Multi-Phase Region Analysis Method And Apparatus

Abstract

A method and apparatus for measuring a presence of a multi-phase system is disclosed. The method includes positioning a fluid communication device of a down hole tool in a well bore, drawing fluid from the well bore to an evaluation cavity and sampling the fluid to determine a presence of a multi-phase system.

Description

BACKGROUND OF THE DISCLOSURE

Wellbores are commonly drilled to locate and extract sub-surface hydrocarbons. A drilling tool with a downhole end bit is advanced into a subterranean formation having hydrocarbons or other desired materials. As the drilling tool is advanced, drilling mud is pumped through the drilling tool and out the end of the drill bit to both cool the drilling tool and carry away cuttings up an annular region. When the wellbore reaches a predetermined level, operators may attempt to recover hydrocarbons trapped in the formation through various pieces of equipment and methodologies.

One common step in conventional hydrocarbon recovery methodology entails using a chromatography sampling apparatus at the surface to analyze fluids from the subterranean environment. Such evaluation allows operators to analyze and characterize the fluids using various techniques. Conventional apparatus and methods for sampling, however, have significant drawbacks. In conventional systems, volumes of liquid and gas formed within a multi-phase region of the formation cannot be effectively analyzed as the methods and systems are prone to error due to, for example, drilling fluid or mud contamination. Such evaluations are not conducted at optimum conditions (i.e. wellbore conditions) and a high relative error is introduced based upon the sampling technique.

Evaluation of multi-phase regions in subterranean formations is especially important to effectively evaluate reservoirs. For gas field operations, where there are significant amounts of gas condensates, characterization is particularly important as estimates of economic return on investment can hinge on both the types of equipment used to remove the condensates and the overall number of processing units. There is a need for both a method and apparatus to evaluate multi-phase regions of hydrocarbon formations at formation conditions to determine fluid types and volumes and to eliminate errors from incorrect sampling and evaluation.

BRIEF DESCRIPTION OF THE DRAWINGS

So that aspects can be understood in detail, a more particular description of the invention, may be had by reference to the embodiments thereof that are illustrated in the drawings. It is to be noted, however, that the drawings illustrate only typical embodiments of this invention and are therefore not to be considered limiting of its scope, for the invention may admit to other equally effective embodiments. Dimensions of various features may be arbitrarily increased or reduced for clarity of discussion.

FIG. 1 illustrates a schematic diagram, including a partial cross-sectional view, of a drilling system having a wellbore telemetry device and a downhole tool connected to a drill string and deployed from a rig into a wellbore.

FIG. 2 is a pressure verses temperature graph for differing reservoir fluids including dry gas, wet gas, gas condensates, volatile oil and black oil.

FIG. 3 is a pressure verses temperature graph of a fluid mixture showing a (liquid+gas) multi-phase border and liquid quality lines of constant liquid volume within a multi-phase region.

FIG. 4 is a dew curve indicating retrograde condensation for a subterranean hydrocarbon fluid.

FIG. 5 is a series of inverted tubes containing a hydrocarbon fluid over a mercury base illustrating how a decreased pressure can affect the amount of liquid phase of the fluid in a sample.

FIG. 6 is a first example embodiment of an arrangement for sampling and analyzing fluid from a subterranean formation while in a wellbore.

FIG. 7 is a second example embodiment of an arrangement for sampling and analyzing fluid from a subterranean formation while in a wellbore, wherein two analysis configuration are provided for simultaneous or singular analysis of formation samples.

FIG. 8 is a third example embodiment of an arrangement for sampling and analyzing fluid from a subterranean formation while in a wellbore, wherein two analysis configurations are provided for simultaneous or singular analysis of formation samples and the two configurations are separated by a set of isolation valves.

FIG. 9 is an example tubular component used in FIGS. 6, 7 and 8 for providing liquid level sensors for fluid evaluation.

FIG. 10 is an second example embodiment of a tubular component used in FIGS. 6, 7 and 8 with sensors atop a bottom of the tubular to obtain properties of both liquid and gas phases of the formation fluid.

FIG. 11 is a method of analyzing a multi-phase region of a subterranean formation.

DETAILED DESCRIPTION

Certain terms are defined throughout this description as they are first used, while certain other terms are used in this description as defined below:

“Annular” is defined as relating to, or forming a ring (i.e., a line, band or arrangement) in the shape of a closed curve such as a circle or an ellipse.

“Downhole tool” is defined as a tool or tools deployed into the wellbore by, for example, a drill string, wireline, slickline, tubing, casing, and coiled tubing that may be used for performing operations related to the evaluation, production and/or management of one or more subsurface formations of interest.

“Operatively connected” is defined as directly or indirectly connected for transmitting or conducting information, force, energy or matter (including fluids).

“Virgin fluid” is defined as subsurface fluid that is sufficiently pure, pristine, connate, uncontaminated or otherwise considered in the fluid sampling and analysis field to be acceptably representative of a given formation for valid hydrocarbon sampling and/or evaluation.

“Continuous” is defined as marked by uninterrupted extension of time, space or sequence.

It is to be understood that the following disclosure provides many different embodiments, or examples, for implementing different features of various embodiments. Specific examples of components and arrangements are described below to simplify the present disclosure. These are, of course, merely examples and are not intended to be limiting. In addition, this disclosure may repeat reference numerals and/or letters in the various examples. This repetition is for the purpose of simplicity and clarity and does not in itself dictate a relationship between the various embodiments and/or configurations discussed. Moreover, the subterranean formation of a first feature over or on a second feature in the description that may include embodiments in which the first and second features are formed in direct contact, and may also include embodiments in which additional features may be formed interposing the first and second features, such that the first and second features may not be in direct contact.

