Single point and fiber optic temperature measurement for correction of a gas column weight in a well

Fluid column weight correction using discrete point and fiber optic temperature measurement. A method for determining pressure at a distal end of a fluid column in a well includes the steps of: dividing the fluid column into multiple segments; determining a temperature of each segment; and determining a pressure and density for each segment. Another method includes the steps of: determining the temperature of each segment by measuring a temperature in the well near a proximal end of the fluid column, and using the measured temperature in conjunction with a thermal wellbore model to generate a temperature profile of the fluid column. Another method includes the steps of: causing a pressure change in the fluid column; recording multiple pressure measurements during the pressure change; and generating a temperature profile of the fluid column for each of the pressure measurements.

BACKGROUND

The present invention relates generally to methods and equipment utilized in conjunction with a subterranean well and, in an embodiment described herein, more particularly provides a fluid column weight correction using discrete point and fiber optic temperature measurement.

It is known to use a fluid column extending to the surface for measuring pressure in a well. An example of such a pressure measurement system is described in U.S. Pat. No. 5,163,321, the entire disclosure of which is incorporated herein by this reference.

Typically, a tube is inserted into the well from the surface to the depth at which pressure is to be monitored. The tube is then pressurized with a gas (such as helium or hydrogen) or other fluid. The tube is purged, so that it contains only the pressurized gas or other fluid, and the pressure at a proximal end of the tube is measured as an indication of pressure in the well at a distal end of the tube.

Of course, the weight of the fluid in the tube affects the pressure measurement, and so various attempts have been made in the past to correct the pressure measurement to account for the fluid weight. One method is to estimate an average temperature of the fluid, and then use this average temperature to estimate a density of the fluid, and thereby calculate a total weight of the fluid at the distal end of the tube. Another method is to use a distributed temperature sensing system to obtain a more accurate measurement of temperature along the tube, and then use this temperature distribution to estimate the density of the fluid and, thus, its weight.

It will be appreciated by those skilled in the art that these prior methods provide only rough estimates of the effect of the fluid weight on the pressure measurement. In particular, the fluid weight is not accurately determined, since it is based on inaccurate calculations of the fluid density. Therefore, it may be seen that improvements are needed in the art of correcting pressure measurements for fluid column weight.

SUMMARY

In carrying out the principles of the present invention, a method is provided which solves at least one problem in the art. One example is described below in which fluid column pressure measurements are corrected, in part by determining a pressure and temperature in each segment of the fluid column. Another example is described below in which fluid column pressure measurements are corrected, in part by determining a density in each segment of the fluid column.

A method is described for determining pressure at a distal end of a fluid column in a well. The method includes the steps of: dividing the fluid column into multiple segments; determining a temperature of each fluid column segment; and for each successive fluid column segment extending toward the distal end of the fluid column, determining a pressure in the fluid column segment and determining a density of the fluid column segment.

In an aspect of the invention, a method is provided which includes the steps of: dividing the fluid column into multiple segments; determining a temperature of each fluid column segment by measuring a temperature in the well near a proximal end of the fluid column, and using the measured temperature in conjunction with a thermal wellbore model to thereby generate a temperature profile of the fluid column. For each successive fluid column segment extending toward the distal end of the fluid column, a pressure in the fluid column segment and a density of the fluid column segment are determined.

In another aspect of the invention, a well testing method is provided which includes the steps of: shutting in the well, thereby causing a pressure increase at the distal end of the fluid column; monitoring the pressure increase over a time period at a proximal end of the fluid column, thereby recording multiple pressure measurements; and generating a temperature profile of the fluid column for each of the pressure measurements, each of the temperature profiles corresponding to a respective one of the pressure measurements at a time the pressure measurement is recorded. For each of the pressure measurements, a corrected pressure at the distal end of the fluid column is determined using the respective temperature profile.

