Title:
System and Method to Convert Surface Pressure to Bottom Hole Pressure Using an Integrated Computation Element
Kind Code:
A1


Abstract:
A system and method for converting wellhead surface fluid pressures to bottom hole pressures through use of real-time fluid characteristic data determined using an Integrated Computational Element (“ICE”) computing device in conjunction with wellhead surface pressure measurements.



Inventors:
Irani, Cyrus (Houston, TX, US)
Kool, Hendrik (Conroe, TX, US)
Application Number:
14/758115
Publication Date:
12/10/2015
Filing Date:
02/19/2013
Assignee:
HALLIBURTON ENERGY SERVICES INC.
Primary Class:
International Classes:
E21B47/06; E21B34/02; E21B49/08
View Patent Images:



Other References:
Economides, "Shut-In and Flowing Bottom Hole Pressure Calculation for Geothermal Steam Wells," Shell Oil Co., 1983, ppg 139-151
Young, "Effect of Assumptions Used to Calculate Bottom-Hole Pressures in Gas Wells," SPE, 1967, ppg 7-10
Liu et al., "A unified formula fo rdetermination of wellhead pressure and bottom-hole pressure," Energy Procedia, 37 (2013) ppg 3291-3298
Cullender and Smith, "Practical Solution of Gas-Flow Equations for Wells and Pipelines with Large Temperature Gradients," SPE, Vol. 207, 1956, ppg 281-287
Cullender and Smith, "Practical Solution of Gas-Flow Equations for Wells and Pipelines with Large Temperature Gradients," SPE, Vol. 207, 1956, ppg 281-287
Young, "Effect of Assumptions Used to Calculate Bottom-Hole Pressures in Gas Wells," SPE, 1967, ppg 7-10
Liu et al., "A unified formula fo rdetermination of wellhead pressure and bottom-hole pressure," Energy Procedia, 37 (2013) ppg 3291-3298
Economides, "Shut-In and Flowing Bottom Hole Pressure Calculation for Geothermal Steam Wells," Shell Oil Co., 1983, ppg 139-151
Primary Examiner:
FITZGERALD, JOHN P
Attorney, Agent or Firm:
HAYNES AND BOONE, LLP (Dallas, TX, US)
Claims:
What is claimed is:

1. A method for converting wellbore surface fluid pressure to bottom hole pressure, the method comprising: providing fluid from a wellbore to a conduit in fluid communication with a pressure sensor and an Integrated Computational Element (“ICE”) computing device; determining a surface fluid pressure at the wellbore using the pressure sensor; determining a characteristic of the fluid using the ICE computing device; and determining a bottom hole pressure of the wellbore using the surface fluid pressure and characteristic of the fluid.

2. A method as defined in claim 1, wherein determining the characteristic of the fluid is performed in real-time.

3. A method as defined in claim 1, wherein the characteristic of the fluid comprises an amount of at least one of C1 hydrocarbon, C2 hydrocarbon, C3 hydrocarbon, C4 hydrocarbon, C5 hydrocarbons, C6 hydrocarbons, C7 hydrocarbons or water within the fluid.

4. A method as defined in claim 1, wherein at least one of the surface fluid pressure or bottom hole pressure are determined in real-time.

5. A method as defined in claim 1, wherein the conduit is coupled to a wellhead.

6. A method as defined in claim 1, wherein determining the characteristic of the fluid further comprises periodically communicating the fluid to the ICE computing device using a valve, thereby providing a plurality of characteristic readings of the fluid over a period of time.

7. A method as defined in claim 1, further comprising locating the pressure sensor and ICE computing device at a surface location.

8. A system for converting wellbore surface fluid pressure to bottom hole pressure, the system comprising: a pressure sensor in fluid communication with the wellbore to determine a surface fluid pressure of the wellbore; and an Integrated Computational Element (“ICE”) computing device that optically interacts with wellbore fluid to determine a characteristic of the wellbore fluid; wherein a bottom hole pressure of the wellbore is determined based upon the surface fluid pressure and the characteristic of the wellbore fluid.

