Apparatus and Method for Generating Steam Quality Delivered to A Reservoir

Abstract

Methods and apparatuses for determining the steam quality at a subsurface location for a steam injection operation. The methods involve obtaining a total mass flow rate, measuring a vapor velocity at the subsurface location and a second parameter, determining a vapor density from the second parameter when the second parameter comprises a measurement other than a vapor density, generating a vapor mass flow rate as a function of the vapor velocity, the vapor density and the internal cross-section area of the conduit, and generating the steam quality at the subsurface location as a function of the vapor mass flow rate and the total mass flow rate.

Description

BACKGROUND

Steam injection is a technique that may be used in oilfield operations to stimulate production of hydrocarbons from subsurface reservoirs. During steam injection, it may be useful to know the quantity of steam injected into the reservoir, as well as a measurement of the quality of steam reaching the reservoir. The steam quality may be defined as a ratio of mass of vapor to total mass of both vapor and liquid.

Steam flooding is a form of steam injection that may be used to inject steam into a reservoir to drive hydrocarbons from the reservoir. Steam injection may be used, for example, in heavy oil reservoirs to raise oil temperature thereby reducing oil viscosity and facilitating oil extraction at rates that may be greater than those that can be achieved at natural geothermal temperatures. While a degree of heat loss to non-oil-bearing formations can be tolerated, a plan for production may include an optimal steam quality reaching the reservoir. Steam quality monitoring can be performed at surface for example at the wellhead, but the steam quality reaching the reservoir may be dependent on modeled thermal losses in the wellbore.

During injection, the steam may change phase to water as the steam travels downhole from the surface, and releases heat to the surroundings on its way downhole. While a degree of heat loss to non-oilbearing formations may be tolerated, steam with sufficient quality may be used to reach some reservoirs. It may, therefore, be useful to have knowledge of steam quality at a subsurface location that reaches the reservoir. Attempts at measuring parameters relating to steam quality have been made as described, for example, in U.S. Pat. No. 5,509,478, U.S. Pat. No. 4,836,032, and U.S. Pat. No. 4,681,466.

SUMMARY

This summary is provided to introduce a selection of concepts that are further described below in the detailed description. This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of the claimed subject matter.

In an embodiment, a method is disclosed for determining a steam quality at a subsurface location for a steam injection operation wherein the internal cross-section area of a conduit supplying the steam is a known dimension. The method may include obtaining a total mass flow rate of the steam. The method may include measuring a vapor velocity at the subsurface location and measuring a second parameter. The method may include determining a vapor density from the second parameter when the second parameter comprises a measurement other than a vapor density. The method may include generating the vapor mass flow rate as a function of the vapor velocity, the vapor density and the internal cross-section area of the conduit. The method may include generating the steam quality at the subsurface location as a function of the vapor mass flow rate and the total mass flow rate.

In an embodiment, an apparatus is disclosed for determining steam quality in a steam injection operation in an oil field. The apparatus may include a steam conduit that supplies wet steam, wherein a cross-section area of the steam conduit is a known dimension. The apparatus may include a steam injector that injects steam into a reservoir. The method may include a vapor flow meter that measures a vapor velocity within the steam conduit. The apparatus may include a second sensor that measures a second parameter within the steam conduit. The apparatus may include a controller that determines a vapor density from the second parameter when the second parameter comprises a measurement other than a vapor density, generates the vapor mass flow rate as a function of the vapor velocity, the vapor density and the internal cross-section area of the conduit; and generates the steam quality at the subsurface location as a function of the vapor mass flow rate and the total mass flow rate. The apparatus may include a user interface that may accept adjustments to steam injection operation based on the steam quality.

BRIEF DESCRIPTION OF DRAWINGS

Embodiments of this disclosure are described with reference to the following figures. The same numbers are used throughout the figures to reference like features and components. A better understanding of the methods or apparatuses can be had when the following detailed description of the several embodiments is considered in conjunction with the following drawings, in which:

FIG. 1 is a schematic diagram showing an example of a wellsite for a production well.

FIG. 2 shows a schematic of a production logging tool such as may be used in an embodiment of the present disclosure.

FIG. 3 shows a flow diagram of one example method in which embodiments of this disclosure can be implemented.

FIG. 3 shows a Phase Diagram Map for Water that may be generated in accordance with at least one embodiment of the present disclosure.

FIG. 5 shows an International Steam Table chart.

FIG. 6 shows multispeed spinner calibration chart in accordance with some embodiments of the present disclosure.