These and other features, advantages, benefits and objects of the present invention will become apparent to one of ordinary skill in the art upon careful consideration of the detailed description of representative embodiments of the invention hereinbelow and the accompanying drawings, in which similar elements are indicated in the various figures using the same reference numbers.

DETAILED DESCRIPTION

It is to be understood that the various embodiments of the present invention described herein may be utilized in various orientations, such as inclined, inverted, horizontal, vertical, etc., and in various configurations, without departing from the principles of the present invention. The embodiments are described merely as examples of useful applications of the principles of the invention, which is not limited to any specific details of these embodiments.

In the following description of the representative embodiments of the invention, directional terms, such as “above”, “below”, “upper”, “lower”, etc., are used for convenience in referring to the accompanying drawings. In general, “above”, “upper”, “upward” and similar terms refer to a direction toward the earth's surface along a wellbore, and “below”, “lower”, “downward” and similar terms refer to a direction away from the earth's surface along the wellbore.

Representatively illustrated inFIG. 1is a well system10which embodies principles of the present invention. A tubular string12(such as a production or injection tubing string) is installed in a wellbore14of the well. The tubular string12is used to convey fluid between the surface and a formation or zone16intersected by the wellbore14.

A tube or conduit18is positioned adjacent the tubular string12. Preferably, the conduit18is installed along with the tubular string12, but other installation methods could be used, if desired. In addition, an optical conductor20(such as a fiber optic line) is preferably positioned adjacent the conduit18for measuring a temperature along the wellbore14.

Alternatively, or in addition, one or more temperature sensors22,24may be positioned in the well. Preferably, at least one of the sensors22is positioned near the surface, but below a tubing hanger26. The near surface location of the sensor22provides for convenient installation, retrieval, maintenance and communication with the sensor. The positioning of the sensor22prevents surface conditions (such as ambient temperature, etc.) from significantly affecting the temperature measurements.

If the other sensor24is used, it is preferably positioned at a location substantially spaced apart from the sensor22. This spacing provides increased accuracy in determining a temperature profile in the well, as described more fully below. The sensor24may communicate with the surface via lines (such as electrical or optical conductors) or via telemetry.

An enlarged chamber28is preferably connected at a distal end of the conduit18. A lower end of the chamber28is in communication with the wellbore14external to the tubular string12. The chamber28provides a substantial internal volume for accommodating pressure fluctuations in the wellbore14.

The conduit18and chamber28are purged by flowing a fluid having known properties through the conduit and into the chamber. The fluid may actually be a combination or mixture of fluids, and preferably has a density which is less than that of the fluid in the wellbore14, so that pressure must be applied to the conduit18at the surface (e.g., using a pump, pressurized container or other pressure source30) to prevent the well fluid from flowing upwardly through the conduit.

Pressure in the conduit18at the surface is monitored (for example, using a pressure gauge or other type of sensor32) to provide an indication of the pressure in the wellbore14at the lower end of the chamber28. It will be readily appreciated by those skilled in the art that a fluid column34extends from its proximal end at the surface to the chamber28at its distal end, and that the weight of the fluid column affects the pressure measurements made at the proximal end of the fluid column.

It should be clearly understood that, although in the well system10as described herein the proximal end of the fluid column34is located near a wellhead36at the earth's surface38, the principles of the invention are not limited to this configuration. For example, the proximal end of the fluid column34could be located at a wellhead on a sea floor or mudline, on a floating or permanent platform, etc. Thus, the invention is not limited to the particular details of the well system10described herein, instead the well system is merely used as an example of an application of the principles of the invention.

Referring additionally now toFIG. 2, an enlarged scale illustration of a portion of the fluid column34is depicted. The fluid column34is divided into a series of successive segments40,42,44. Although only three segments40,42,44are depicted inFIG. 2, preferably the entire fluid column34, from its proximal end to its distal end, is divided up into similar segments, with each of the segments having an equal length l.