9. A system as defined in claim 8, wherein the characteristic of the wellbore fluid is a real-time fluid characteristic.

10. A system as defined in claim 8, further comprising a signal processor communicably coupled to the pressure sensor and ICE computing device to determine the bottom hole pressure using the surface fluid pressure and the characteristic of the wellbore fluid.

11. A system as defined in claim 8, wherein the characteristic of the wellbore fluid comprises an amount of at least one of C1 hydrocarbon, C2 hydrocarbon, C3 hydrocarbon, C4 hydrocarbon, C5 hydrocarbons, C6 hydrocarbons, C7 hydrocarbons or water within the wellbore fluid.

12. A system as defined in claim 8, wherein at least one of the surface fluid pressure or bottom hole pressure are real-time data.

13. A system as defined in claim 8, wherein the wellbore fluid is communicated to the pressure sensor using a conduit coupled to a wellhead.

14. A system as defined in claim 8, wherein the ICE computing device is fluidly coupled to the wellbore using a conduit, the system further comprising a valve positioned along the conduit to periodically communicate the wellbore fluid to the ICE computing device over a period of time.

15. A system as defined in claim 8, wherein the pressure sensor and ICE computing device are positioned at a surface location.

16. A method for converting wellbore surface fluid pressure to bottom hole pressure, the method comprising converting a surface fluid pressure to a bottom hole pressure using at least one fluid characteristic of a wellbore fluid, the at least one fluid characteristic being determined in real-time.

17. A method as defined in claim 16, wherein the at least one fluid characteristic is determined using an Integrated Computational Element (“ICE”) computing device.

18. A method as defined in claim 16, wherein the at least one fluid characteristic comprises an amount of at least one of C1 hydrocarbon, C2 hydrocarbon, C3 hydrocarbon, C4 hydrocarbon, C5 hydrocarbons, C6 hydrocarbons, C7 hydrocarbons or water within the wellbore fluid.

19. A method as defined in claim 17, further comprising communicating the wellbore fluid from a wellhead to the ICE computing device using a conduit.

20. A method as defined in claim 17, further comprising periodically communicating the wellbore fluid to the ICE computing device, thereby providing a plurality of the at least one fluid characteristics over a period of time.

Description:

FIELD OF THE INVENTION

The present invention relates generally to bottom hole pressure analysis and, more specifically, to a system for converting wellhead surface fluid pressures to bottom hole pressures through use of an Integrated Computational Element (“ICE”) computing device.

BACKGROUND

Acquiring surface pressures for conversion to bottom hole pressures is a technology dating back to the mid-1980's. Conventionally, surface pressure measurements and compositional data of the wellbore fluid are necessary to perform such conversions. Unfortunately, however, current surface-to-bottom hole pressure conversion methodologies are dependent upon outdated, historical fluid compositional data. Consequently, the computed bottom hole pressures are sometimes incorrect, which can lead to inaccurate interpretation of the bottom hole pressure and erroneous decision making based upon these outdated measurements.

Accordingly, there is a need in the art for a surface-to-bottom hole pressure conversion system that utilizes actual, real-time wellbore fluid compositional data.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a schematic illustration of a well system having a pressure sensing module and ICE computing device according to certain exemplary embodiments of the present invention;

FIG. 2 is a block diagrammatical illustration of an ICE computing device used to provide downhole fluid characteristic that, in turn, is utilized to convert surface fluid pressures to bottom hole pressures according to certain exemplary embodiments of the present invention; and

FIG. 3 is a flow chart of a method for converting surface fluid pressure to bottom hole pressure according to certain exemplary methodologies of the present invention.

DESCRIPTION OF ILLUSTRATIVE EMBODIMENTS

Illustrative embodiments and related methodologies of the present invention are described below as they might be employed in a system to convert wellbore surface fluid pressures to bottom hole pressures. In the interest of clarity, not all features of an actual implementation or methodology are described in this specification. Also, the “exemplary” embodiments described herein refer to examples of the present invention. It will of course be appreciated that in the development of any such actual embodiment, numerous implementation-specific decisions must be made to achieve the developers' specific goals, such as compliance with system-related and business-related constraints, which will vary from one implementation to another. Moreover, it will be appreciated that such a development effort might be complex and time-consuming, but would nevertheless be a routine undertaking for those of ordinary skill in the art having the benefit of this disclosure. Further aspects and advantages of the various embodiments and related methodologies of the invention will become apparent from consideration of the following description and drawings.

