Patent Application
20210131273
The present invention is directed to a method for determining the characteristics of an isolated fracture in a well comprising multiple hydraulic fractures within a hydrocarbon containing formation. In particular, the present invention is directed to a method in which the near wellbore characteristics of an isolated fracture in a multiply hydraulically fractured well in a low permeability hydrocarbon-containing formation may be determined in a short pressure transient test.
Oil and gas may be recovered from hydrocarbon-containing formations using well known techniques. In certain formations a wellbore, often a deviated wellbore such as a horizontal wellbore, may be drilled into the formation and the formation may be stimulated by hydraulic fracturing methods to increase the productivity of the well. Hydraulic fracturing accelerates production from conventional formations and enables production from low permeability reservoirs such as shale formations which would not produce hydrocarbons without such stimulation.
Hydraulic fracturing involves fracturing rock in the formation adjacent the wellbore by injecting a pressurized “fracking fluid”, optionally including propping solids such as sand, into the wellbore and directing the fracking fluid to a fracture zone to fracture the rock. Multiple fractures may be created along the length of the wellbore by hydraulically fracturing the formation at a plurality of frac zones. The productivity improvement of hydraulic fracturing is achieved by creating fractures in the formation that provide a connection between the wellbore and the hydrocarbons in the formation, where the fractures have a large surface area with high fluid conductivity relative to the reservoir.
The effectiveness of hydraulic fracturing for increasing formation productivity is in part dependent on the selection of appropriate hydraulic fracturing and completion methods for the formation in which they are applied. A variety of hydraulic fracturing and completion methods may be selected and used to hydraulically fracture a formation. Hydraulic fracturing methods may be selected to optimize productivity based on the composition, volume, and type of fracturing fluids and types of proppants that may be included therein; the injection rate used to induce fracturing; and fracturing treatment schedules. Completion methods also may be selected to optimize productivity where commonly used completion methods include plug and perf, cemented sleeves, open hole sleeves, and limited entry designs. Hydraulic fracturing and completions may also be designed to provide a selected number of perforation clusters per stimulated stage and a selected spacing between frac stages.
Efforts have been made to determine the effectiveness of hydraulic fracturing and completion techniques in a formation. As noted above, the outcome of hydraulic fracturing stimulation on well productivity is in part dependent on the hydraulic fracturing and completion methods selected for a formation—parameters that may be controlled to increase productivity—and is also in part dependent on subsurface characteristics—parameters that cannot be controlled. Decoupling the impact on well productivity of the hydraulic fracturing and completion parameters that may be controlled from the impact of subsurface parameters that may not be controlled permits the identification and selection of an optimal fracturing and completion design for a particular hydrocarbon-containing rock formation.
Conventionally, the effectiveness of a hydraulic fracturing treatment in a low permeability formation has been determined by measuring the fluid output rate and fluid output volume of a well. More accurate assessment of the treatment can be obtained from a well test, such as buildup test. It has been recognized, however, that measuring the fluid output of, or conducting the well test for, the commingled fractures in an entire well provides little information about the relative effectiveness of a particular hydraulic fracturing treatment. For example, the well may be hydraulically fractured at many isolated fracture zones along the wellbore, however, total fluid production may be dominated by production from only a few of the fractures. In a multi-fractured well, the overall effectiveness of the hydraulic fracturing treatment is based upon the distribution of fracture conductivity and near wellbore connectivity of each fracture zone. In order to characterize this distribution each fracture must be individually assessed.
Methods and systems have been recently developed for analyzing individual fractures in a wellbore. U.S. Patent Publication No. 2017/0051605 discloses a method for evaluating individual fracture production zones in a hydraulically fractured well in a hydrocarbon-containing formation to provide a measure of the fluid output of individual fracture zones. In the method, an initial bottom hole pressure is measured at an individual fracture zone. The individual fracture zone in the wellbore is then hydraulically isolated by straddle packers and fluid flow is induced in the isolated zone by engaging a jet pump to pump fluids from the isolated zone. A flowing bottom hole pressure and production flow rate are measured in the isolated zone while fluid flow is being induced in the isolated zone. A productivity index is produced from the measured initial bottom hole pressure and the flowing bottom hole pressure from which it may be determined whether the fracture is a candidate for re-fracturing. While this method provides information about the production in the isolated frac zone, it does not provide information regarding the fracture itself, in particular, it does not provide information regarding the near-wellbore characteristics of the fracture or characteristics of the fracture as a whole.