In accordance with the present disclosure, a wellsite with associated wellbore and apparatus is described in order to describe a typical, but not limiting, embodiment of the application. To that end, apparatus at the wellsite may be altered, as necessary, due to field considerations encountered.

Determining reservoir fluid properties is an important part of any reservoir evaluation. In general, for proper reservoir characterization, representative fluids from a formation should be used to determine both subterranean fluid properties and fluid chemical composition. Conventionally, analysis of fluid formations entails removing a subterranean sample, letting the sample form a two phase region within a bottle, and then analyzing the sample after recombining the different phases of the sample with simultaneous heating and pressurization. Agitation may also be used. Such surface sampling and attempted recombination of the constituent phases can be sources of large error in properly characterizing a subterranean fluid and formation. Using surface sampling or sampling at non-subterranean temperatures and pressures can lead to inaccurate estimates of fluid properties that are not representative of those of the reservoir virgin fluid. Additionally, surface samples are affected by production conditions prior to and during sampling and are thus prone to error as the sample can be significantly disturbed or altered when the samples are taken from the wellbore. Formation measurements of the constituent properties of gas and oil in multi-phase systems is best determined within the wellbore as such samples undergo minimal disturbance. Conventional systems lack the ability to obtain and analyze such samples without significant disturbance.

To illustrate the inherent error in sampling and evaluation of a formation fluid at conditions other than those present in the formation, FIG. 4 illustrates a condition known as retrograde condensation. In the retrograde system of FIG. 4, both liquid and gas will be present in production tubing and surface facilities as the production pathway (i.e. drill string and multi-phase analysis tool) enters the two-phase region, traveling along retrograde condensation and evaporation pathway “b” over the fluid dew curve as pressure is slightly decreased. In the illustrated embodiment along pathway “b”, volatile oil behavior, for example, is similar to that of retrograde gas condensates because T is less than Tc, where T is the in-situ temperature and Tc is the condensation temperature. Thus, when the temperature of the formation is close to condensation temperature, condensates may be present in different amounts according to other factors. In field conditions, during reservoir depletion, volatile oils and retrograde condensates differ significantly, wherein a gas phase evolves in the subterranean formation at pressures less than the bubble pressure. Small changes in methodology chosen in formation fluid sampling and evaluation can lead to the incorrect assignment of a gas condensate phase for a volatile oil or vice versa. As an example, if a sample is not representative of the formation, the sample may indicate a many fold increase in gaseous components over that which actually exists. Under these circumstances, production engineers may design a top side facility that is inappropriate for the fluid to be produced. Aspects of the methodology and apparatus provided herein alleviate these concerns. Using the configurations and methodologies described herein, such inaccuracies are avoided as a virgin fluid sample measured at appropriate temperature and pressure readings is used for characterization of the multi-phase region.

Referring to FIG. 4, specifically along pathway “b”, at point 401, the pathway intercepts the dew curve indicating a presence of liquids. At point 402, the dew curve is exited. At points along pathway “b” in between points 401 and 402, the pathway indicates both a liquid and gas component for the hydrocarbon. The liquids formed during travel along pathway “b” are predominately higher molar mass compounds. The liquid amount is dependent upon temperature, pressure and chemical composition of the original hydrocarbon gas. A fluid with significant but relatively low higher molar mass components is called a lean gas condensate. In one example, a lean gas condensate might produce a volume of less than 561 cubic meters of liquid from 10⁶ cubic meters of gas while a so called rich condensate might produce 842 cubic meters of liquid for 10⁶ cubic meters of gas. In this example, all of the volumes refer to local standard temperature and pressure. It is thus vital for engineers and operators to understand the specific subterranean characteristics for evaluation of a fluid as the potential production can vary from gaseous components, to liquid, and back to gas.

To illustrate matters further, referring to FIG. 5, a series of inverted tubes, A, B, C, D and E, is presented where a hydrocarbon is placed over a mercury layer 501. Progressing from the right tube E to the left tube A, pressure is decreased. In the middle tube, C, a maximum amount of liquid 502 is present with a corresponding minimum of gas 503. At the left most tube, A, where the pressure is the least, the amount of liquid 504 is negligible while the amount of gaseous component is maximized 505. It is thus important to accurately determine subterranean conditions as these conditions will ultimately determine the quantity and type of hydrocarbon removed. Typically, pressure and temperature will affect these liquid/gaseous phases. Moreover, conditions may change over time in the formation and it would be advantageous to proactively determine the future amounts and types of hydrocarbons to be removed.

Referring to FIG. 1, a schematic view of an apparatus is illustrated according to one or more aspects of the present disclosure. The apparatus includes a drilling rig 100 or similar lifting device employable to move a drill pipe string 105 within a wellbore 110 that has been drilled through subterranean formations, shown generally at 115, that provides an environment for application of one or more aspects of the present disclosure. The drill pipe string 105 may be extended into the wellbore 110 by threadedly coupling together, end to end, a number of coupled drill pipes (one of which is designated 120) of the drill pipe string 105. The drill pipe 105 may be structurally similar to ordinary drill pipes, as illustrated for example, in U.S. Pat. No. 6,174,001, issued to Enderle, entitled “Two-Step, a Low Torque, Wedge Thread for Tubular Connector,” issued Aug. 7, 2001 and includes a cable associated with each drill pipe 120 that serves as a communication channel. A cable in the drill pipe string may be any type of cable capable of transmitting data and/or signals, such as an electrically conductive wire, a coaxial cable, an optical fiber or the like.

