between the fibers.
The multi-measurement fiber optic cable may, for example, be deployed in a borehole along a fluid flow path (e.g., cable 44 in
Numerous modifications, equivalents, and alternatives will become apparent to those skilled in the art once the above disclosure is fully appreciated. It is intended that the following claims be interpreted (where applicable) to embrace all such modifications, equivalents, and alternatives.