U.S. Pat. No. 9,976,402 (the '402 patent) discloses a method for evaluating isolated fractures in a wellbore. Packing elements are set to hydraulically isolate a portion of the wellbore about the fracture. A coiled tubing string extending from the surface to the isolated portion of the wellbore provides hydraulic continuity to the isolated portion of the wellbore through a port within the isolated portion of the wellbore. The coiled tubing is filled with a fluid of known density. A pressure transient may be induced in the isolated zone by either removing an amount of the fluid from the coiled tubing string at the surface to draw fluid from the isolated portion of the wellbore into the coiled tubing string or pumping fluid at the surface into the coiled tubing string and thus into the isolated portion of the wellbore. The resulting transient pressure is measured and recorded until the pressure has stabilized. Analysis of the pressure transient may provide diagnostic information about the fracture, formation, and/or the reservoir of hydrocarbons in the formation for the period of time the pressure transient may be measured. However, the pressure transient is initially masked from measurement due to the wellbore storage effect of the volume of fluid in the coiled tubing. As a result, this method does not enable effective determination of the fracture characteristics in the near wellbore area, which may only be determined from the initial pressure transient response.
Near-wellbore characteristics, in part, determine whether the fracture is effective to deliver fluid flow from the fracture into the wellbore. Hydraulic fracturing may induce damage in the formation and in the portion of the fracture near the wellbore. Such damage may reduce the fluid conductivity of the near-wellbore portion of the fracture relative to the main body of the fracture such that the near-wellbore portion of the fracture may act as a choke point between the main body of the fracture and the wellbore restricting or preventing flow of fluid from the main body of the fracture into the wellbore. The flow restriction caused by near-wellbore formation or fracture damage may be measured as skin factor, a dimensionless pressure drop caused by flow restriction in the near-wellbore region.
There is a need, therefore, for a system and a method to effectively measure pressure transients induced in an isolated zone containing a fracture in a multi-fractured wellbore so that the near-wellbore characteristics of the fracture may be assessed. Preferably, the method could be executed in a relatively short period of time so that the method could be replicated to measure fracture characteristics of multiple fractures in the well to provide an assessment of the fracture efficacy in the overall well. Assessment of the overall characteristics of a fracture including its near-wellbore characteristics and the distribution of these properties over multiple fractures in a wellbore would enable an assessment and comparison of the effectiveness of the selected completion designs and hydraulic fracturing methods.
In one aspect, the present invention is directed to a method for quantitatively determining near-wellbore characteristics of a hydraulic fracture in a hydraulically fractured wellbore in a hydrocarbon-containing formation, comprising:
In another aspect, the present invention is directed to a system for quantitatively determining near-wellbore fracture characteristics of a hydraulic fracture in a hydraulically fractured wellbore of a well in a hydrocarbon-containing formation, comprising:
The present invention provides a system and a method for determining the near-wellbore fracture characteristics of a fracture in a hydraulically fractured wellbore. In particular, the present invention provides a system and a method for effectively inducing and measuring a pressure transient in an isolated zone of a wellbore containing a fracture thereby enabling assessment of near-wellbore fracture characteristics such as conductivity and skin factor. The system and method of the present invention limit the volume of fluid present in the isolated zone and, optionally, a portion of a string hydraulically coupled to the isolated zone, when a pressure transient is induced in the isolated zone, thereby limiting the masking effects of wellbore storage upon the measured pressure transient. As a result, the near-wellbore characteristics of the fracture including conductivity and skin factor may be accurately assessed. Accurate assessment of the near-wellbore characteristics of individual fractures may be utilized in a determination of the effectiveness of hydraulic fracturing and completion methods in creating productive fractures in a hydrocarbon-containing formation. Accurate assessment of the effectiveness of the hydraulic fracturing and completion methods may be utilized to select optimum hydraulic fracturing and completion methods for use in further wells in the formation. Accurate assessment of the near-wellbore formation and fracture characteristics such as conductivity and skin factor may also be utilized to determine whether to re-stimulate fracture zones.
