Evaluating multiphase fluid flow in a wellbore using temperature and pressure measurements   

FIELD OF THE INVENTION

This disclosure relates to evaluating fluid flow in an oil or gas well, and more particularly relates to a system and method of evaluating multiphase fluid flow in a wellbore using temperature and pressure measurements.

BACKGROUND OF THE INVENTION

Reliable and accurate downhole temperature and pressure measurements have been available in the petroleum industry for the past several years. Permanent downhole pressure monitoring equipment has now been installed in a number of producing basins around the world, with successful measurement operations exceeding five or more years at this time. Downhole permanent temperature measurements have also become more common, with both conventional or fiber optic thermal measurements currently available for most reservoir conditions. While continuous pressure and temperature readings provide an important part of understanding oil and gas production, quantitative information must typically be obtained using other types of data.

For example, the quantitative evaluation of the production or injection profile in an oil and/or gas well has traditionally involved the use of production log measurements of flow rate, pressure, density, and fluid holdup to derive estimates of the wellbore fluid mixture phase velocities, densities, pressure distributions, and completed interval inflow or outflow contributions. Modern production logs can be used in many situations to obtain the necessary measurements that are required to perform these quantitative computations. The measurements made in these cases however are periodic and reflect the wellbore fluid inflows/outflows at the time that the production log was run. Unfortunately, the known art does not provide a solution to obtain continuous or real-time quantitative measurements and evaluations using downhole pressure and temperature readings obtained from a plurality of sensors in the wellbore.

SUMMARY

The present invention relates to a system, method and program product that provides a computational model and evaluation technique for using array pressure and temperature measurements obtained in a flow conduit to evaluate the phase flow rates and velocities, fluid phase holdup, slip velocities between fluid phases, and mixture density and viscosity. These values can then be used, for instance, to quantify the inflow and outflow contributions of completed zones in a wellbore.

In one embodiment, there is a system for analyzing multiphase flow in a wellbore, comprising: an input system for receiving pressure and temperature readings from a pair of sensors located in the wellbore; a computation system that utilizes a flow analysis model to generate a set of wellbore fluid properties from the pressure and temperature readings, wherein the set of wellbore fluid properties includes at least one of: a fluid mixture value, a phase velocity value, a flow rate, a mixture density, a mixture viscosity, a fluid holdup, and a slip velocity; and a system for outputting the wellbore fluid properties.

In a second embodiment, there is a method for analyzing multiphase flow in a wellbore, comprising: obtaining pressure and temperature readings from a pair of sensors located in the wellbore; utilizing a flow analysis model to generate a set of wellbore fluid properties from the pressure and temperature readings, wherein the set of wellbore fluid properties includes at least one of: a fluid mixture value, a phase velocity value, a flow rate, a mixture density, a mixture viscosity, a fluid holdup, and a slip velocity; and outputting the wellbore fluid properties.

In a third embodiment, there is a computer readable medium for storing a computer program product, which when executed by a computer system analyzes multiphase flow in a wellbore, comprising: program code for inputting pressure and temperature readings from a pair of sensors located in the wellbore; program code for implementing a flow analysis model to generate a set of wellbore fluid properties from the pressure and temperature readings, wherein the set of wellbore fluid properties includes at least one of: a fluid mixture value, a phase velocity value, a flow rate, a mixture density, a mixture viscosity, a fluid holdup, and a slip velocity; and program code for outputting the wellbore fluid properties.

An advantage of this invention is the implementation of a quantitative evaluation methodology for characterizing the temperature, pressure, wellbore fluid mixture density and viscosity, and fluid holdup distributions in a wellbore using the temperature and pressure distributions in the well. This is achieved by the development and use of a comprehensive multiphase capillary flow analysis model. The results provide a reliable, accurate, and continuous characterization of the wellbore fluid flow properties such as pressure, temperature, mixture density, mixture viscosity, fluid phase holdup distributions, and completed zone inflow/outflow contributions.