FIG. 7 shows a computer system by which methods disclosed can be implemented.

DETAILED DESCRIPTION

In the following description, numerous details are set forth to provide an understanding of the present disclosure. However, it will be understood by those skilled in the art that the present disclosure may be practiced without these details and that numerous variations or modifications from the described embodiments are possible.

The present disclosure relates to methods and apparatuses for determining the quality of a steam delivered to a subterranean formation via a wellbore in a steam flooding operation. In the methods and apparatuses described herein, a total mass flow rate of steam supplied to the wellbore can be measured by any suitable technology. A spinner velocity from the surface to a top of the formation subject to the steam flooding operation can first be calculated. In an embodiment, the “top” of the formation subject to the steam flooding operation may be defined by the location of the first perforation. In various embodiments, the flow regime may be assumed to be annular, and thus the spinner velocity may be driven by the steam velocity. Employing pressure, temperature, or a combination of pressure and temperature, steam density can be computed over the length of the well. From the steam density, steam velocity and an internal cross sectional area of the conduit in which the steam flows (i.e., a pipe), a steam mass flow rate can then be calculated from surface to the top of the formation. The steam quality at a given depth can then be computed as the steam mass flow rate divided by the total mass flow rate. Superficial velocities of water and steam along the length of the well may be plotted on a flow regime map to determine whether annular flow is present.

FIG. 1 schematically illustrates a steam injection well containing devices for a steam injection operation at a rig 101. The well is lined with a casing 105. At the surface, a downhole tool 104 (e.g., a production logging tool, a flow scanner or other downhole tool) can be inserted with a cable 103. The well casing 105 has a pipe 106 contained therein. The downhole tool 104 is shown in a position at the surface and in the pipe 106 near the top of a reservoir 11. Perforations 108 at a lower portion of the well casing 105 can provide direct fluid communication between the pipe 106 and a subterranean formation.

An injection point P located (in situ) near the bottom of casing 105 or pipe 106 is where injected steam leaves steam injecting conduit pipe 106 and enters subterranean formation and perforation 108. Point P is also where measurements can be performed to calculate steam quality using methods described in this application.

Packer 107 can provide pressure isolation between the annuluses of casing 105 and pipe 106 and any steam inside the pipe 106. A pressurized steam may be supplied from a steam supply 109 to a steam pipe 110. A meter 102, such as a flowmeter, can be used to measure total mass flow rate (M). Additional repetitive measurements may be optional. Therefore, measurements can be obtained easily and accurately with little interference to normal oilfield operation or steam injection operation. Optionally, some metering techniques may include the use of orifice plates and venturi meters and other suitable technologies. The meter 102 can be situated either adjacent to the wellhead, adjacent to the steam supply 109 or at any place there between. The meter 102 and/or steam pipe 110 may also have various sensors for measuring various parameters, such as temperature, pressure, etc.

The cable 103 is attached to a production logging tool 104. The cable 103 can be an electrical wireline for surface readout or a slickline for memory logging. If a turbine flow meter (or vapor flow meter) is used, the production logging tool 104 may contain at least one turbine flow meter whose angular velocity (ω) can be processed to deliver an apparent fluid velocity. The production logging tool 104 may also contain a second meter, a device for measuring pressure, a device for measuring temperature, a device for measuring vapor density or a combination of them among other instruments. Pressure or temperature sensors may also be embedded at various locations within the pipe 106 where routine temperatures/pressures are continuously monitored.

Flow inside the pipe 106 may contain water liquid and water vapor. For a two-phase gas/liquid flow, there may be a number of flow regimes. These flow regimes can include, for example, bubble flow, slug flow, froth flow, annular flow, dispersed bubble flow, and the like. For commercial steam injection operations, the volumetric liquid fraction can be around 1%, while the density of the liquid can be around 100 times greater than the vapor. The flow regime may be, for example, annular flow. Whether or not the flow regime in tubing 106 is annular can be verified once the superficial liquid velocity is determined, and compared with a Flow Pattern Map (to be discussed further below) or based on a known relationship.

A surface control unit 150 having various data storage and processors may be connected to various controllers, tools and sensors to control and adjust various parts of the steam injection operation as will be described further herein with respect to FIG. 7. The processor may be used to determine the steam quality from the measurements received from various meters using one of the methods described in this application. Depending on the steam quality, the surface control unit 150 can instruct the master controller or various controllers to adjust relevant parts of the steam injection operation. Alternatively, the surface control unit 150 may display the steam quality as one of the operation parameters so that an operator may take actions manually to adjust the steam operation.