Further, the present invention provides a system and method for rapidly testing the near-wellbore characteristics of individual fractures in multiple isolated fracture zones to enable the characterization of the distribution of fracture properties between fracture zones and along the wellbore. Rapid testing may be conducted due to the limited volume of fluid present in the isolated zone when a pressure transient is induced in the zone and resulting limited wellbore storage. As a result, the effects on productivity of hydraulic fracturing and completion method parameters may be separated from subsurface characteristics productivity effects, where the hydraulic fracturing and completion method parameters may be utilized to determine the actual effectiveness of the created hydraulic fractures and completions so that the hydraulic fracturing and completions can be optimized and improved.
In one aspect, the present invention is a system for determining the fracture characteristics of an isolated portion of a hydraulically fractured well in a hydrocarbon-containing formation. As shown in
The well 17 extends through a hydrocarbon-containing formation 21. The well 17 may be a deviated well, and preferably is a horizontal deviated well wherein the wellbore 15 of the well is comprised of a vertical section extending from the surface 13 to the hydrocarbon-containing portion of the formation and a substantially horizontal section extending through the hydrocarbon-containing portion of the formation. The wellbore 15 of the well 17 may be any conventional type of wellbore, for example, the wellbore may be an open wellbore, or the wellbore may be cased, for example, by a cemented casing 23. The wellbore has been completed by hydraulically fracturing the wellbore with a hydraulic fluid so that fractures 25 are present along the length of the wellbore extending into the hydrocarbon-containing portion of the formation to enhance recovery of hydrocarbons therefrom.
An isolation mechanism is coupled to the string 11 structured and arranged to reversibly fluidly and substantially hermetically isolate a zone 26 of the wellbore 15 containing a fracture 25. As used herein, a zone 26 is substantially hermetically isolated when the isolation mechanism maintains from 95 vol. % to 105 vol. %, or from 97 vol. % to 103 vol. %, or from 99 vol. % to 101 vol. % of a fluid in the zone for the period that the isolation mechanism is engaged to form the isolated zone, wherein the fluid may contain a gas phase. The isolation mechanism is also structured and arranged to reversibly fluidly isolate the zone 26 from the ingress into the zone or egress from the zone of a liquid fluid. The isolation mechanism is comprised of a first adjustable packing element 27 mechanically coupled to a first portion of the string 29 and a second adjustable packing element 31 mechanically coupled to a second portion of the string 33. The first adjustable packing element 27 is spaced apart from the second packing element 31 by a distance sufficient to create an isolated zone 26 between the packing elements that may straddle a portion of the wellbore containing a fracture when the packing elements are adjusted to engage with the wall of the wellbore. The first and second adjustable packing elements 27 and 31 may be adjusted to reversibly engage with the wall of the wellbore to substantially hermetically and fluidly isolate a zone 26 within the wellbore so that packing elements may be engaged to form a pressure and fluid isolated zone within the wellbore and then may be disengaged so that the string 11 may be moved within the wellbore 15 to another position where the packing elements may be engaged with the wall of the wellbore to form another pressure and fluid isolated zone within the wellbore containing a fracture. In an embodiment, the first and second adjustable packing elements are conventional expandable straddle packers that may be inflated and deflated to engage and disengage the packers with the wall of the wellbore.
One or more apertures 35 extend through the wall of the string 11 to fluidly couple the interior of the string and the wellbore 15 within an isolated zone 26 when the packers are engaged with the wall of the wellbore, where the apertures 35 are structured and arranged to permit fluid communication between the interior of the string and the wellbore 15 within the zone 26. The one or more apertures are located in a portion of the string located between the first and second packing elements 27 and 31 so that the apertures 35 are located in the portion of the string in the isolated zone 26 when the first and second packing elements 27 and 31 are engaged with the wall of the wellbore. The apertures 35 are of sufficient size to permit fluid to flow freely between the portion of the wellbore within the isolated zone 26 and the interior of the string.
Referring now to
The valve 37 or 41 may be positioned to limit the wellbore storage effect on the measurement of a pressure transient induced in the isolated zone 26. The valve may be positioned to limit the wellbore storage coefficient of fluid prevented from flowing from or into the isolated zone and any portion of the interior of the string fluidly coupled to the isolated zone when the valve is engaged to at most 0.1 L/MPa, or at most 0.05 UM Pa.