The drill pipe string 105 typically includes some form of signal coupling to communicate signals between adjacent drill pipes when coupled end to end, as illustrated. See, as a non-limiting example, the description of one type of wired drill pipe having inductive couplers at adjacent drill pipe collars in U.S. Pat. No. 6,641,434. However, one or more aspects of the present disclosure are not limited to the drill pipe string 105 and can include other communication or telemetry systems, including a combination of telemetry systems, such as a combination of wired drill pipe, mud pulse telemetry, electronic pulse telemetry, acoustic telemetry or the like.

The drill pipe string 105 may include one, an assembly, or a “string” of downhole tools at a lower end thereof. In the illustrated example, the downhole tool string may include well logging tool(s) 125 coupled to a lower end thereof. As used in the present description, the term “well logging tool” or a string of such tools, is defined as one or more wireline well logging tools that are capable of being conveyed through a wellbore using armored electrical cable (“wireline”), logging while drilling tools, formation evaluation tools, formation sampling tools and/or other tools capable of measuring a characteristic of the subterranean formation 115 and/or of the wellbore 110.

Several of the components disposed proximate the drilling rig 100 may be used to operate components of the system. These components will be explained with respect to their uses in drilling the wellbore 110 for a better understanding thereof. The wired drill pipe string 105 may be used to turn and axially urge a drill bit into the bottom of the wellbore 110 to increase its length (depth). During drilling of the wellbore 110, a pump 130 lifts drilling fluid (“mud”) 135 from a tank 140 or pit and discharges the mud 135 under pressure through a standpipe 145 and flexible conduit 150 or hose, through a topdrive 155 and into an interior passage inside the drill pipe 105. The mud 135, which can be water- or oil-based, exits the wired drill pipe 105 through courses or nozzles (not shown separately) in the drill bit 116, where it then cools and lubricates the drill bit and lifts drill cuttings generated by the drill bit 116 to the surface of the earth through an annular arrangement.

When the wellbore 110 has been drilled to a selected depth, the drill pipe 105 may be withdrawn from the wellbore 110. An adapter sub 160 and the well logging tools 125 may be then coupled to the end of the drill pipe 105, if not previously installed. The drill pipe 105 may then be reinserted into the wellbore 110 so that the well logging tools 125 may be moved through, for example in the illustrated embodiment, a highly inclined portion 165 of the wellbore 110, which would be inaccessible using armored electrical cable (“wireline”) to move the well logging tools 125. The well logging tools 125 may be positioned on the wired drill pipe 105 in other manners, such as by pumping the well logging tools 125 down the wired drill pipe 105 or otherwise moving the well logging tools 125 down the wired drill pipe 105 while the wired drill pipe 105 is within the wellbore 110.

During well logging operations, the pump 130 may be operated to provide fluid flow to operate one or more turbines (not shown in FIG. 1) in the well logging tools 125 to provide power to operate certain devices in the well logging tools 125. However, when tripping in or out of the wellbore 110, it may be infeasible to provide fluid flow. As a result, power may be provided to the well logging tools 125 in other ways. For example, batteries may be used to provide power to the well logging tools 125. In one embodiment, the batteries may be rechargeable batteries that may be recharged by turbine(s) during fluid flow. The batteries may be positioned within a housing of one or more of the well logging tools 125. Other manners of powering the well logging tools 125 may be used including, but not limited to one time power use batteries.

As the well logging tools 125 are moved along the wellbore 110 by moving the wired drill pipe 105 as explained above, signals may be detected by various devices, of which non-limiting examples may include a resistivity measurement device 170, a gamma ray measurement device 175 and a formation fluid sampling tool 610, 710, 810 which may include a formation fluid pressure measurement device (not shown separately). The signals may be transmitted toward the surface of the earth along the wired drill pipe 105.

When tripping in and out of the wellbore 110 or performing another process wherein drill pipe 120 is being added, removed or disconnected from the wired drill pipe 105, it may be beneficial to have an apparatus and system for communicating from the wired drill pipe 105 to a surface computer system 185 or other component configured to receive, analyze, and/or transmit data. Accordingly, a second adapter sub 190 may be coupled between an end of the wired drill pipe 105 and the topdrive 155 that may be employed to provide a wired or wireless communication channel or path with a receiving unit 195 for signals received from the well logging tools 125. The receiving unit 195 may be coupled to the surface computer system 185 to provide a data path therebetween that may be a bidirectional data path.

Continuing with FIG. 1, the drill string 105 may suspend from the drilling rig 100 into the wellbore 110 and may be connected to rotary table, a kelly, a traveling block or hook, and may additionally include a rotary swivel. The rotary swivel may be suspended from the drilling rig 100 through the hook, and the kelly may be connected to the rotary swivel such that the kelly may rotate with respect to the rotary swivel. The kelly may be any matched set of polygonal or splined outer surface pipe that mates to a kelly bushing such that actuation of a drive may rotate the kelly.

An upper end of the drill string 105 may be connected to the kelly, such as by threadingly connecting the drill string 105 to the kelly, and the rotary table may rotate the kelly, thereby rotating the drill string 105 connected thereto. As such, the drill string 105 may be able to rotate with respect to the hook. Though a rotary drilling system is shown in FIG. 1, other drilling systems may be used without departing from the scope of the present disclosure.