FIG. 2 shows additional detail of the production logging tool 104 of FIG. 1 with a spinner 200 positioned in place via a centralizer cage 205. Spinner 200 may be a device for measuring in-situ a velocity of fluid flow in a production or injection well based on the speed of rotation of an impeller. In some embodiments, the spinner can be helical, that is, longer than it is wide, or like a vane which is similar to a fan blade. In either case, the speed of rotation may be measured and related to the effective velocity of the fluid.

FIG. 3 illustrates a flow diagram of one method 300 for determining steam quality at a subsurface location for a steam injection operation. This method 300 may be used, for example, to determine steam quality in the systems as shown in FIGS. 1 and 2. Some of the operational parameters may be known at the outset of the operation, e.g. the size (the diameter and/or the cross-section area) of the steam injecting pipe. Some of the operation parameters (e.g. the total mass flow rate of the supplied steam) may be known or obtained at other time (e.g. during the operation).

The method involves several determining various steam variables, which will be introduced here and described further below. At 310, a total mass flow rate of the supplied steam may be obtained. In an embodiment, the total mass flow rate may be obtained from a steam supplier or from a meter at surface. At 320, a vapor velocity at a subsurface location may be measured. In an embodiment velocity may be measured by various tools such as PSP™, a Doppler flow meter, a heated anemometer, or an optical flow meter. At 330, a second parameter may be measured. In an embodiment, the second parameter may be one of pressure, temperature, or vapor density. At 340, a vapor density may be determined from the second parameter, when the measured second parameter is not a vapor density. At 345, a vapor mass flow rate may be generated as product of the vapor velocity, the vapor density and the internal cross-section area of the pipe. Optionally, a velocity profile correction factor may also be applied to the vapor mass flow rate. At 350, a steam quality at the subsurface location may be generated by dividing a vapor mass flow rate with the total mass flow rate at 310. A spinner calibration 360 may also optionally be performed.

Many steps listed above may be modified. The sequence of steps listed is for convenience, not necessarily performed in that order. For example, steps 310, 320 and 330 are listed in one sequence, but they can be performed in any sequence, e.g. perform the three steps in order of 330, 320 and 310; or e.g. the three steps are performed at simultaneously. One or more of the steps may be repeated. Referring back to FIG. 1, a surface control unit 150 may be in communication with the production logging tool 104 (via the wireline or other telemetry device) for receiving the data acquired. Various computer systems and processors at either the surface control unit 150 and/or logging tool 104, or distributed between the two, may be used to interpret the data to determine, for example, the steam quantity and steam quality in the well. Steam quality may be determined based on one or more of the following variables:

E=energy in kJ

h″₂₀₀=the enthalpy of steam vapor at 200 deg C. in kJ/kg

h′₂₀₀=the enthalpy of water at 200 deg C. in kJ/kg

h′₁₀₀=the enthalpy of water at 100 deg C. in kJ/kg

m=mass in kg, subscript _vapor for vapor, _liquid for liquid

m_vapor=mass of water vapor

m_liquid=mass of liquid water

Q=steam quality

ν_vapor=velocity of water vapor

ν_liquid=velocity of liquid water

ν_app=spinner velocity, apparent velocity

offset=spinner offset

k=spinner slope

ω₁=turbine flow meter RPS (revolutions per second)

F_vpc=spinner correction factor

F_vpr=velocity profile correction factor

A=area of internal cross-section of steam conduit

d_pipe=internal diameter of the pipe

δ_vapor=density of water vapor

δ_liquid=density of liquid water

Y_vapor=holdup of water vapor

Y_liquid=holdup of liquid water

p_vapor=steam pressure

T_vapor=steam temperature

w_vapor=mass flow rate of water vapor

w_liquid=mass flow rate of liquid water

w_total=mass flow rate of liquid and vapor entering the well

q_liquid=flow rate of liquid water

ν_sup—liquid=superficial velocity of liquid water

ν_gas=superficial gas velocity

The steam quality can be determined as the ratio of the mass of vapor to the total mass of vapor and liquid:

$\begin{array}{cc}Q=\frac{m_{\mathrm{vapor}}}{m_{\mathrm{vapor}}+m_{\mathrm{liquid}}}& \mathrm{Eq}.1\end{array}$

The above equation can be rewritten in terms of measurable quantities as:

$\begin{array}{cc}Q=\frac{Y_{\mathrm{vapor}}\times p_{\mathrm{vapor}}}{Y_{\mathrm{vapor}}\times p_{\mathrm{vapor}}+Y_{\mathrm{liquid}}\times p_{\mathrm{liquid}}}& \mathrm{Eq}.2\end{array}$