Referring now to
When the valve 37 is located adjacent the first packing element in the interior of the string, the valve 37 is positioned to limit the volume of fluid in the portion of the wellbore in isolated zone 26 and the interior of the portion of the string 11 fluidly coupled to the isolated zone when the valve is engaged, thereby limiting the wellbore storage effect of the fluid. In one embodiment, the valve 37 is positioned in the interior of the string adjacent the first packing element 27 so that at most 800 L of fluid, or at most 500 L of fluid, or at most 250 L of fluid may be contained within portion of the wellbore in the isolated zone 26 and the portion of the interior of the string in fluid communication with the isolated zone when the valve 37 is engaged to fluidly isolate the isolated zone and the portion of the string in fluid communication with the isolated zone.
Referring now to
Referring back to
In an embodiment, the system 10 includes additional pressure sensors. A toe-side pressure sensor 47 may be coupled to the exterior of the string located outside the isolated zone 26 adjacent the second packing element 31 towards the toe 43 of the wellbore 15. A heel-side pressure sensor 49 may be coupled to the exterior of the string located outside the isolated zone 26 towards the heel 39 of the wellbore 15. The toe-side pressure sensor 47 and the heel-side pressure sensor 49 are structured and arranged to measure the pressure in the wellbore 15 outside of the isolated zone 26 on the toe side of the isolated zone 26 and on the heel side of the isolated zone, respectively. The toe-side pressure sensor 47 and the heel-side pressure sensor 49 may be in electronic communication with the surface to provide instantaneous pressure measurements to the surface 13. The toe-side pressure sensor 47 and the heel-side pressure sensor 49 may be electronically coupled to the surface wirelessly or with wires. Pressure measurements from the toe-side pressure sensor 47 and the heel-side pressure sensor 49 may be useful to determine whether a fracture located in the isolated zone 26 is in fluid communication with the wellbore through other fractures in the formation located outside the isolated zone.
In an embodiment, the system 10 includes an artificial lift mechanism. The artificial lift mechanism may be any conventional artificial lift mechanism used to reduce the bottom hole pressure of a well and thereby generate flow. The artificial lift mechanism may be a positive displacement downhole pump such as a beam pump or a progressive cavity pump. The artificial lift mechanism may be a jet pump. The artificial lift mechanism may be a downhole centrifugal pump such as an electrical submersible pump. The artificial lift mechanism may be a mechanism to induce gas lift in the string 11. The artificial lift mechanism may be hydraulically coupled to the wellbore portion of the isolated zone 26 and be structured and arranged to induce or promote fluid flow from the isolated zone.
In an embodiment, the system 10 includes a pump 51 located in the interior of the string 11 outside of the isolated zone 26 and towards the heel 39 of the wellbore relative to the first adjustable packing element 27 and the valve 37 (or 41). The pump may be located adjacent the valve 37 and the first adjustable packing element 27 towards the heel 39 of the wellbore 15 from the valve. The pump 51 is structured and arranged to pump fluid either from the isolated zone 26 or into the isolated zone when the valve 37 (or 41) is open in order to induce a pressure transient in the isolated zone. The pump may be a conventional electronic pump or a jet pump utilized to pump fluids in wellbores. The pump 51 may be electrically coupled wirelessly or by wires to the surface so the pump may be activated and deactivated from the surface 13. The pump 51 may be an artificial lift mechanism.