Though not shown, the drill pipe string 105 may include one or more stabilizing collars. A stabilizing collar may be disposed within and/or connected to the drill string 105, in which the stabilizing collar may be used to engage and apply a force against the wall of the wellbore 110. This may enable the stabilizing collar to prevent the drill pipe string 105 from deviating from the desired direction for the wellbore 110. For example, during drilling, the drill pipe string 105 may “wobble” within the wellbore 110, thereby allowing the drill pipe string 105 to deviate from the desired direction of the wellbore 110. This wobble action may also be detrimental to the drill pipe string 105, components disposed therein, and the drill bit 116 connected thereto. A stabilizing collar may be used to minimize, if not overcome altogether, the wobble action of the drill pipe string 105, thereby possibly increasing the efficiency of the drilling performed at the wellsite and/or increasing the overall life of the components at the wellsite.

LWD tools used with the drilling rig 100 may include a thick-walled housing, commonly referred to as a drill collar, and may include one or more of a number of logging devices. Thus, the LWD tool may be capable of measuring, processing, and/or storing information therein, as well as communicating with equipment disposed at the surface of the wellsite.

MWD tools may include one or more of the following measuring tools: a weight-on-bit measuring device, a torque measuring device, a vibration measuring device, a shock measuring device, a stick slip measuring device, a direction measuring device, an inclination measuring device, and/or any other device. It is contemplated to incorporate one or more of the tools and/or other devices shown in FIG. 1 with one or more aspects of the present disclosure.

Referring to FIG. 2, a pressure verses temperature plot of constant compositions of matter is illustrated, the figure showing a bubble cure, a dew curve and temperatures relative to a critical point at which liquid oil and gas coexist. In FIG. 2, differing materials, all with constant composition, are plotted on a pressure verses temperature graph to indicate dew curves for each substance. Aspects, described later, provide a tubular that is configured to measure temperature, pressure, density and viscosity as well as the phase borders of (solid+liquid) and (gas+liquid) for these specific compositions of matter as well as compositions of matter that are not constant in composition.

The borders of the associated dew curves provided may be determined by increasing the volume occupied by a captured fixed amount of substance that results in a decrease in pressure on the sample. The apparatus and the method employed can be used for all reservoir hydrocarbon types that have a (liquid+gas) phase border such as: dry gas 202, wet gas 204, gas condensate 206, volatile oil 208 and black oil 210 as provided in FIG. 2. As illustrated in FIG. 2, in general, the heavier the constituent substance, the more depressed the curve is, with dry gas 202 being the least depressed.

In FIG. 2, the (solid+liquid) phase borders broadly represent wax, asphaltene and hydrate formation and can occur within the single phase region as well as within the multiple phase region within the (liquid+gas) phase border. Information obtained from measurements of fluids in these states can be used as input to determine preliminary equations-of-state. These equations-of-state, called cubic equations of state, are used to perform reservoir quantification and simulation, surface facility design and, if required, transmission system estimation. In one embodiment, the data may be used as part of economic analyses of an exploration well or result in adjustments to production processes in operation.

The ability of the equations of state to reproduce the states of the fluids within the two-phase region illustrated in FIG. 2, is necessary for proper characterization. These states can be determined by comparison with measurements of the fluid obtained while decreasing the pressure beneath that of the phase border of the fluid, as illustrated in FIG. 5.

Distinguishing gas condensates from volatile oils, for example, can be problematic as the gas condensates and volatile oils have different variations of liquid-drop-out volumes as a function of decreasing pressure. Measurements of the properties of the phases in equilibrium is important and also assist in tuning the predictive models.

Referring to FIG. 3, a pressure versus temperature plot 300 is provided for a hydrocarbon. The plot 300 provides an envelope 302 which is the liquid/gas boundary for the hydrocarbon. The areas within the boundary 304 indicates that both liquid and gas will be present, while areas outside of the boundary indicate that only a gas will be present. The boundary has a dew-point line 306 and a bubble-point line 308. The dew point line 306 indicates the point on the pressure versus temperature plot 300 at which vapor will condense into a liquid state. As illustrated, a first line of constant temperature 310, indicates that as pressure decreases from an initial pressure at point 311, the dew point line is reached at 312. As pressure decreases, the percentage of liquid increases from trace amounts up to approximately 17% of the total. After reaching a maximum at point 314, the percentage of liquid then decreases to a final point 316 on the line at approximately 11%. For a second line 320, at a higher temperature, the dew point line is reached at approximately the same pressure as before, however as the line continues, the maximum percentage of fluid only reaches 4% at point 322. The difference between the two lines indicates that percentages of the total amount of hydrocarbons can be greatly impacted by temperature and pressure. The effects described above can be even more pronounced if the temperature is decreased, where the liquid percentage could exceed 30%. Accurate quantification, therefore, is vital for measurement in the field.

FIG. 6 provides one non-limiting aspect of a downhole tool 610 used to draw fluid from a subterranean formation, to establish the equations-of-state and properly sample and analyze a formation. FIGS. 6, 7 and 8 are variants of a fluid measuring apparatus disclosed in US 2006/0243033 A1. The downhole tool 610 has a fluid analysis assembly 626 used by operators to analyze subterranean formation fluids in single or multi-phase states. The fluid analysis assembly 626 is configured to perform phase measurements, viscosity measurements and/or density measurements, as a non-limiting example, of the formation fluid. In the illustrated embodiment, the fluid analysis assembly 626 is provided with a chamber 660, a fluid movement device 662, a pressurization assembly 664 and one or more sensors 666. A sample chamber 650 is provided to accept formation fluid and dispense it as necessary. A probe 685 extends out from the body of the downhole tool 610 to allow packers 636 to contact a side wall of the wellbore. The entire downhole tool 610 may be placed into sampling position through a series of pistons pushing against the wellbore wall, contacting the packers 636 to the wellbore.