If the optical conductor20is used for temperature measurement in the wellbore14, then preferably temperature measurements are made for each of the segments40,42,44. For example, temperature measurements may be made at locations46,48,50along the optical conductor20. These temperature measurements could be made by detecting Raman scattering in the optical conductor20, by use of Bragg gratings along the optical conductor, or by any other method.

InFIG. 2, the optical conductor20is depicted as being closely adjacent the fluid column34for accurate temperature measurements along the fluid column. Many different configurations are possible, and a few of these are representatively illustrated inFIGS. 3-5.

InFIG. 3, the optical conductor20is positioned inside the conduit18, and is surrounded by or immersed in the fluid column34. In one alternative, the optical conductor20could be incorporated into a cable or other line which is installed within the conduit18, either prior to or after the conduit is installed in the wellbore14.

InFIG. 4, the optical conductor20is installed in a separate tube or conduit52within the conduit18. In this manner, the optical conductor20is isolated from the fluid column34.

InFIG. 5, the optical conductor20is positioned within the conduit52, but in this configuration the conduit52is external to the conduit18. Thus, it will be readily appreciated that any arrangement of the optical conductor20relative to the fluid column34may be utilized, without departing from the principles of the invention.

Referring additionally now toFIG. 6, a method60for determining the pressure in the wellbore14at the distal end of the fluid column34is representatively illustrated in flowchart form. The method60may be used with the well system10for correcting the pressure measurements made at the sensor32, based on a weight of the fluid column34. Of course, the method60may be used with other well systems in keeping with the principles of the invention.

An initial step62in the method60is to determine the temperature of each of the segments of the fluid column34, from its proximal end to its distal end. Various techniques may be used in this step62. As depicted inFIG. 2, the temperature of each segment may be directly measured using the optical conductor20. Other techniques for determining the temperature of each of the segments are described below.

In step64, a pressure in each of the segments of the fluid column34is determined. Using the sensor32, pressure in the uppermost segment of the fluid column34may be directly measured. For each successive segment, however, the accumulated weight of the vertically higher segments cause an increased pressure in the segment. In other words, the pressure in each segment is equal to the súm of the pressure applied to the conduit18(e.g., from the pressure source30) and the pressure due to the weight of the vertically higher segments.

As depicted inFIG. 2, the pressure in the segment40is equal to the pressure applied to the conduit18at the surface, plus the pressure due to the weight of all segments of the fluid column34above the segment40. Similarly, the pressure in the segment42is equal to the pressure applied to the conduit18at the surface, plus the pressure due to the weight of all segments of the fluid column34above the segment42, including the weight of the segment40. Again, in a similar manner, the pressure in the segment44is equal to the pressure applied to the conduit18at the surface, plus the pressure due to the weight of all segments of the fluid column34above the segment44, including the weights of the segments40,42.

The pressure in a particular segment due to the accumulated weight of the vertically higher segments is equal to the weight divided by the internal cross-sectional area of the conduit18. If, for example, the accumulated weight of the vertically higher segments were 2 pounds, and the cross-sectional area of the conduit18were 0.1 square inch, then the pressure due to the weight of the vertically higher segments would be 20 psi. If the pressure applied to the conduit18at the surface were, for example, 2,000 psi, then the total pressure in the segment would be 2,020 psi.

In order to determine the weight of each of the segments of the fluid column34, the density of each segment is determined in step66. As discussed above, the fluid in the fluid column34has known properties, including a known relationship between the fluid temperature, pressure and density.

For a gas, this relationship may be represented, for example, by the Van Der Waals equation of state:
(P+a(n/V)2)(V−nb)=nRT(1)

in which P is pressure, V is volume, T is temperature, R is the universal gas constant (8.314 J/mole/K), n is number of gram moles, and a and b are specific constants for each gas. For helium, a=0.00341 J m3/mole2and b=2.34×10−5m3/mole. For hydrogen, a=0.0247 J m3/mole2and b=2.65×10−5m3/mole. For nitrogen, a=0.1361 J m3/mole2and b=3.85×10−5m3/mole.