In an embodiment, the system 10 includes a multiphase flow meter 53 located in the interior of the string outside the isolated zone 26 and towards the heel 39 of the wellbore relative to the first adjustable packing element 37. The multiphase flow meter 53 is structured and arranged to measure the flow of a multi-phase fluid through the interior of the string. The multiphase flow meter 53 may be a three-phase flow meter for measuring the fluid flow of a fluid comprised of liquid hydrocarbons, gaseous hydrocarbons, and water. The multiphase flow meter 53 may be a conventional flow meter for measuring fluid flow in a pipe. The multiphase flow meter 53 may be located within the string between the pump 51 and the valve 37 or the first adjustable packing element 27. Alternatively, the flow meter 53 may be located within the string adjacent the pump 51 towards the heel 39 of the wellbore 15. The multiphase flow meter 53 may be utilized to measure the flow of fluid from or into the isolated zone 26 of the wellbore 15 when the pump 51 is activated or deactivated to provide information regarding the overall flow of fluid from the hydrocarbon formation through the fracture 25 in the isolated zone 26. The multiphase flow meter may also be utilized to provide information regarding the composition of a fluid flowing from the isolated zone. In an embodiment, two or more flow meters may be located in the interior of the string outside of the isolated zone, where one of the flow meters may be a multiphase flow meter for measuring the flow of two phases of the fluid, for example liquid hydrocarbons and water, and one of the flow meters may be a flow meter for measuring the flow of the gas phase of the fluid.
In an embodiment, the system 10 may comprise an actuating system for separately activating and deactivating the pump 51, engaging and disengaging the first and second adjustable packing elements 27 and 31 to create or remove the isolated zone 26, and/or opening and closing the valve 37 (or 41) to create a pressure transient. The actuating system may be an electronic system electrically coupled to the pump, the first and second adjustable packing elements, and the valve, either by wires or wirelessly. The actuating system may be located on the surface 13 and provides electric communication with some of the subsurface elements of the system 10. The actuating system may further comprise means for mechanically moving the string and moving the string 11 along the wellbore 15 to enable the assessment of multiple zones and fractures within the wellbore, for example a mechanically operated spool 19.
In another embodiment, the present invention is directed to a method for determining the fracture characteristics of a fracture 25 located in an isolated portion 26 of a hydraulically fractured well 17 in a hydrocarbon-containing formation 21. In particular, the method of the present invention enables an accurate determination of the near-wellbore characteristics of a fracture including conductivity and skin factor in an isolated portion of the hydraulically fractured well.
In the method of the invention, a zone is selected for isolation within the wellbore 15 of a well, preferably a deviated well, that has been hydraulically fractured. The selected zone contains a fracture 25 in the wellbore therein, where the fracture may extend into the hydrocarbon-containing formation 21. The zone is substantially hermetically and fluidly isolated within the wellbore to form an isolated zone 26 within the wellbore 15. The zone must be sufficiently hermetically isolated so that any leakage of fluid from or into the isolated zone over the period of the method has a negligible effect on measurement of pressure within the zone. As used herein, the zone 26 is substantially hermetically isolated when the isolated zone maintains from 95 vol. % to 105 vol. %, or from 97 vol. % to 103 vol. %, or from 99 vol. %, to 101 vol. % and preferably 100 vol. % of fluid contained in the zone for the period that pressure is measured within the zone, wherein the fluid may contain a gas phase. The zone may be isolated within the wellbore 15 with an isolation mechanism, preferably with first and second adjustable packing elements 27 and 31. The first and second adjustable packing elements may be conventional expandable straddle packers, where the zone is isolated by locating the straddle packers about the zone and expanding the straddle packers to abut the wall of the wellbore and substantially hermetically and fluidly seal the isolated zone 26 from the rest of the wellbore. The isolated zone 26 contains and hydraulically communicates with a wellbore fracture 25 therein, where the wellbore fracture extends from the wall of the wellbore into the hydrocarbon-containing portion of the formation 21. The isolated zone 26 may hydraulically communicate to a wellbore fracture therein through a perforated casing if the well is cemented and cased.
A string 11 having walls and an interior flow path through which fluid may flow, preferably comprised of coiled tubing or jointed pipe, may extend from the surface 13 into the isolated zone 26. The interior of the string 11 may be fluidly coupled to the portion of the wellbore 15 within the isolated zone 26 through apertures 35 in the wall of a portion of the string located in the isolated zone 26 so that fluid may be communicated between the interior of the string and the portion of the wellbore located in the isolated zone.