Exemplary embodiments of the present invention are directed to a system that converts wellbore surface fluid pressures to bottom hole pressures using real-time fluid compositional data. As described herein, the present invention utilizes one or more pressure sensors and ICE computing devices that analyze the wellbore surface pressure and fluid to determine the bottom hole pressure. A conduit communicates fluid pressure and wellbore fluid from the wellhead to the sensor(s) and ICE computing device(s) for analysis. The pressure sensor is utilized to determine the surface pressure of the wellbore, while the ICE computing device identifies one or more characteristics of the wellbore fluid (compositional data, for example) continuously in real-time. The pressure sensor(s) and ICE computing device(s) may be separate modules coupled to the wellbore, or may be embodied in a single module. In certain embodiments, once the surface fluid pressure and fluid characteristic data are determined, the resulting data is then converted into bottom hole pressures using a local or remote signal processor. Accordingly, through use of the present invention, bottom hole pressures may be continuously monitored in real-time without the necessity of any downhole sensors or components.

The exemplary ICE computing devices described herein utilize one or more ICE structures, also known as a Multivariate Optical Elements (“MOE”), to achieve the objectives of the present invention. An ICE computing device is a device configured to receive an input of electromagnetic radiation from a substance or sample of the substance and produce an output of electromagnetic radiation from a processing element. Fundamentally, ICE computing devices utilize ICE structures to perform calculations, as opposed to the hardwired circuits of conventional electronic processors. When electromagnetic radiation interacts with a substance, unique physical and chemical information about the substance is encoded in the electromagnetic radiation that is reflected from, transmitted through, or radiated from the sample. This information is often referred to as the substance's spectral “fingerprint.” Thus, the ICE computing device, through use of the ICE structure, is capable of extracting the information of the spectral fingerprint of multiple characteristics/properties or analytes within a substance and converting that information into a detectable output regarding the overall properties of a sample.

Further discussion of the design and operation of various alternative ICE computing devices utilized in the present invention may be found in, for example, U.S. Pat. No. 6,198,531, entitled “OPTICAL COMPUTATIONAL SYSTEM,” issued to Myrick et al. on Mar. 6, 2001; U.S. Pat. No. 7,697,141, entitled “IN SITU OPTICAL COMPUTATION FLUID ANALYSIS SYSTEM AND METHOD,” issued to Jones et al. on Apr. 13, 2010; and U.S. Pat. No. 8,049,881, entitled “OPTICAL ANALYSIS SYSTEM AND METHODS FOR OPERATING MULTIVARIATE OPTICAL ELEMENTS IN A NORMAL INCIDENCE ORIENTATION,” issued to Myrick et al. on Nov. 1, 2011, each being owned by the Assignee of the present invention, Halliburton Energy Services, Inc., of Houston, Tex., the disclosure of each being hereby incorporated by reference in its entirety.

As illustrated in FIG. 1, an exemplary well system 10 comprises a wellbore 12 extending from a surface 14 of a hydrocarbon bearing formation, and may be cased or uncased. Although wellbore 12 is illustrated as vertical, it may also be deviated or horizontal. In addition, wellbore 12 may also be associated with either an inland well or an offshore operation. In offshore embodiments, a subsea blow-out preventer (“BOP”) 20, or wellhead, is positioned atop wellbore 12, while a subsea safety system 22 is coupled to a workstring 16 extending from the surface, as understood in the art. A pressure sensor module 24 and ICE computing device 100 are coupled to BOP 20 via a conduit 26 which hydraulically communicates wellbore fluid and associated fluid pressure from BOP 20. As such, in this embodiment, conduit 26 provides a continuous open fluid passage from the workstring 16 and through the BOP rams that instantly and equally transmits the fluid pressure to pressure sensor module 24. Although illustrated as being connected to the lowermost BOP ram, conduit 26 may also be connected at other positions along BOP 20, as will be understood by those ordinarily skilled in the art having the benefit of this disclosure.