This invention is directly applicable in wellbore environments and conditions in which modern production logging techniques may not be readily accessible or may not be deployable as a result of the wellbore geometry, well depth, water depth, or other operational and economical considerations.

The illustrative aspects of the present invention are designed to solve the problems herein described and other problems not discussed.

BRIEF DESCRIPTION OF THE DRAWINGS

These and other features of this invention will be more readily understood from the following detailed description of the various aspects of the invention taken in conjunction with the accompanying drawings.

FIG. 1 depicts a computer system having a multiphase flow analysis system in accordance with an embodiment of the present invention.

FIG. 2 depicts an embodiment of a multiphase flow analysis system that provides a contribution analysis in accordance with an embodiment of the present invention.

FIG. 3 depicts a graph showing a Fanning friction factor correlated with the Reynolds number and relative roughness for single-phase flow systems.

FIG. 4 depicts a graph showing a friction factor showing the transition between the laminar and turbulent flow regimes in multiphase flow systems.

The drawings are merely schematic representations, not intended to portray specific parameters of the invention. The drawings are intended to depict only typical embodiments of the invention, and therefore should not be considered as limiting the scope of the invention. In the drawings, like numbering represents like elements.

DETAILED DESCRIPTION

Referring to the drawings, FIG. 1 depicts an overview of an illustrative system 11 for implementing aspects of the present invention. As shown, a computer system 10 is provided that includes a multiphase flow analysis system 18 for analyzing fluid characteristics flowing through a wellbore 34. Also provided are at least two sensors 30, 32 placed within the wellbore to provide multipoint pressure and temperature readings.

Multiphase flow analysis system 18 includes a pressure and temperature input system 20 for obtaining pressure and temperature readings from each sensor 30, 32 in a continuous, as needed, or periodic manner. Also included is a computation system 22 that utilizes a flow analysis model 24 for computing wellbore fluid properties, including one or more of: (1) the fluid mixture; (2) phase velocities; (3) flow rates; (4) mixture density; (5) mixture viscosity; (6) fluid holdups; and (7) estimates of the slip velocities between the wellbore liquid and gas phases and between the oil and water phases, if those phases are present in the system. Wellbore fluid properties 28 may be computed and outputted by output system 29 in an “on-demand” manner, i.e., continuously, as needed, periodically, in real-time, etc. It is also possible to output the wellbore fluid properties when pre-selected system conditions are reached, such as anomalous incidents or trends, conditions exceeding thresholds, etc. A description of the flow analysis model 24 and how the computations may be implemented is provided below.

Also included in multiphase flow analysis system 18 is a contribution analysis system 26 to quantitatively evaluate an oil or gas well with multiple production or injection zones. For example, FIG. 2 depicts a well 50 having multiple production zones that include a main branch 42, a first contribution branch 44, and a second contribution branch 46. In this case, multipoint measurements are obtained with sets of sensors configured into a multipoint measurements array. In particular, the complex multi-branched well 50 is fitted with three sets of sensors (A, B, and C). Each set is strategically located to obtain contribution readings from each different zone in the well. Namely, sensor set C is located to obtain readings for main branch 42; sensor set B is located to obtain contribution readings from main branch 42 and first contribution branch 44; and sensor set A is located to obtain contribution readings from main branch 42, first contribution branch 44, and second contribution branch 46.

A contribution analysis 40 may be obtained for each contribution branch 44, 46 by subtracting all the downstream fluid property computations. For instance, by subtracting computation values obtained from sensor set C from computation values obtained from sensor set B, a contribution analysis 40 for the first contribution branch 44 can be obtained. Similarly, by subtracting computation values obtained from sensor sets B and C from computation values obtained from sensor set A, a contribution analysis 40 for the second contribution branch 46 can be obtained. Contribution analysis 40 for main branch 42 is simply obtained from sensor set C, which has no additional downstream contributions.