Fluid flow is induced either into or from the portion of the wellbore within the isolated zone 26 by injecting fluid into or withdrawing fluid from the portion of the wellbore within the isolated zone through the string 11. Fluid may be injected into or withdrawn from the portion of the wellbore within the isolated zone 26 through the apertures 35 in the string 11. In a preferred embodiment, the fluid flow is induced either from or into the portion of the wellbore within the isolated zone 26 by injecting fluid into the portion of the wellbore within the isolated zone 26 from the interior of the string or by drawing fluid from the portion of the wellbore within the isolated zone into the interior of the string through the one or more apertures 35 in the string. Fluid flow may be induced either from or into the portion of the wellbore within the isolated zone 26 by actuating a pump 51 located in the interior of the string 11 outside the isolated zone 26, preferably towards the heel 39 of the wellbore 15 relative to the isolated zone. The pump 51 may be an electrical pump or may be a jet pump. The rate at which the pump 51 either draws fluid from the portion of the wellbore within the isolated zone 26 into the string 11 or injects fluid into the portion of the wellbore within the isolated zone from the string should be sufficient to induce a pressure differential in the portion of the wellbore within the isolated zone relative to the pressure in the portion of the wellbore within the isolated zone prior to actuating the pump.
Fluid flow may be induced from or into the portion of the wellbore within the isolated zone 26 for a period of time sufficient to induce a pressure differential in the portion of the wellbore within the isolated zone relative to the pressure in the portion of the wellbore within the isolated zone prior to inducing fluid flow. Fluid flow is induced from or into the portion of the wellbore within the isolated zone 26 for a period of time sufficient to measure flowing pressure in the isolated zone and to measure the induced flow rate of fluid from or into the portion of the wellbore within the isolated zone. Fluid flow may be induced from or into the isolated zone for a period of time of at most 12 hours, or at most 8 hours, or at most 3 hours, and at least 0.5 hours.
The pressure within the portion of the wellbore located in the isolated zone 26 is measured while fluid flow is induced from or into the portion of the wellbore within the isolated zone. The flowing pressure may be measured by a pressure sensor 45 located in the portion of the wellbore in the isolated zone 26 or within a portion of the string 11 in fluid communication with the portion of the wellbore in the isolated zone. The flowing pressure may be measured for a period of time of at most 12 hours, or at most 8 hours, or at most 3 hours, and at least 0.5 hours. The flowing pressure may be measured for comparison with pressure measured in the portion of the wellbore in the isolated zone upon the pressure stabilizing after induction of a pressure transient, as described below, to analyze the potential of the wellbore and fracture within the isolated zone to produce fluids as pressure in the formation and wellbore is reduced as a function of producing hydrocarbons therefrom.
The flow rate of fluid through the string induced by drawing fluid from or injecting fluid into the portion of the wellbore within the isolated zone 26 into the interior of the string is also measured. The induced flow rate of fluid in the string may be measured by passing the fluid through one or more conventional multiphase flow meters. The flow rate of fluid may be measured for at most 12 hours, or at most 8 hours, or at most 3 hours, and at least 0.5 hours. In an embodiment, a multiphase flow meter may measure the flow of a fluid comprised of liquid hydrocarbons, water, and gaseous hydrocarbons. In an embodiment a first multiphase flow meter may measure the flow rate of liquid hydrocarbons and water in a fluid comprised of liquid hydrocarbons, water, and gas and a second multiphase flow meter may measure the flow rate of gas of the fluid. The one or more multiphase flow meters may also be used to analyze the ratio of oil, gas, and water flowing through the meter(s), providing data regarding the fluid composition produced from the formation through the fracture in the isolated zone. The flow rate of fluid through the string 11 induced by drawing fluid from the portion of the wellbore within the isolated zone 26 may also be measured to provide data regarding the volume of fluid that may be produced from the hydrocarbon-containing formation 21 through the fracture 25.
Subsequent to inducing fluid flow into or from the portion of the wellbore within the isolated zone 26 and measuring the flowing pressure and flow rate, fluid is rapidly prevented from flowing between the portion of the wellbore within the isolated zone 26 and the string 11 or between a portion of the string extending from adjacent the isolated zone away from the isolated zone and the portion of the wellbore in the isolated zone together with a portion of the string extending into the isolated zone that is fluidly coupled to the portion of the wellbore in the isolated zone. As used herein, rapidly preventing fluid flow means preventing the flow of fluid within 5 seconds, or 3 seconds, or 1 second. Fluid is prevented from flowing to enable measurement of a pressure transient in the portion of the wellbore in isolated zone that is based on fracture characteristics of a fracture 25 in the isolated zone.