Pressure sensor module 24 contains one or more pressure sensors and the associated electrical circuitry necessary to determine the pressure being communicated from BOP 20 through conduit 26. In certain exemplary embodiments, the pressure sensors are high-frequency, high-resolution pressure sensors that are packaged and calibrated to minimize ambient temperature effects at surface 14. The pressure sensors may take a variety of forms such as, for example, piezoelectric, resonant, potentiometric or electromagnetic, as will be understood by those ordinarily skilled in the art having the benefit of this disclosure. Although not illustrated, pressure sensor module 24 also contains one or more temperature sensors utilized to correlate the pressure readings, as understood in the art. A communications link 30a is coupled to pressure sensor module 24 in order to provide the necessary data communication between pressure sensor module 24 and some remote terminal such as, for example, a signal processor that further analyzes the surface fluid pressure data to determine bottom hole pressures, as will be described below.

A valve 28 is positioned along conduit 26 between pressure sensor module 24 and ICE computing device 100 in order to allow selective or periodic communication of the wellbore fluid from pressure sensor module 24 to ICE computing device 100. Valve 28 is provided to isolate ICE computing device 100 from pressure sensor module 24 during potential malfunctions of ICE computing device 100. In addition, well system 10 will be more effective by using a number of fluid characteristic readings over time, which is achieved by periodically opening valve 28 to bleed wellbore fluid through to ICE computing device 100.

As previously described, ICE computing device 100 analyzes the wellbore fluid in order to determine one or more characteristics of the fluid. Such characteristic data may include fluid compositional data of the gas phase, such as, for example, gas gravity, mole %, CO2, H2S, N2, or C1-C7 hydrocarbon or higher. In addition, fluid properties, such as, for example, water, may be analyzed as well. Once the characteristic data has been determined by ICE computing device 100, the data is then communicated via communications link 30b to some remote terminal for further determination of bottom hole pressures, as previously described. Although communications links 30a,b are illustrated as wired links, each may alternatively be wireless communication link as well.

After the wellbore fluid has been communicated through ICE computing device 100, it is then communicated to a vent mechanism that serves to discard the sample fluid that is in conduit 26 so that fresh wellbore fluid may subsequently enter conduit 26. In certain exemplary embodiments, the wellbore fluid may simply be vented into the atmosphere. However, in other embodiments, the wellbore fluid exiting ICE computing device 100 may be recycled back into wellbore 12.

In this exemplary embodiment, pressure sensor module 24 and ICE computing device 100 are positioned along surface 14 as illustrated. However, in an alternate embodiment, pressure sensor module 24 and ICE computing device 100 may be embodied within a single housing positioned along workstring 16 near surface 14. Workstring 16 may be a variety of strings such as, for example, a production, testing, or injection string. Moreover, those ordinarily skilled in the art having the benefit of this disclosure will realize that the present system may be utilized in a variety of applications, even non-oilfield related applications.

In an alternative embodiment, conduit 26 may be arranged such that it splits off into two separate conduits in which one branch communicates wellbore fluid to ICE computing device 100, while the other branch communicates wellbore fluid to pressure sensor module 24. In such embodiments, valve 28 would again be positioned along the branch communicating with ICE computing device in like manner to that described in FIG. 1.

FIG. 2 illustrates a block diagram of ICE computing device 100 according to certain exemplary embodiments of the present invention. As shown in FIG. 2, an electromagnetic radiation source 108 may be configured to emit or otherwise generate electromagnetic radiation 110. As understood in the art, electromagnetic radiation source 108 may be any device capable of emitting or generating electromagnetic radiation. For example, electromagnetic radiation source 108 may be a light bulb, light emitting device, laser, blackbody, photonic crystal, or X-Ray source, etc. In one embodiment, electromagnetic radiation 110 may be configured to optically interact with the fluid 106 and generate fluid-interacted light 112 directed to a first ICE 102. In this example, fluid 106 is the wellbore fluid communicated from BOP 20 via conduit 26.