Eq. 2 may be rewritten as:

$\begin{array}{cc}Q=\frac{Y_{\mathrm{vapor}}\times p_{\mathrm{vapor}}\times v_{\mathrm{vapor}}}{Y_{\mathrm{vapor}}\times p_{\mathrm{vapor}}\times v_{\mathrm{vapor}}+Y_{\mathrm{liquid}}\times p_{\mathrm{liquid}}\times v_{\mathrm{liquid}}}& \mathrm{Eq}.3\end{array}$

In steam injection operations, the flow regime in a steam conduit may be annular in the center of the conduit with a thin film of water on the conduit wall. One way to determine whether the flow scheme is within annular flow is to analyze the superficial velocity of vapor and liquid within the pipe using a Flow Pattern Map 400, as shown in FIG. 4. In the Flow Pattern Map 400, the horizontal axis is superficial gas velocity (v_gas) and the vertical axis is the superficial liquid velocity (v_{sup—liquids}). As shown in this map 400, the symbol “A” is for annular flow; I is for intermittent flow; and DB is for Dispersed Bubble. Although a flow pattern depends on both gas velocity and liquid velocity, for at least some steam injection operations, the liquid velocity may be needed to determine a flow pattern. When the superficial liquid velocity is less than about 0.60 m/s, the flow pattern remains in annular flow, regardless of the superficial vapor velocity. In some embodiments, ν_sup—liquid is less than about 0.60 m/s for annular flow.

In cases of annular flow, the spinner disposed in the pipe may be used to record core vapor velocity ν_vapor (see, e.g., 205 of FIG. 2). In an embodiment, the spinner may be centered in the pipe for the purpose of recording the core vapor velocity. In a given steam injection operation, the liquid water holdup may be as low as about a few percent. In such cases, the cross-section of the pipe may be occupied by flowing vapor. Therefore, the vapor flow rate q_vapor may be governed by the following equations:

$\begin{array}{cc}{q}_{\mathrm{vapor}}=v_{\mathrm{vapor}}\times A& \mathrm{Eq}.4\\ q_{\mathrm{vapor}}=v_{\mathrm{vapor}}\times v_{\mathrm{vapor}}\times \frac{\pi \times d_{\mathrm{pipe}}^2}{4}& \mathrm{Eq}.5\\ q_{\mathrm{vapor}}=v_{\mathrm{app}}\times F_{\mathrm{vpc}}\times A& \mathrm{Eq}.6\\ q_{\mathrm{vapor}}=v_{\mathrm{app}}\times F_{\mathrm{vpc}}\times \frac{\pi \times d_{\mathrm{pipe}}^2}{4}& \mathrm{Eq}.7\end{array}$

Eq. 4 may be used when vapor velocity (ν_vapor) is measured. When a turbine spinner (e.g., 205 of FIG. 2) is used to measure flow velocity, the apparent vapor velocity may be obtained. The apparent vapor velocity may be converted to actual vapor velocity via a spinner correction factor F_vpc using Eq. 6. In some cases, the steam conduit may be a pipe whose internal diameter is known. In such cases, the area of the internal cross-section may be the area of a circle:

$\frac{\pi \times d_{\mathrm{pipe}}^2}{4},$

instead of cross-section areas as used in Eq. 5 and Eq. 7 above.

The actual vapor velocity may not be proportional to the spinner revolutions per second (“RPS”). The relationship between the spinner RPS and velocity may be governed by the following equation:

ν_vapor=(ω₁×k+offset)×F_vpc  Eq. 8

Slope k and offset are two empirical factors of a spinner. The three spinner factors (F_vpr, k, and offset) may change with respect to locations in the steam conduit and other operating conditions. An in-situ multi-speed turbine calibration may be performed when a turbine flow meter is used in a well, as discussed below. F_vpr is a velocity profile correction factor related to a turbine flow meter in an oil, gas or water injected well. F_vpr may also be used in a steam injected well. The value of F_vpr may range from about 0.80 to about 0.85, but may vary and depend on many conditions, including casing/conduit size, fluid viscosity, spinner blade size, spinner surface roughness, mechanical friction on the spinner pivots, etc. In some embodiments, two of the spinner factors F_vpr and offset may be negligible and omitted. In some other embodiments, errors due to neglecting F_vpr and offset may surpass a threshold and thus may not be omitted from the calculation.