In an embodiment of the invention, fluid is prevented from flowing between a portion of the string extending from adjacent the isolated zone 26 away from the isolated zone and the portion of the wellbore in the isolated zone together with a portion of the string extending into the isolated zone that is fluidly coupled to the portion of the wellbore in the isolated zone. The flow of fluid may be prevented by blocking fluid flow within the string 11 at a location adjacent to the isolated zone 26. As shown in
In another embodiment, as shown in
Referring now to
The wellbore storage coefficient of the fluid in fluid communication with the fracture 25 in the isolated zone 26 after fluid is prevented from flowing by actuating a valve as described above is limited as a result of the relatively small volume of fluid in fluid communication with the fracture in the isolated zone because the wellbore storage coefficient is the product of the fluid volume and fluid compressibility. The wellbore storage coefficient of the fluid in fluid communication with the fracture 25 in the isolated zone 26 after fluid is prevented from flowing may be at most 0.1 L/MPa, or at most 0.05 L/MPa, or at most 0.01 L/MPa. For comparison, a coiled tubing extending from the surface to an isolated zone in a formation having a length as described above may have a wellbore storage coefficient, assuming a stiff fluid such as water, of greater than 1.5 L/MPa, and a jointed pipe having the same length may have a wellbore storage coefficient, assuming a stiff fluid, of greater than 4 L/MPa.
Referring back to
The measured flow rate, the measured flowing pressure, and the measured non-flowing pressure are analyzed to determine the near-wellbore fracture characteristics of the fracture 25 in the wellbore within the isolated zone. A portion of the near-wellbore fracture characteristics of the fracture 25 may be determined by analyzing a log-log plot of pressure (P) in relation to time for a pressure derivative (t*dP/dt), as shown in
The measured flow rate, the measured flowing pressure, and the measured non-flowing pressure may also be analyzed to determine other features of the fracture 25 in the isolated zone and the formation into which the fracture extends. The fracture geometry—height, length, size, and shape—may be also determined from the pressure transient induced by preventing flow from the isolated zone. Formation properties of the formation through which the fracture extends—formation permeability and interaction between the formation and the fracture—may be also be determined from the pressure transient.
The pressure may be measured in the portion of the wellbore within the isolated zone 26 or within the portion of the string in fluid communication with the portion of the wellbore in the isolated zone for a period of time after preventing the flow of fluid until the pressure within the portion of the wellbore in isolated zone stabilizes. The pressure within the portion of the wellbore in the isolated zone or within the portion of the string in fluid communication with the portion of the wellbore in the isolated zone may be measured upon stabilization. The stabilized pressure may be analyzed in conjunction with the flowing pressure and flow rate measured as described above to analyze the potential of the fracture in the isolated zone to produce fluids as pressure in the formation and wellbore is reduced as a function of producing hydrocarbons therefrom. In particular, the fracture potential may be determined by subtracting the flowing pressure from the stabilized pressure and dividing the result by the flow rate.
In an embodiment of the method of the present invention, pressure within the wellbore 15 may be measured in the wellbore adjacent the isolated zone 26 on the toe-side 43, on the heel-side 39, or both subsequent to inducing a pressure transient in the portion of the wellbore in the isolated zone 26. Pressure in the wellbore 15 outside and adjacent to the isolated zone 26 may be measured to determine whether a fracture 25 within the isolated zone is in fluid communication with fractures in communication with the wellbore outside the isolated zone. Pressure in the wellbore outside of the isolated zone on the toe-side of the wellbore may be measured with a toe-side pressure sensor 47, and pressure in the wellbore outside the isolated zone on the heel-side of the wellbore may be measured with a heel-side pressure sensor 49.