While FIG. 2 shows electromagnetic radiation 110 as passing through the multiphase fluid 106 to produce fluid-interacted light 112, it is also contemplated herein to reflect electromagnetic radiation 110 off of multiphase fluid 106, such as in the case of a multiphase fluid 106 that is translucent, opaque, or has solids therein, and equally generate the fluid-interacted light 112. In this specific embodiment, fluid 106 is a multiphase fluid originating from wellbore 12 (comprising oil, gas, water, solids, for example) consisting of a variety of fluid characteristics such as, for example, C1-C5 and higher hydrocarbons, groupings of such elements, and saline water. Moreover, as defined herein, the term “characteristic” means a chemical or physical property or element contained in the multiphase fluid or which forms the multiphase fluid and which includes, but is not limited to SARA (saturates, asphaltene, resins, aromatics), solid particulate content such as dirt, mud, scale, sand, and similar contaminants, water, water ion-composition and content, saturation level, mass readings, hydrocarbon composition and content, gas composition and content, carbon dioxide, hydrogen sulfide, and correlated PVT properties including GOR (gas-oil ratio), bubble point, density, a formation factor and viscosity among other properties. Furthermore, the term “characteristic” as used herein includes calculated data and information, such as, for example, quantities, concentrations, relative proportions and fractions of measured elements and other properties, mass, volume, mass and volume, flow rate, etc. of the multiphase fluid and its constituents. In addition, the fluid characteristics may be measured indirectly, through measuring an indicator constituent (explained further below).

After being illuminated with electromagnetic radiation 110, multiphase fluid 106 containing an analyte of interest (a characteristic of the fluid, for example) produces an output of electromagnetic radiation (fluid-interacted light 112, for example). Although not specifically shown, one or more spectral elements may be employed in ICE computing device 100 in order to restrict the optical wavelengths and/or bandwidths of the system and, thereby, eliminate unwanted electromagnetic radiation existing in wavelength regions that have no importance. As will be understood by those ordinarily skilled in the art having the benefit of this disclosure, such spectral elements can be located anywhere along the optical train, but are typically employed directly after the light source which provides the initial electromagnetic radiation. Various configurations and applications of spectral elements in optical computing devices may also be found in commonly owned U.S. Pat. Nos. 6,198,531; 7,697,141; and 8,049,881, as previously mentioned herein.

Still referring to the exemplary embodiment of FIG. 2, ICE computing device 100 includes first ICE 102a, second ICE 102b and additional ICE 102n, each configured to determine one characteristic of multiphase fluid 106. In this embodiment, the properties determined include the presence and quantity of specific inorganic gases such as, for example, CO2 and H2S, organic gases such as methane (C1), ethane (C2) and propane (C3) and saline water. In certain embodiments, a single ICE may detect a single characteristic, while in others a single ICE may determine multiple properties, as will be understood by those ordinarily skilled in the art having the benefit of this disclosure.

In the embodiment specifically depicted, the first ICE 102a is arranged to receive the fluid-interacted light 112 from the fluid 106. First ICE 102a is configured to transmit a first optically interacted light 104a to the first detector 116a and simultaneously convey reflected optically interacted light 105 toward the second ICE 102b. The second ICE 102b is configured to convey a second optically interacted light 104b via reflection toward the second detector 116b, and simultaneously transmit additional optically interacted light 108 toward the additional ICE 102n. The additional ICE 102n is configured to convey an additional optically interacted light 104n via reflection toward the additional detector 116n.

Those ordinarily skilled in the art having the benefit of this disclosure will readily recognize numerous alternative configurations of the first, second, and additional ICE structures depicted herein as 102a-n, without departing from the scope of the disclosure. For example, reflection of optically interacted light from a particular ICE structure may be replaced with transmission of optically interacted light, or alternatively configurations may include the use of mirrors or beam splitters configured to direct the electromagnetic radiation 110 (or fluid-interacted light 112) to each of the first, second, and additional ICE 102a-n.

In certain exemplary embodiments, first, second, and additional detectors 116a-n may be configured to detect the first, second, and additional optically interacted light 104a-n, respectively, and thereby generate a first signal 106a, a second signal 106b, and one or more additional signals 106n, respectively. In some embodiments, the first, second, and additional signals 106a-n may be received by a local signal processor 118 communicably coupled to each detector 116a-n and configured to computationally combine the first, second, and additional signals 106a-n in order to determine the characteristic of the multiphase fluid 106. Although illustrated as part of ICE computing device 100, signal processor 118 may be located remotely and, in such embodiments, signals 106a-n may be transmitted using wired or wireless methodologies, as understood in the art.