Where the density of the gas is relatively low (e.g., helium at low pressure), then the ideal gas law (PV=nRT) may provide an acceptably accurate alternative to the Van Der Waals equation of state. Of course, if the fluid column34contains liquid, then an appropriate relationship between pressure, temperature and density for the liquid would be used instead.

The pressure P is provided in step64and the temperature T is provided in step62. The density is n/V, expressed in terms of mass. When multiplied by the gravitational constant and the volume of the segment, the weight of the segment is given.

Thus, the weight of each segment of the fluid column34may be conveniently and accurately determined using the method60. Importantly, in the method60both the temperature and pressure of each segment are used in calculating the density of the segment. This method is far more accurate than relying on an estimation of the overall average temperature and average density of the fluid column34to determine the weight of the entire fluid column.

Note that in step68of the method60, a determination is made as to whether the last segment has been reached. If so, then the method is terminated. If not, then steps64-68are repeated for the next segment in succession.

In summary, a temperature of each segment of the fluid column34is determined in step62and then, for each segment in succession (starting at the proximal end of the fluid column34and proceeding to the distal end) the pressure in that segment and the density of that segment are determined. When the last segment is reached (at the distal end of the fluid column34), the pressure at the distal end can be conveniently calculated as the pressure applied to the fluid column at the surface, plus the pressure due to the accumulated weight of all vertically higher segments.

Referring additionally now toFIG. 7, a technique70for determining the temperature of each segment of the fluid column34is representatively illustrated in flowchart form. The technique70may be used in step62of the method60in the event that a direct measurement of the temperature of each segment is not available.

In an initial step72of the technique70, a thermal wellbore model is generated. A thermal wellbore model is a mathematical representation of the thermal characteristics of a wellbore, and is based on physical properties of the wellbore, the surrounding environment, thermal properties of fluids and solids, dynamic characteristics (such as fluid flow rate), etc. For example, significant parameters in constructing a thermal wellbore model for the wellbore14may include the dimensions of the wellbore, the dimensions of the tubular string12, casing, cement, etc., wellbore inclination or deviation, the undisturbed geothermal gradient, the heat capacity and conductivity of the formation16, the location and number of perforations, the physical properties of fluids flowing between the wellbore and the formation, the flow rate, etc.

An acceptable thermal wellbore model which may be used in step72is Wellcat-Prod™ available from Halliburton Energy Services, Inc. of Houston, Tex.

In step74, a temperature measurement is made. The sensor22may be used for the temperature measurement. If the sensor24is used, then temperature measurements made by either or both of the sensors may be used in the step74.

In step76, a temperature profile for the fluid column34is determined. The temperature profile provides a correlation between depth and temperature in the wellbore14. In this manner, the temperature of each segment of the fluid column34may be determined.

The temperature profile is generated by the thermal wellbore model. In one alternative, the thermal wellbore model may generate a series of possible temperature profiles. In that case, the proper temperature profile to use in the method60is determined by selecting the temperature profile which corresponds to the temperature measurement in step74.

That is, if in step74a temperature T1is measured at depth D1, then the proper temperature profile will include the temperature T1at depth D1. The other possible temperature profiles generated by the thermal wellbore model will preferably not include the temperature T1at depth D1. If in step74multiple temperature measurements T1, T2are made at respective multiple depths D1, D2(for example, using the sensors22,24), then the proper temperature profile will include the temperature T1at depth D1, and will also include the temperature T2at depth D2.

Instead of using the measured temperature(s) to select from among multiple possible temperature profiles generated by the thermal wellbore model, an alternative is to input the measured temperature(s) and depth(s) to the thermal wellbore model (for example, as boundary conditions). In this manner, the thermal wellbore model can output the proper temperature profile, without a need for selecting from among multiple possible temperature profiles. In basic terms, the measured temperature(s) allows the thermal wellbore model to be “calibrated” for the particular circumstances and configuration of the well system10.