In some operations, commercial steam injection may use saturated steam that may be water vapor in equilibrium with liquid water. In such equilibrium, a saturated steam line S in an International Steam Table provides an established relationship between pressure and temperature that extends from the triple point T (which may be defined as the particular pressure and temperature at which the three phases of water can coexist in equilibrium, that is at 273.16K and 611.73 Pa) to the critical point (which may be defined as the particular pressure and temperature whether the phase boundary ceases to exist, that is, at 647K and 22.064 MPa) as shown in FIG. 5. Therefore, a steam injection production logging tool string can acquire either a pressure measurement or a temperature measurement to determine an operating point on the saturated steam line.

A density of liquid water and a density of water vapor can be determined from either the pressure or the temperature using polynomial expressions from the International Steam Tables as shown in FIG. 5. The vapor density (ρ_vapor) can also be expressed in a polynomial. One such expression contains 34 terms, for simplicity, it is expressed as:

ρ_vapor=f(p_vapor) or ρ_vapor=f(T_vapor)  Eq. 9

The mass flow rate (w_vapor) of vapor may then be defined as:

$\begin{array}{cc}{w}_{\mathrm{vapor}}=v_{\mathrm{vapor}}\times A\times f\left(p_{\mathrm{vapor}}\right)\mathrm{or}& \mathrm{Eq}.10\\ w_{\mathrm{vapor}}=v_{\mathrm{appp}}\times F_{\mathrm{vpc}}\times \frac{\pi \times d_{\mathrm{pipe}}^2}{4}\times f\left(p_{\mathrm{vapor}}\right)& \mathrm{Eq}.11\end{array}$

The total mass flow rate of both vapor and liquid going into the well (w_total) may be known, e.g. obtained as a known total from the steam supplier. Due to mass conservation law, the total mass flow rate may be the same throughout the steam injection conduit, at surface or subsurface. If the total mass flow rate is unknown, the total mass flow rate can also be measured at the surface. In some embodiments, a total mass flow rate may be measured at a subsurface location in a well by a choke meter. In some embodiments, subsurface measurement of total mass flow rate may be unnecessary and omitted. Thus, the steam quality at any depth above the top perforation may be governed by;

$\begin{array}{cc}Q=\frac{w_{\mathrm{vapor}}}{w_{\mathrm{total}}}& \mathrm{Eq}.12\end{array}$

From the steam quality governed by Eq. 12, the liquid superficial velocity, liquid volumetric flow, and liquid mass flow can also be calculated:

$\begin{array}{cc}{v}_{{\sup }_{\mathrm{liquid}}}=\frac{q_{\mathrm{liquid}}}{A}& \mathrm{Eq}.13\\ q_{\mathrm{liquid}}=\frac{w_{\mathrm{liquid}}}{p_{\mathrm{liquid}}}& \mathrm{Eq}.14\\ w_{\mathrm{liquid}}=\left(1-Q\right)\times w_{\mathrm{total}}& \mathrm{Eq}.15\end{array}$

Using any one of the above equations, the vapor mass flow rate can be obtained from the measurement of a vapor velocity and a second parameter, which can be a temperature or a pressure, or the vapor density itself. Therefore, the steam quality may be determined.

In using some of the above equations, such as Eq. 4, Eq. 11, etc., it may be assumed that the steam flow is annular flow. When the steam flow pattern inside a pipe is not annular flow, however, the lack of annular flow may be an indication that there are problems with the steam injection operation. Operators may be able to locate and adjust for the problem before continuing steam injection operations.

There are many ways to measure vapor velocity within a steam injection conduit, e.g., a tubing or a pipe. Wherever the vapor velocity and a second parameter, such as a temperature, a pressure or a vapor density are measured, then the steam quality at that location can be determined. Logging tools (e.g., Production Services Platform, PSP™) may be used in production logging tool 104 to measure multiphase fluid velocity, temperature, and pressure, among other properties, or any suitable velocity measurement techniques, for example, by a Doppler flow meter, a heated anemometer, or an Optical flow meter. By using such logging tools, one can obtain measurements that can be used to determine steam quality at various downhole locations, for example at various locations between the wellhead and the manifold where steam is injected into a perforation. The steam qualities at many different locations along a well can be determined and a steam quality profile can be generated. A steam quality profile can be used in managing a steam injection operation.

The second parameter, which can be a temperature, a pressure or a vapor density, can also be measured by various suitable techniques, such as logging tools or from embedded sensors within the pipe or the wellbore casing.