The packers 636 provide contact to the wellbore wall so that fluids may be extracted without damage to the rest of the downhole tool 610. To this end, the packers 636 are configured of a high temperature stable material, such as an elastomer. Temperature capability of the material may be over 300 degrees F. (approximately 150 degrees C.) and pressures greater than 500 pounds per square inch (3.477*10⁶ Pa). The packers 636, in the illustrated embodiment, are made of polytetrafluoroethylene (PTFE) as a non-limiting example embodiment. In the illustrated embodiment, the packers 636 are provided with an entrance that does not provide a sharp angle for fluid flow, thus allowing a more laminar flow regime for the formation fluid as it enters the downhole tool 610.

The chamber 660 has an evaluation cavity 668 configured to receive and store formation fluids, including liquid, gas and liquid/gas mixtures, for example. The chamber 660 may have any configuration capable of receiving the formation fluid and permit movement of the fluid, as discussed herein, so that the measurements can be conducted. As shown in FIG. 6, the chamber 660 may alternatively be configured with a bypass flow line communicating with a fluid communication device 646. The fluid communication device 646 accepts formation fluid from a formation wherein a series of packers 636 abut a wellbore wall and travels through fitting 618, thereby operatively connecting the arrangement to the formation. With this configuration, formation fluids can be positioned or diverted into the bypass flow line instead of entering the chamber 660. The fluid analysis assembly 626 is configured with a first valve 670, a second valve 672 and a third valve 674, wherein the valves 670, 672, 674 may be used to selectively divert the formation fluid into and out of the chamber 660. The valves 670, 672, 674 are also configured to mechanically isolate the chamber 660 from the fluid communication device 646.

Formation fluid may be accepted into the chamber 660 when the first and second valves 670,672 are opened while the third valve 674 is closed. In this configuration, a pump 652 moves the formation fluid into the chamber 660. In the illustrated embodiment, the pump 652, as well as the other pumps and fluid motion control devices, are designed to maintain flows that are laminar for accurate testing. The pumps, such as pump 652, may be controlled through the signal processing device 694 wherein the amount of force placed on the fluid may be variable at the desired rate by an operator.

In order to seal the chamber 660, the first and second valves 670,672 are closed to prevent further formation fluid flow. The third valve 674 may be opened, to permit differing operation of the downhole tool 610. For example, the third valve 674 may be opened and valves 670,672 closed while the fluid in chamber 660 is being evaluated. Additional valves and flow lines or chambers may be added, as desired, to facilitate the flow of fluid or to provide additional chambers as necessary for testing or retention of fluid within the tool 610.

A fluid movement device 662 is positioned to move and/or mix the formation fluid inside the evaluation cavity 668 as necessary, to enhance homogeneity of the fluid, if desired. The fluid movement device 662 can be any type of device that manipulates fluid in order for the fluid to be recirculated in the evaluation cavity 668, including, but not limited to a positive displacement pump, a vane pump, a screw pump, a peristaltic pump as non-limiting embodiments. Fluid may be moved through evaluation cavity 668 to enhance the accuracy of the measurements obtained by sensor(s) in FIGS. 9 and 10, described later. In the non-limiting embodiment disclosed, the fluid movement device 662 applies a force to the formation fluid to aid in recirculation of the fluid.

When the fluid movement device 662 mixes the fluid, a sensor or sensors can be positioned on the discharge side of the fluid movement device 662 to be within a vortex formed by the fluid movement device 662. These sensors, described in FIGS. 9 and 10, may be liquid level sensors that rely on acoustic or electromagnetic measurements.

In the example embodiment in FIG. 6, a pressurization assembly 664 is provided with a separate decompression chamber 682, a housing 684, a piston 686 and a piston motion control device 688. The piston 686 has an outer face 690 that interfaces with the housing 684 thereby defining the decomposition chamber 682. The piston motion control device 688 controls piston 686 location within the housing 684 to allow the volume of the decompression chamber 682 to be altered. As will be understood, the volume of the decompression system and the difference in pressure between a reservoir and a phase border may require multiple decompressions within a single phase by expulsion of excess fluid between expansions prior to reaching a phase border.

As the decompression chamber 682 volume changes, the pressure within the chamber 660 also changes and can be measured by a pressure gauge (not shown). Thus, as the decompression chamber 682 becomes larger, the pressure within the chamber 660 is reduced. Alternatively, when the decompression chamber 682 volume decreases, the pressure within the chamber 669 increases. The piston motion control device 688 can be any electronic and/or mechanical device capable of changing piston 686 position. For example, the piston motion control device 688 can be a pump exerting forces on a fluid on the piston 686 or a motor operably connected to the piston 686 via a mechanical linkage, such as a post, flange or threaded screw. In the illustrated embodiment, a signal processor 694 is used to evaluate sensor signals and to actuate valves 670, 672, 674 as well as actuating piston motion control device 688. The signal processor 694 is configured to communicate with the fluid movement device 662, the sensors 666 and the piston motion control device 688 via any suitable communication link. In an alternate configuration, the signal processor 694 may be configured remotely from the remainder of the downhole tool 610. The signal processor 694 is also configured to remotely provide communication capability to operators on the surface in a real-time environment.

The valves 670, 672, 674 may be any type valve that prevents flow from unintended escape. Such types of valves include hydraulic, ball, butterfly, choke, glove, needle and spool valves. In the illustrated embodiment provided, all of the valves provided are check valves to prevent leakage. In instances where ball valves are used, the ball valve material may be a non-corrosive material, such as stainless steel or titanium. All seats provided in the valves used are “soft” seat materials that help prevent leakage during use and enhance durability of the overall design.