In practice it may be impractical or inconvenient to have the thermal wellbore model generate the temperature profile at the time the temperature is measured. Instead, using specific well information (such as depth of the chamber28, well deviation, fluid column properties, etc.) the thermal wellbore model may be used to generate multiple possible temperature profiles. A range of expected surface pressure readings can then be used in conjunction with the possible temperature profiles to calculate the pressure applied downhole due to the fluid column weight (i.e., by calculating the pressure and density in each of the fluid column segments as described above) for each combination of temperature profile and surface pressure reading.

At the jobsite, the measured temperature and surface pressure reading are then used to select the appropriate pressure applied downhole due to the fluid column weight. Thus, it will be appreciated that the steps of the technique70could be performed in any order, without departing from the principles of the invention. For example, the temperature profile could be generated by the thermal wellbore model prior to measuring the temperature in step74.

In some circumstances, a temperature measurement in the well may not be available. For example, a temperature sensor may not have been installed in the wellbore14, or a previously installed sensor may have malfunctioned, etc. In this case, other factors may be used to enable the thermal wellbore model to generate a proper temperature profile, or to appropriately modify a previously determined temperature profile.

Referring additionally now toFIG. 8, a technique80is representatively illustrated in flowchart form. This technique allows a thermal wellbore model to use a flow rate of fluid in the well to generate a proper temperature profile, or to modify a previously determined temperature profile.

Flow rate is used in the technique80, since it is known that flow rate is a significant factor in determining the temperature profile of a wellbore. For example, if flow is completely stopped, the wellbore temperature profile will gradually correspond to the geothermal gradient for the well location. If flow increases, then temperature in the well will change accordingly. Note that production and/or injection flow rates may be used in the technique80.

In step82, the thermal wellbore model is generated. This step is similar to the step72in the technique70.

In step84, the flow rate is determined. The flow rate could be measured directly, for example, one or both of the sensors22,24could include a flowmeter, or a flowmeter could be located at the surface. Alternatively, the flow rate could be derived from other measurements, for example, pressure could be measured using a gauge or other sensor88as an indication of flow rate. A pressure differential across a calibrated choke, orifice or venturi may also be used as an accurate indicator of flow rate.

In step86, the flow rate is used in conjunction with the thermal wellbore model to determine the proper temperature profile. The flow rate may be input as a boundary condition to the thermal wellbore model, so that the thermal wellbore model outputs the proper temperature profile. Alternatively, the thermal wellbore model may have been previously “calibrated” as described above, for example, using measured temperature(s) and depth(s) at a certain previous flow rate. In that case, the current flow rate determined in step84may be used to modify the thermal wellbore model, so that an updated temperature profile is generated for the current flow rate.

Similar to the temperature measurement described above for the technique70, it is not necessary for the flow rate to be determined prior to generating the temperature profile. Instead, using specific well information (such as depth of the chamber28, well deviation, fluid column properties, etc.) the thermal wellbore model may be used to generate multiple possible temperature profiles. A range of expected surface pressure readings can then be used in conjunction with the possible temperature profiles to calculate the pressure applied downhole due to the fluid column weight (i.e., by calculating the pressure and density in each of the fluid column segments as described above) for each combination of temperature profile and surface pressure reading.

At the jobsite, the measured flow rate and surface pressure reading are then used to select the appropriate pressure applied downhole due to the fluid column weight. Thus, it will be appreciated that the steps of the technique80could be performed in any order, without departing from the principles of the invention. For example, the temperature profile could be generated by the thermal wellbore model prior to measuring the flow rate in step84.

Each of the techniques70,80described above allows an appropriate temperature profile to be determined for use in correcting the surface pressure measurements for the weight of the fluid column34. The temperature profile is useful in step62of the method60for determining the temperature of each of the segments of the gas column34. However, it should be clearly understood that other techniques may be used for determining a wellbore temperature profile, without departing from the principles of the invention.