Accordingly, any number of ICE may be arranged or otherwise used in series in order to determine the desired characteristic of the multiphase fluid 106 that is used to determine bottom hole pressures. In some embodiments, each of the first, second, and additional ICE 102a-n may be specially-designed to detect the particular characteristic of interest or otherwise be configured to be associated therewith. In other embodiments, however, one or more of the first, second, and additional ICE 102a-n may be configured to be disassociated with the particular characteristic of interest, and/or otherwise may be associated with an entirely different characteristic of the multiphase fluid 106. In yet other embodiments, each of the first, second, and additional ICE 102a-n may be configured to be disassociated with the particular characteristic of interest, and otherwise may be associated with an entirely different characteristic of the multiphase fluid 106. Moreover, although not shown, ICE computing device 100 also comprises the necessary components to produce the pressure and temperature measurements, or operating conditions, associated with multiphase fluid 106 necessary to determine operating conditions, as will be understood by those ordinarily skilled in the art having the benefit of this disclosure.

Accordingly, through use of exemplary embodiments of ICE computing 100, the amount and composition of the gas phase and water phase of multiphase fluid 106 of wellbore 12 may be constantly monitored. Referring back to FIG. 1, the resulting fluid characteristic data, along with the fluid pressure data generated by pressure sensor module 24, are then transmitted via communication links 30a,b to a remote signal processing terminal (not shown), whereby bottom hole pressures may be determined. As will be understood by those ordinarily skilled in the art having the benefit of this disclosure, the remote signal processor will then perform a bottom hole pressure determination algorithm that converts the surface fluid pressure data into bottom hole pressures using mathematical equations (Cullender and Smith, for example), Equation of State (“EOS”) computations and the real-time fluid characteristic data. There are a variety of other bottom hole pressure determination algorithms that may be used including, for example, the software algorithm embodied within the SPIDR® platform, commercially offered through the Assignee of the present invention, Halliburton Energy Services, Company of Houston, Tex. Alternatively, however, other bottom hole pressure determination algorithms may also be utilized without departing from the scope of the present invention.

In certain exemplary embodiments, the bottom hole pressure computations may be conducted within pressure sensor module 24 or ICE computing device 100. In such embodiments, a signal processor will be located on-board pressure sensor module 24 or ICE computing device 100 to perform the necessary computations. Thereafter, the resultant data may then be communicated remotely as previously described herein. FIG. 3 is a flow chart of a method 300 for converting surface fluid pressure to bottom hole pressure according to certain exemplary methodologies of the present invention. With reference to FIG. 1 also, wellbore fluid is communicated through conduit 26 to pressure sensor module 24 and ICE computing device 100, at block 302. Pressure conduit 26 may be continuously coupled to BOP 20 via a port such it remains statically open. Alternatively, conduit 26 may be equipped with a suitable valve which may be open/closed selectively. At block 304, the surface fluid pressure of the wellbore fluid is determined using pressure sensor module 24 in hydraulic connection with the fluid traveling through conduit 26. At block 306, one or more wellbore fluid characteristics are determined using ICE computing device 100. In certain embodiments, the determination of the fluid characteristic is performed in real-time. In addition, the determination of the fluid characteristic may be performed periodically or continuously. At block 308, bottom hole pressures are then determined using the surface fluid pressure and wellbore fluid characteristic data.

Accordingly, the exemplary embodiments of well system 10 described herein utilize real-time wellbore fluid characteristic data to convert wellhead pressures to bottom hole pressures. Pressure transient analysis is the performed in order to derive numerous relevant reservoir parameters such as, for example, skin, permeability, and initial reservoir pressure, which may be applied in a variety of applications, such as, for example, build-up testing, injection fall-off testing, multiple rate testing, step rate testing, or well communication testing. In addition, the present invention may also be applied in stimulation planning and execution, package leakage testing and flow measurement testing. As a result, the accuracy of the computed bottom hole pressures is greatly increased, especially where condensates and black oils are present.