In one implementation, a temperature, as the second parameter, is measured. From the measured temperature, using the vapor density expression as in Eq. 9 the corresponding vapor density is obtained. Alternatively, the steam density can also be obtained from a standard steam table as in FIG. 5. Once the vapor density, vapor velocity and total steam mass flow are known, the steam quality can be calculated, e.g. using Eq. 12.

In another implementation, a pressure, as the second parameter, is measured. From the measured pressure, using the vapor density expression as in Eq. 9 the corresponding vapor density is obtained. Similarly, once the vapor density, vapor velocity and total steam mass flow are known, the steam quality can be calculated, e.g. using Eq. 12.

In another implementation, a vapor density, as the second parameter, is measured. From the measured vapor density, the measured vapor velocity and the known total steam mass flow, the steam quality can be calculated, e.g. using Eq. 12.

To ensure that steam injection operation is operating properly, e.g. that the steam flow regime in the pipe 106 is annular flow, the liquid superficial velocity can be calculated. With the liquid superficial velocity and the vapor superficial velocity, the flow regime can be determined using a flow pattern chart (e.g., the chart shown in FIG. 5). If the liquid superficial velocity is too large, e.g. is above the annular flow threshold, then an error sign is raised. The operation may be halted until a problem is located or resolved.

In some cases, calibration of the spinner (e.g., 200 of FIG. 2) may be desired, for example, to eliminate potential error in the generated steam quality. With a turbine flow meter, the spinner's angular velocity may be used to indicate the velocity of the fluid passing through the spinner. The relationship may not, however, be proportional. The relationship may be represented by Eq. 8 as discussed earlier. The spinner may need to be calibrated in order to provide an accurate and reliable measurement of a fluid velocity.

In some implementations, a multispeed turbine flow meter calibration can be performed near the lower end of pipe 106 and just above the perforations 108. In some implementations, a continuous calibration over the entire length of pipe 106 and down to the top of the first open perforation 8 can be performed. The multispeed calibration can be converted to an apparent velocity (ν_app).

FIG. 6 shows a multispeed spinner calibration chart 600 that may be used for calibrating a turbine flow meter, e.g. a PSP™. The chart of FIG. 6 takes into account that the positive spinner slope, spinner threshold and the velocity profile correction factor can change with depth. The x-axis depicts cable velocity and the y-axis depicts spinner velocity in revolutions per second (RPS).

The chart 600 plots a line 611 describing movement of the spinner 205 along cable 103 (see FIGS. 1 and 2). When the cable 103 moves upward against the steam flow, the spinner RPS increases at a rate proportional to the velocity of the cable motion. When the cable moves down, the spinner RPS decreases until the spinner stops spinning. As shown in FIG. 6, the spinner velocity may have two thresholds: one positive threshold (+) and one negative threshold (−). Between the two thresholds, the spinner RPS reading is zero, but the relative speed between the cable and the steam flow is about zero. The cable velocity also has a positive threshold (+) and a negative threshold (−). By applying a spinner calibration, a more accurate reading of the vapor velocity can be obtained.

In an example operation, a well is injected with wet steam with a mass flow rate of 0.16 kg/s. A calibrated turbine flow meter at the tubing top delivers a V_app of 5.7 m/s. From a pressure reading of 12.7 bar, a steam density of 6.6 kg/m³ is determined. The tubing has an internal diameter of 2.95″ (74.93 mm) giving an internal flowing area of 0.0044 m². Given a gas F_vpc value of 0.85, the steam mass flow rate may be calculated using Equation 11 to generate 0.14 kg/s (=5.7*0.85*0.0044*6.6). The corresponding steam quality based on Equation 12 is 88% (=0.14/0.16). In this case the liquid mass flow rate is known as 0.02 kg/s. The liquid superficial velocity may be determined using Equation 15 to be: (1-88%)*0.16 kg/s/(876 kg/m³)/0.0044 m²=5.0×10⁻³ m/s. Based on the Flow Pattern Map of FIG. 4, this calculation indicates that the well is within the annular flow regime.

In another example operation, a well is injected with wet steam with a mass flow rate of 0.16 kg/s. A calibrated turbine flow meter at the tubing bottom delivers a V_app of 6.1 m/s. From a pressure reading of 11.3 bars (11.52 kg/cm²) and using Equation 9, a steam density of 5.9 kg/m³ is determined. The tubing has an internal diameter of 2.95″ (74.93 mm) giving an internal flowing area of 0.0044 m². Taking a light gas F_vpc value of 0.85, the steam mass flow rate is calculated as 0.135 kg/s (=6.1*0.85*0.0044*5.9) using Equation 11. A corresponding steam quality of 84% (=0.135/0.16) may be determined using Equation 12. The liquid superficial velocity is about 5.6×10⁻³ m/s, again within the annular flow regime.