The signal processor 694 can communicate with the fluid movement device 662, the sensor(s) 902, 1002, 1004 and/or the piston motion control device 688 via any suitable communication line, such as a cable or wire communication link, an airway communication link, infrared communication link or microwave communication link, as non-limiting examples. The signal processor 694 may be configured to be external to the housing, including, but not limited to, at ground elevation.

The signal processor 694 may include an electronic or optical configuration to execute logic and associated control valves such as 670, 672, 674 at the direction of the operator. Alternatively, the signal processor 694 may include a timer to accomplish actions on a timed basis, without need for operator interaction.

Referring to FIGS. 7 and 8, alternative configurations of the fluid analysis assembly are provided. In FIG. 7, the alternative configuration provides two fluid analysis assemblies with associated valves and sensors. In FIG. 8, additional isolation valves 720 and 722 are provided for the overall unit. In each of the alternative configurations, a signal processor, although present, has been omitted for clarity of the drawings. The signal processors in FIG. 7 and FIG. 8 are similar to the unit provided in FIG. 6.

Referring to FIG. 7, in an alternative configuration for sampling and testing formation fluid for multi-phase regional analysis, a pressurization assembly 764 changes formation fluid pressure within a chamber 760. This may be done in a continuous or a step wise manner as directed by and operator. The pressurization assembly 764 can be any type of device capable of communicating with the chamber 760 and changing either a volume or pressure of the formation fluid within the chamber 760 for evaluation. As provided in FIG. 7, a downhole tool 710 is presented wherein a pump 752 establishes a force on a formation fluid through line 746 and associated packer 736 and fitting 718. The fluid removed consequently travels along sample line 746. Fluid passes the pump 752 to a series of control valves 770, 774. Two separate sampling configurations are provided and each can be isolated through use of the control valves 770. Fluid may be drawn into either a pressurization/depressurization chamber 764 directly from the formation or from sample chamber 750. Two separate pumps 762 may exert a force on the formation fluid so that the fluid may enter and leave the chamber 764. Control valves 770, 772 may close such that a vacuum or pressurization may occur. Two trains are provided to allow for redundancy of evaluation and to allow more rapid evaluation time. Pumps 762 may be positioned to move fluid throughout the system. Control valves 766 may throttle or limit fluid flow to or from the pumps.

Each of the reservoir sampling tools previously described contains an analysis system as defined in FIGS. 6, 7 and 8 that may be deployed within a wellbore to a desired depth of a hydrocarbon bearing formation. The tools described herein could be conveyed by wire-line, drill-pipe, or coil tubing or any other means or apparatus, as non-limiting examples. Although the tools are shown in a vertical orientation in FIGS. 6, 7 and 8, the tool may equally be at an angle from vertical up to and including horizontal. The tool may also be at inverted angles for use in directional drilling.

In each of the illustrated embodiments of the downhole tool 610, 710 and 810, it may be necessary to test fluids at the ground surface level. To this extend, the sample chambers 650, 750 and 850 may be incorporated within the tool 610, 710 and 810 to be disengaged and taken to a laboratory for further analysis. The sample chambers 650, 750, 850 may have a quick disconnect to allow operators the ability to remove the chamber with minimal effort. The housing, not illustrated for clarity in the drawings, may have a doorway that allows the operators the ability to access the sample chambers 650, 750, 850.

To ensure proper sampling, a temperature probe maybe included within the housing of the down hole tool 610, 710, 810. The temperature probe is configured to measure wellbore temperature levels. A pressure probe/gauge may also be used provided. Likewise, temperature readings and pressure readings may be taken of the formation fluids and the results analyzed to allow operators the ability to see potential temperature discrepancies between the formation fluid temperature and the temperature of the downhole tool 610, 710, 810.

In the illustrated embodiments, the tool 610, 710, 810 is in a vertical orientation. For a fixed volume of liquid, a vertical orientation is defined by the location of the cylindrical axis of symmetry that provides the smallest area and consequently the greatest height variation when compared to that obtained from a tube oriented so the cylindrical axis is horizontal.

Referring to FIG. 8, a downhole tool 810 is illustrated. Similar to FIG. 7, a dual sampling and analysis system is presented for the downhole tool 810. Packers 836 abut a formation “F” establishing a seal between the tool 810 and the formation Fm through fitting 818. A pump 852 establishes a draw of formation fluid through sample line 846. The fluid is then directed through a series of control valves V to respective sensor sections “S”. Each sample and analysis configuration is connected to the other configuration through isolation valves 220 and 222. A sample may be drawn from sample chamber 850 or directly from the formation “F”. As in the previously discussed embodiments, each configuration may be independently controlled such that analysis can be performed singularly or in combination.

In addition to providing isolation of the respective configuration for sampling and analysis, the isolation valves 220 and 222 allow for the ability for an operator to mix samples between the two configurations, therefore allowing samples to be combined. In this embodiment, the isolation valves 220 and 222 may be controlled by the signal processing unit so that an operator may control actions of the separate trains.

Referring to FIGS. 9 and 10, tubulars, identified as 960 and 1000 contain sensors used for testing the formation fluids. In addition, the tubular 960, 1000 may also be fitted with additional sensors that permit the detection of liquid and gas. The configuration may or may not be combined with knowledge of the tool orientation and volume of the chamber 660, 760 permits the determination of either the presence of liquid formed from a gas below the dew curve. The tubular 960 and 1000 may be positioned, on FIG. 8, near the positions indicated on both trains in FIG. 8. In FIG. 7, the tubular may extend along the tubular denoted with the appropriate numerals. In FIG. 6, the tubular may be connected to the pressurization assembly 664. Additionally, the system may identify gas formed beneath the bubble curve. Fluid movement device 662, for example, can be operated during the volume determination. The liquid level sensors 902, 1002, 1004 rely on either acoustic technology or electromagnetic wave technology in non-limiting embodiments.