The enhanced accuracy in downhole pressure measurements provided by the principles of the invention can be of substantial benefit in various phases of well operations. For example, production and/or injection monitoring can benefit from the greater accuracy provided by the methods described herein.

Another well operation which can utilize the principles of the invention is well testing. In one type of well test, the well is shut in and a pressure buildup is monitored. The manner in which the pressure buildup occurs enables certain important characteristics of the formation or zone16to be determined. Improved accuracy in the pressure measurements will result in corresponding improved accuracy in the determinations of the formation characteristics.

Representatively illustrated inFIG. 9is a graph90depicting an example of a recorded pressure buildup during a well testing operation. A vertical axis on the graph90represents pressure recorded at the surface Ps, and a horizontal axis on the graph represents time t.

As discussed above, when a well is shut in (i.e., the flow is completely stopped, whether at the surface or downhole) its temperature profile gradually changes. Therefore, it will be appreciated that the temperature profile of the wellbore14will be different at different points92,94during the pressure buildup. Therefore, in order to increase the accuracy of the downhole pressure measurements using the method60, the appropriate temperature profile for each of the points92,94(and all other points along the pressure buildup) should be used when correcting the surface pressure measurements for the weight of the fluid column34.

Referring additionally now toFIG. 10, a graph100of multiple possible temperature profiles102,104,106,108,110is representatively illustrated. A vertical axis on the graph100represents depth D in the wellbore14(increasing from top to bottom on the graph), and a horizontal axis on the graph represents temperature T in the wellbore (increasing from left to right on the graph). The temperature profiles102,104,106,108,110may be generated, for example, by a thermal wellbore model of the type described above.

The temperature profile110corresponds to the geothermal gradient for the well location. The temperature profile102corresponds to the temperature distribution in the wellbore14at a certain flow rate prior to the well being shut in, for example, at point96on the graph90. It will be appreciated by those skilled in the art that, upon shut in, the temperature profile will gradually change from the profile102to each of the profiles104,106,108in succession, and then eventually to the geothermal gradient profile110.

A determination can be made as to which of the temperature profiles104,106,110corresponds to each of the points along the pressure buildup shown in the graph90. For example, it may be determined that the temperature profile104corresponds to the point92, and that the temperature profile108corresponds to the point94. In this manner, the appropriate temperature profile can be used to correct the surface pressure measurements Ps made during the well test for the weight of the gas column34using the method60.

Referring additionally now toFIG. 11, this technique120of correcting well test pressure measurements is representatively illustrated in flowchart form. The technique120is described as being used for a pressure buildup when a well is shut in, but it will be appreciated that similar techniques may used for pressure decreases during a drawdown test, and for other types of well tests and other well operations (such as production and/or injection monitoring, stimulation treatments, completion operations, etc.).

In step122, the well is shut in. This may be accomplished in various ways, such as by closing a choke or valve at the surface, installing a testing tool in the tubular string12via wireline, etc.

In step124, the pressure is measured at the surface. For example, the gauge or sensor32may be used to monitor and record the pressure buildup. The recorded pressure measurements may be similar to that shown in the graph90ofFIG. 9.

In step126, the appropriate temperature profiles for each of the pressure measurements are determined. As described above, a thermal wellbore model may be used to generate the temperature profiles.

In step128, the pressure measurements are corrected for the weight of the fluid column34using the method60as described above, with the appropriate temperature profile for each pressure measurement being used in the method to determine the temperature of each of the segments of the fluid column. In this manner, the corrected pressure measurements may be used for more accurately determining the characteristics of the formation or zone16.

Of course, a person skilled in the art would, upon a careful consideration of the above description of representative embodiments of the invention, readily appreciate that many modifications, additions, substitutions, deletions, and other changes may be made to these specific embodiments, and such changes are within the scope of the principles of the present invention. Accordingly, the foregoing detailed description is to be clearly understood as being given by way of illustration and example only, the spirit and scope of the present invention being limited solely by the appended claims and their equivalents.