As those with skill in the art will understand, one or more of the steps of methods discussed above may be combined and/or the order of some operations may be changed. Further, some operations in methods may be combined with aspects of other example embodiments disclosed herein, and/or the order of some operations may be changed. The process of measurement, its interpretation and actions taken by operators may be done in an iterative fashion; this concept is applicable to the methods discussed herein. Finally, portions of methods may be performed by any suitable techniques, including on an automated or semi-automated basis on a computing system, such as the system 700 in FIG. 7, usable with or as part of the surface unit 150 of FIG. 1.

FIG. 7 depicts a computer system 700 including a system computer 730 that may be in communication with disk storage devices 729, 731, 733 and 735, which may be external hard disk storage devices and measurement sensors (not shown). It is contemplated that disk storage devices 729, 731, 733 and 735 may be conventional hard disk drives, and as such, may be implemented by way of a local area network or by remote access. While disk storage devices are illustrated as separate devices, a single disk storage device may be used to store any and all of the program instructions, measurement data, and results as desired.

In one implementation, petroleum real-time data from sensors at the wellsite may be stored in disk storage device 731. Various data, such as non-real-time data, from different sources may be stored in disk storage device 733. The system computer 730 may retrieve the appropriate data from the disk storage devices 731 or 733 to process data according to program instructions that correspond to implementations of various techniques described herein. The program instructions may be written in a computer programming language, such as C++, Java and the like. The program instructions may be stored in a computer-readable medium, such as program disk storage device 635. Such computer-readable media may include computer storage media. Computer storage media may include volatile and non-volatile, and removable and non-removable media implemented in any method or technology for storage of information, such as computer-readable instructions, data structures, program modules or other data. Computer storage media may further include RAM, ROM, erasable programmable read-only memory (EPROM), electrically erasable programmable read-only memory (EEPROM), flash memory or other solid state memory technology, CD-ROM, digital versatile disks (DVD), or other optical storage, magnetic cassettes, magnetic tape, magnetic disk storage or other magnetic storage devices, or any other medium which can be used to store the desired information and which can be accessed by the system computer 730. Combinations of any of the above may also be included within the scope of computer readable media.

In one implementation, the system computer 730 may present output primarily onto graphics display 727, or alternatively via printer (not shown). The output from computer 730 may also be used to control instruments within the steam injection operation. The system computer 730 may store the results of the methods described above on disk storage 729 for later use and further analysis. The keyboard 726 and the pointing device (e.g., a mouse, trackball, or the like) 725 may be provided with the system computer 730 to enable interactive operation.

The system computer 730 may be located on-site near the well as the surface control unit 150 of FIG. 1, or at a data center remote from the field. The system computer 730 may be in communication with equipment on site to receive data of various measurements. Such data, after conventional formatting and other initial processing, may be stored by the system computer 730 as digital data in the disk storage 731 or 733 for subsequent retrieval and processing in the manner described above.

While FIG. 7 illustrates the disk storage, e.g. 731 as directly connected to the system computer 730, it is also contemplated that the disk storage device may be accessible through a local area network or by remote access. Furthermore, while disk storage devices 729, 731 are illustrated as separate devices for storing input petroleum data and analysis results, the disk storage devices 729, 731 may be implemented within a single disk drive (either together with or separately from program disk storage device 733), or in any other conventional manner as will be fully understood by one of skill in the art having reference to this specification.

Although only a few example embodiments have been described in detail above, those skilled in the art will readily appreciate that many modifications are possible in the example embodiments without materially departing from this invention. Accordingly, all such modifications are intended to be included within the scope of this disclosure as defined in the following claims. In the claims, means-plus-function clauses are intended to cover the structures described herein as performing the recited function and not only structural equivalents, but also equivalent structures. Thus, although a nail and a screw may not be structural equivalents in that a nail employs a cylindrical surface to secure wooden parts together, whereas a screw employs a helical surface, in the environment of fastening wooden parts, a nail and a screw may be equivalent structures. It is the express intention of the applicant not to invoke 35 U.S.C. §112, paragraph 6 for any limitations of any of the claims herein, except for those in which the claim expressly uses the words ‘means for’ together with an associated function.