Example configurations of sensors are provide in FIG. 9 and FIG. 10. Sufficient sensors are distributed in the tubular provided in FIGS. 9 and 10 to permit a desired uncertainty in liquid and gas volumes to be determined. This distribution of sensors may be non-linear or linear. In the illustrated embodiments, the separation between detectors is less at the top and bottom of the tube to aid in analysis. Data is evaluated from a sample and used to distinguish between retrograde gas condensate and volatile oil. In one example embodiment, a pressure in the chamber 660 may be reduced for the former to first form then eliminate liquid.

The sensors, shown in FIGS. 9 and 10, may be paired as illustrated or may be single sensors. In one example, for a black oil sample (e.g. one that is optically opaque), the sensors 902 may be paired and optical transmission detected, if possible, through the sample. In the event that there is no signal provided, the total opacity is noted as there is no signal provided. For gas condensates, that are typically optically translucent, the acoustic sensors can be used to determine time of flight or impedance that are significantly different for the two phases potentially present in the fluid. In one embodiment, a liquid of density 800 g/cc and sound 1000 m/s can be in equilibrium with a gas of density opaque, 200 g/cc and sound 150 m/s. The sensors in FIGS. 9 and 10 may also conduct density and viscosity measurements that may be evaluated so that the sensor line has approximately equal volumes of both gas and liquid. The sensors may additionally be configured such that they may determine chemical composition of the phases present.

The sensors 902, 1002, 1004 used may be electromagnetic and provide estimates of a complex relative electric permittivity that can distinguish between gas, oil and water. For oil, the dielectric constant typically lies between two and ten but both higher and lower values have been observed. As a result, the method provided by one example embodiment identifies a presence of water.

In addition, if measurement sensors such as density and viscosity sensors 1002, 1004 are placed at the top and bottom of the tube as shown in FIG. 10, then when the pressure is reduced so that the sensor line has about an equal volume of both gas and liquid, measurements can be obtained to determine each phase. This information can be valuable for separator design. Although not shown, these sensor packages could also contain methods of determining chemical composition of the phases or methods of acquiring an aliquot of fluid for analyses of the form adopted for transitional laboratory phase equilibrium measurement that are commonly used and reported in archival literature.

Referring to FIG. 11, a method 1100 for conducting a multi-phase region analysis is illustrated. First, a downhole tool is positioned within a wellbore 1102. The positioning of the wellbore tool is such that fluid may be withdrawn from a geotechnical formation surrounding the wellbore without significant disturbance to the fluid. The positioning can include taking temperature measurements of the downhole tool environment for calculation purposes. In the illustrated embodiments provided in FIGS. 6, 7 and 8, packers are positioned on the wellbore wall so that a fluid may be extracted.

Next, the method 1100 provides for extraction of the fluid sample from the surrounding geotechnical formation 1104. The extraction of the fluid sample from the surrounding geotechnical formation 1104 is accomplished such that a pump draws the fluid into the interior casing of the downhole tool 610, 710, 810 for evaluation. The extraction of the fluid sample from the surrounding geotechnical formation 1104 may be directly into an evaluation chamber 660, for example, or the sample may be provided to a sample chamber 650. The extraction of the fluid sample 1104 may be through an insulated line such that there is negligible change in the overall temperature of the extracted sample. Thus, through the method and configuration provided the drawing of the fluid is performed at formation environmental conditions.

Next, the fluid is transported to an evaluation chamber for analysis 1106 from either the sample chamber 650 or directly from the formation. The transportation of the fluid to the evaluation chamber for analysis 1106 is done through internal tubular that are configured to transport a sufficient amount of fluid for later analysis. The transportation is accomplished through use of a pump 662, in example FIG. 6 so that the fluid moves into an evaluation chamber 660 for ultimate analysis.

After arriving in the evaluation chamber 660, for example, the sample may be pressurized or depressurized to identify the material constituents of the sample 1108. Chemical analyzers may be installed inside the evaluation chamber 660 such that the specific hydrocarbon being measured is ultimately identified. Temperature of the fluid may be taken, as well as viscosity and starting pressure of the fluid. As previously described, all analysis can be performed within the tool 610, 710, 810.

After analysis, a query can be taken if a tool orientation is desired to be taken 1110. The tool orientation may be useful to operators as they identify the approximate location of the sample for use in characterization studies to be performed. If the operator wishes to obtain a tool orientation 1110, the desired depth, axial inclination and radial orientation may be obtained 1112 by the tool 610, 710, 810 which is configured to measure these parameters. These parameters may also be continually fed back to the operator so that the operator is kept apprised of tool depth and status.

Next, after depressurization or pressurization of the sample accomplished in step 1108, the approximate volumes of the constituent fluids are calculated through equations of state for the hydrocarbon materials present, consequently each equation of state for each individual component is established. Thus, this method step determines at least one of a liquid formed from a gas below a dew curve and a gas formed beneath a bubble curve through use of sensors in the downhole tool 610, 710, 810.

The results of the evaluation may be provided to an operator 1116 so that the operator may take the results and act accordingly. The method may then be ended at step 1118.

The method describes a process for measuring a presence of a multi-phase system. The method may include the steps of positioning a downhole tool with a fluid analysis assembly in a well bore, extracting fluid from a surrounding geotechnical formation into the wellbore to an evaluation cavity of the fluid analysis assembly, wherein the drawing of the fluid is performed at formation environmental conditions and evaluating the fluid drawn from the surrounding geotechnical formation to determine a presence of a multi-phase system wherein the evaluating is performed to determine at least one of a liquid formed from a gas below a dew curve and a gas formed beneath a bubble curve.