Note that each sensor set A, B, C may include more than two sensors in order to provide redundancy. In this example, each set is shown including four sensors, e.g., set A includes sensors A1, A2, A3, and A4. This thus allows six different sensor pairs (e.g., A1-A2, A1-A3, A1-A4, A2-A3, A2-A4, A3-A4) to be used as a basis calculating wellbore fluid properties. Any one or more of the sensor pairs may be used for evaluation purposes. While FIG. 2 depicts a well that has a main branch and first and second contribution branches, embodiments of the invention may also be used with a wellbore having only a main branch with different inflow or outflow zones, such as a cased well having separate perforated intervals.

As noted in FIG. 1, computation system 22 provides a flow analysis model 24 for generating wellbore fluid properties 28 for a sensor pair 30, 32. An explanation for how such properties may be obtained from temperature and pressure readings from sensor pair 30, 32 begins with a review of the fundamental governing relationships that pertain to multiphase fluid flow in a tubular conduit (e.g., a wellbore). The following notation is used throughout the discussion.

D Flow conduit inside diameter f Fanning friction factor fo Fraction of oil in liquid component of the system fw Fraction of water in liquid component of the system g Gravitational acceleration HL Liquid holdup hL Elevation at end of flow conduit segment h0 Elevation at start of flow conduit segment L Measured length of the flow conduit segment NRe Reynolds number PL Pressure at outlet end of flow conduit segment P0 Pressure at start end of flow conduit segment qg Insitu gas volumetric flow rate qL Insitu liquid volumetric flow rate V Fluid average velocity in circular conduit Vm Wellbore fluid mixture superficial velocity, ft/s Vsg Gas superficial velocity, ft/s VsgL Gas-liquid slip velocity, ft/s VsL Liquid superficial velocity, ft/s Vso Oil superficial velocity, ft/s Vsow Oil-water slip velocity, ft/s Vsw Water superficial velocity, ft/s Yg Gas holdup YL Liquid holdup Yo Oil holdup Yw Water holdup

α Wellbore deviation angle from vertical, deg ε Pipe roughness λL No-slip liquid holdup μg Gas dynamic viscosity, cp μL Liquid dynamic viscosity, cp μm Fluid mixture dynamic viscosity, cp μo Oil dynamic viscosity, cp μw Water dynamic viscosity, cp υm Fluid mixture kinematic viscosity, cp-cu ft/lbs ρg Gas density, lbs/cu ft ρL Liquid density, lbs/cu ft ρm Fluid mixture density, lbs/cu ft ρo Oil density, lbs/cu ft ρosg Oil density, g/cc ρw Water density, lbs/cu ft ρwsg Water density, g/cc

One of the fundamental parameters that can be used to quantify and correlate the level of inertial to viscous forces in a fluid flowing in a circular conduit is the Reynolds number. This dimensionless parameter is defined in Eq. 1.

N Re = DV m υ m ( 1 )

The kinematic viscosity of a fluid mixture appearing in Eq. 1 is defined as the ratio of the dynamic fluid viscosity to its density. This relationship is expressed mathematically in Eq. 2.

υ m = μ m ρ m ( 2 )

The general relationship that describes the pressure loss exhibited due to fluid flow in a circular tubular conduit is given by Fanning\'s equation. Note that gravitational effects have been included in this expression.

P 0 - P L + ρ m  g  ( h 0 - h L ) L = 2  ρ m  fV m 2 D ( 3 )

Substitution of Eqs. 2 and 3 into Eq. 1 results in expression that can be used to correlate the Reynolds number and friction factor to the conduit dimensions, the pressure loss over a given length of conduit, and the physical properties of the fluid flowing in the conduit. Note that the relationship given in Eq. 4 is explicitly independent of the fluid velocity, except that the effect of this parameter is implicitly manifested in the fluid flow problem in the form of the Reynolds number.

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