An exemplary methodology of the present invention provides a method for converting wellbore surface fluid pressure to bottom hole pressure, the method comprising providing fluid from a wellbore to a conduit in fluid communication with a pressure sensor and an ICE computing device, determining a surface fluid pressure at the wellbore using the pressure sensor, determining a characteristic of the fluid using the ICE computing device, and determining a bottom hole pressure of the wellbore using the surface fluid pressure and characteristic of the fluid. In another method, determining the characteristic of the fluid is performed in real-time. In yet another, the characteristic of the fluid comprises an amount of at least one of C1 hydrocarbon, C2 hydrocarbon, C3 hydrocarbon, C4 hydrocarbon, C5 hydrocarbons, C6 hydrocarbons, C7 hydrocarbons or water within the fluid.

In another methodology, at least one of the surface fluid pressure or bottom hole pressure are determined in real-time. In yet another, the conduit is coupled to a wellhead. In another method, determining the characteristic of the fluid further comprises periodically communicating the fluid to the ICE computing device using a valve, thereby providing a plurality of characteristic readings of the fluid over a period of time. Yet another methodology further comprises locating the pressure sensor and ICE computing device at a surface location.

An exemplary embodiment of the present invention provides a system for converting wellbore surface fluid pressure to bottom hole pressure, the system comprising a pressure sensor in fluid communication with the wellbore to determine a surface fluid pressure of the wellbore, and an ICE computing device that optically interacts with wellbore fluid to determine a characteristic of the wellbore fluid, wherein a bottom hole pressure of the wellbore is determined based upon the surface fluid pressure and the characteristic of the wellbore fluid. In another embodiment, the characteristic of the wellbore fluid is a real-time fluid characteristic. In yet another, the system further comprises a signal processor communicably coupled to the pressure sensor and ICE computing device to determine the bottom hole pressure using the surface fluid pressure and the characteristic of the wellbore fluid. In another, the characteristic of the wellbore fluid comprises an amount of at least one of C1 hydrocarbon, C2 hydrocarbon, C3 hydrocarbon, C4 hydrocarbon, C5 hydrocarbons, C6 hydrocarbons, C7 hydrocarbons or water within the wellbore fluid.

In another embodiment, at least one of the surface fluid pressure or bottom hole pressure are real-time data. In yet another, the wellbore fluid is communicated to the pressure sensor using a conduit coupled to a wellhead. In yet another, the ICE computing device is fluidly coupled to the wellbore using a conduit, the system further comprising a valve positioned along the conduit to periodically communicate the wellbore fluid to the ICE computing device over a period of time. In yet another, the pressure sensor and ICE computing device are positioned at a surface location.

Yet another exemplary methodology of the present invention provides a method for converting wellbore surface fluid pressure to bottom hole pressure, the method comprising converting a surface fluid pressure to a bottom hole pressure using at least one fluid characteristic of a wellbore fluid, the at least one fluid characteristic being determined in real-time. In another method, the at least one fluid characteristic is determined using an ICE computing device. In yet another, the at least one fluid characteristic comprises an amount of at least one of C1 hydrocarbon, C2 hydrocarbon, C3 hydrocarbon, C4 hydrocarbon, C5 hydrocarbons, C6 hydrocarbons, C7 hydrocarbons or water within the wellbore fluid. Another method further comprises communicating the wellbore fluid from a wellhead to the ICE computing device using a conduit. Yet another further comprises periodically communicating the wellbore fluid to the ICE computing device, thereby providing a plurality of the at least one fluid characteristics over a period of time.

Although various embodiments and methodologies have been shown and described, the invention is not limited to such embodiments and methodologies and will be understood to include all modifications and variations as would be apparent to one skilled in the art. For example, instead of utilizing an Integrated Computational Element, other analytical devices may be utilized to provide the fluid characteristic data such as, for example, a narrow band optical filter or a portable gas chromatograph. Therefore, it should be understood that the invention is not intended to be limited to the particular forms disclosed. Rather, the intention is to cover all modifications, equivalents and alternatives falling within the spirit and scope of the invention as defined by the appended claims.