In an embodiment of the method of the present invention, a zone containing a fracture may be selected for isolation within the wellbore 15 of a well, the string may be positioned so that the zone may be isolated by engaging the adjustable first and second packing elements with the wall of the wellbore, fluid flow may be induced either to or from the isolated zone, flowing pressure within the isolated zone and flow rate and composition of fluid flowing from the isolated zone may be measured, subsequent to inducing fluid flow into or from the isolated zone fluid may be prevented from flowing, and pressure may be measured in the shut-in isolated zone as described above. Subsequently, the adjustable first and second packing elements may be disengaged from the wall of the wellbore, one or more additional zones containing a fracture may be identified for evaluation, the string may be moved and positioned so that such additional zones may be isolated, and the process may be repeated to evaluate additional fractures in the wellbore. Additional zones containing a fracture for evaluation may be selected based upon production logging data for grouping the frac zones based on their inflow performance. Testing the additional fractures enables an assessment of the efficacy of a hydraulic fracturing and completion method stimulation over the length of the well.
Simulations were conducted to illustrate the effectiveness of the method of the present invention for the measurement of a pressure transient from which near-wellbore characteristics of a fracture may be determined relative to measurement of pressure transients utilizing a fluid contained in a coiled tubing or tubing extending from the surface to an isolated zone containing a fracture within a wellbore.
In each simulation, a pressure transient was induced in a portion of a wellbore containing a fracture that was located within an isolated zone. The pressure was determined in the isolated zone after the induction of a pressure transient in the isolated zone, wherein the masking effect of the wellbore storage of the fluid was included in the pressure determination. The volume of fluid for determining the masking effect of the wellbore storage was assumed as follows for the simulation: coiled tubing with a valve in accordance with the present invention: 48 L (0.3 bbls-petroleum); coiled tubing extending from the surface to the isolated zone in the wellbore, assuming the distance from the surface to the isolated zone is 1830 m (6000 ft): 3180 L (20 bbls-petroleum); and tubing extending from the surface to the isolated zone in the wellbore, assuming the distance from the surface to the isolated zone is 1830 m (6000 ft): 12718 L. Assuming that the fluid utilized is a slightly compressible fluid, the wellbore storage coefficients were calculated, where the calculated wellbore storage coefficient for the coiled tubing with a valve in accordance with the present invention was determined as 0.0162 L/MPa (7E-7 bbl/psi); the wellbore storage coefficient for the coiled tubing extending from the surface to the isolated zone was calculated to be 1.73 L/MPa (7.5E-5 bbl/psi); and the wellbore storage coefficient for the tubing extending from the surface to the isolated zone was calculated to be 4.61 L/MPa (2E-4 bbl/psi). Two simulations were run utilizing the calculated wellbore storage coefficients for determining pressure relative to time after shut-in of the isolated wellbore zone, where one simulation was run for a period of twelve hours after shut-in and the other simulation was run for a period of three hours after shut-in. A derivative of pressure v. time was calculated from the simulated pressure measurements for each simulation, and log-log plots (pressure v. time) of the calculated derivative of pressure v. time were created.
The present invention is well adapted to attain the ends and advantages mentioned as well as those that are inherent therein. The particular embodiments disclosed above are illustrative only, as the present invention may be modified and practiced in different but equivalent manners apparent to those skilled in the art having the benefit of the teachings herein. Furthermore, no limitations are intended to the details of construction or design herein shown, other than as described in the claims below. It is therefore evident that the particular illustrative embodiments disclosed above may be altered, combined, or modified and all such variations are considered within the scope of the present invention. The invention illustratively disclosed herein suitably may be practiced in the absence of any element that is not specifically disclosed herein and/or any optional element disclosed herein. While compositions and methods are described in terms of “comprising,” “containing,” or “including” various components or steps, the compositions and methods can also “consist essentially of” or “consist of” the various components and steps. All numbers and ranges disclosed above may vary by some amount. Whenever a numerical range with a lower limit and an upper limit is disclosed, any number and any included range falling within the range is specifically disclosed. In particular, every range of values (of the form, “from about a to about b,” or, equivalently, “from approximately a to b,” or, equivalently, “from approximately a-b”) disclosed herein is to be understood to set forth every number and range encompassed within the broader range of values. Also, the terms in the claims have their plain, ordinary meaning unless otherwise explicitly and clearly defined by the patentee. Moreover, the indefinite articles “a” or “an,” as used in the claims, are defined herein to mean one or more than one of the element that it introduces. If there is any conflict in the usages of a word or term in this specification and one or more patent or other documents that may be incorporated herein by reference, the definitions that are consistent with this specification should be adopted.