In another example embodiment, a tool for sampling a subterranean formation is presented, the tool having a housing, a fluid communication device contained within the housing, the fluid communication device configured to be positioned on a wellbore opening, a fluid analysis assembly connected to the fluid communication device, wherein the fluid analysis assembly comprises a chamber to accept and hold a fluid delivered from the fluid communication device, a fluid movement device configured within the housing, the fluid moving device configured to apply a force to the fluid for transportation from the fluid communication device to the fluid analysis assembly and a tubular component connected to the chamber within the housing, the tubular component configured to determine at least one of a liquid formed from a gas below a dew curve and a gas formed beneath a bubble curve.

Through the foregoing description of components, a volume of liquid and gas in a two phase region may be determined. This volume computation of liquid and gas has the advantage of allowing operators and engineers the ability to properly characterize a geotechnical formation. Proper characterization allows appropriate recovery equipment to be established to remove hydrocarbons from the formation with a minimum of cost and delay.

The foregoing outlines features of several embodiments so that those skilled in the art may better understand the aspects of the disclosure. Those skilled in the art should appreciate that they may readily use the present disclosure as a basis for designing or modifying other processes and structures for carrying out the same purposes and/or achieving the same advantages of the embodiments introduced herein. Those skilled in the art should also realize that such equivalent constructions do not depart from the spirit and scope of the present disclosure, and that they may make various changes, substitutions and alterations herein without departing from the spirit and scope of the present disclosure.

The Abstract at the end of this disclosure is provided to comply with 37 C.F.R. §1.72(b) to allow the reader to quickly ascertain the nature of the technical disclosure. It is submitted with the understanding that it will not be used to interpret or limit the scope or meaning of the claims.

Claims

1. A method for measuring a presence of a multi-phase system, comprising:

positioning a downhole tool with a fluid analysis assembly in a well bore;

extracting fluid from a surrounding geotechnical formation into the wellbore to an evaluation cavity of the fluid analysis assembly, wherein the drawing of the fluid is performed at formation environmental conditions; and

evaluating the fluid drawn from the surrounding geotechnical formation to determine a presence of a multi-phase system wherein the evaluating is performed to determine at least one of a liquid formed from a gas below a dew curve and a gas formed beneath a bubble curve.

2. The method according to claim 1, wherein the evaluating of the fluid drawn from the surrounding geotechnical formation is conducted by at least one of acoustic and electromagnetic measurements during the sampling.

3. The method according to claim 1, further comprising:

determining a tool orientation of the fluid communication device prior to the evaluating of the fluid drawn from the surrounding geotechnical formation.

4. The method according to claim 1, wherein the evaluating the fluid drawn from the surrounding geotechnical formation to determine a presence of a multi-phase system is performed by at least one of acoustic and electromagnetic wave sensors.

5. The method according to claim 1, wherein the evaluating the fluid to determine the presence of a multi-phase system is accomplished at a specified temperature and pressure by an operator.

6. The method according to claim 1, further comprising:

providing results to an operator of the evaluation done on the fluid.

7. The method according to claim 1, wherein the evaluating the fluid drawn from the surrounding geotechnical formation to determine a presence of a multi-phase system further includes subjecting the fluid to a decreasing pressure.

8. The method according to claim 1, further comprising:

transporting the fluid from a point of the extracting of the fluid to a second point for the evaluating of the fluid.

9. The method according to claim 8, wherein the transporting of the fluid is accomplished through a pump actuated by an operator.

10. A tool for sampling a subterranean formation, comprising:

a housing;

a fluid communication device contained within the housing, the fluid communication device configured to be positioned on a wellbore opening;

a fluid analysis assembly connected to the fluid communication device, wherein the fluid analysis assembly comprises a chamber to accept and hold a fluid delivered from the fluid communication device;

a fluid movement device configured within the housing, the fluid moving device configured to apply a force to the fluid for transportation from the fluid communication device to the fluid analysis assembly; and

a tubular component connected to the chamber within the housing, the tubular component configured to determine at least one of a liquid formed from a gas below a dew curve and a gas formed beneath a bubble curve.

11. The tool according to claim 10, wherein the tubular component has at least one of an acoustic and an electromagnetic sensor.

12. The tool according to claim 10, wherein the tubular component comprises at least one liquid level sensor.

13. The tool according to claim 10, wherein the tubular component comprises at least two sensors, wherein at least one sensor is positioned at an alternating end of the tubular component compared to a first end.

14. The tool according to claim 10, wherein the fluid movement device is a pump.

15. The tool according to claim 10, further comprising:

at least one isolation valve to isolate the fluid analysis assembly from a remainder of the tool.

16. The tool according to claim 10, further comprising:

a communication device configured to interface with the fluid analysis assembly, wherein the communication device is configured to provide results from an analysis of the fluid to an operator.

17. The tool according to claim 16, wherein the communication device is configured to provide results to the operator by at least one of wireline and wireless communication technology.

18. The tool according to claim 10, further comprising:

at least one sensor configured to measure at least one of a density and a viscosity of the fluid in the tubular component connected to the chamber.

19. The tool according to claim 10, where the fluid analysis assembly connected to the fluid communication device comprises:

a signal processor configured to receive signals from the tubular component and process the signals for evaluation, the signal processor further configured to receive operator instructions and control at least one valve in the tool.

20. The tool according to claim 10, further comprising:

at least one control valve in the a fluid analysis assembly, the at least one control valve configured to isolate the fluid analysis assembly such that fluid does not escape from the assembly.