Claims

1. A method for determining a steam quality at a subsurface location for a steam injection operation wherein an internal cross-section area of a conduit supplying steam is a known dimension, comprising: obtaining a total mass flow rate of the steam;measuring a vapor velocity at the subsurface location;measuring a second parameter;determining a vapor density from the second parameter when the second parameter comprises a measurement other than the vapor density;generating a vapor mass flow rate as a function of the vapor velocity, the vapor density and the internal cross-section area of the conduit; andgenerating the steam quality at the subsurface location as a function of the vapor mass flow rate and the total mass flow rate.

2. The method of claim 1, wherein the second parameter comprises one of a temperature, a pressure, the vapor density and combinations thereof.

3. The method of claim 2, wherein the second parameter is a temperature or a pressure and wherein the vapor density is determined from a steam table.

4. The method of claim 2, wherein the second parameter is a temperature or a pressure and wherein the vapor density is determined using a polynomial expression from an International Steam Table.

5. The method of claim 1, wherein the total mass flow rate is obtained from one of a steam supplier and a measurement at a steam generator.

6. The method of claim 1, further comprising measuring the vapor velocity by one of an optical flow meter, a Doppler flow meter, and a heated anemometer.

7. The method of claim 1, wherein said method is performed by a production logging tool comprising one of a slickline tool, a wireline tool and a coil tubing tool.

8. The method of claim 1, wherein the vapor velocity is measured by a turbine flow meter.

9. The method of claim 8, wherein the vapor velocity measured by the turbine flow meter is determined from an apparent turbine velocity using a multispeed calibration.

10. The method of claim 9, wherein the multispeed calibration comprises a calibration chart including a plurality of depths.

11. The method of claim 1, further comprising: computing a superficial liquid velocity from the steam quality and the total mass flow rate;verifying the superficial liquid velocity is below an annular flow threshold; andif the superficial liquid velocity is not below the annular flow threshold, raising an error sign.

12. The method of claim 11, wherein the annular flow threshold is determined from a flow pattern map using superficial vapor velocity and superficial liquid velocity.

13. The method of claim 1, wherein the subsurface location is at a location in the steam injection conduit before injected steam leaves the conduit.

14. The method of claim 1, further comprising: measuring the vapor velocities at a plurality of the subsurface locations;measuring the second parameters at the plurality of the subsurface locations;generating a plurality of the steam qualities at the plurality of subsurface locations as a function of the vapor velocities, the second parameters and the internal cross-section area of the conduit; andoutputting a steam quality profile based on the plurality of steam qualities at the plurality of subsurface locations.

15. The method of claim 1, further comprising performing a spinner calibration.

16. A system for determining a steam quality in a steam injection operation in an oil field, comprising: a steam conduit that supplies steam, wherein a cross-section area of the steam conduit is a known dimension; a steam injector that injects the steam into a reservoir;a vapor flow meter that measures a vapor velocity within the steam conduit;a second sensor that measures a second parameter within the steam conduit; anda controller that determines a vapor density from the second parameter when the second parameter comprises a measurement other than the vapor density; generates a vapor mass flow rate as a function of the vapor velocity, the vapor density and the internal cross-section area of the conduit; andgenerates the steam quality at a subsurface location as a function of the vapor mass flow rate and a total mass flow rate.

17. The system of claim 16, wherein the second sensor comprises a temperature sensor, a pressure sensor, or a vapor density sensor.

18. The system of claim 16, wherein the vapor flow meter comprises a turbine flow meter; andwherein the controller determines the vapor velocity from the turbine flow meter measurement with a multispeed calibration.

19. The system of claim 16, wherein the vapor flow meter and the second sensor are disposed about a logging tool string.

20. The system of claim 16, further comprising a user interface that accepts at least one adjustment to steam injection operation based on the steam quality.

21. The system of claim 16, wherein the controller further computes a superficial liquid velocity from the steam quality and the total mass flow rate; verifies the superficial liquid velocity is below an annular flow threshold; and generates an error alert when the superficial liquid velocity exceeds the annular flow threshold.

22. The system of claim 16, wherein the vapor flow meter measure vapor velocities at a plurality of subsurface locations; and wherein the second sensor measures second parameters at the plurality of subsurface locations; and the controller generates a plurality of steam qualities at the plurality of subsurface locations and outputs a steam quality profile based on the plurality of steam qualities at the plurality of subsurface locations.

23. The system of claim 16, wherein the controller generates a vapor mass flow rate as a product of the vapor velocity, the vapor density and the internal cross-section area of the conduit.

24. The system of claim 16, wherein the controller generates the steam quality at a subsurface location by dividing the vapor mass flow rate by a total mass flow rate.