Patent Application
20120251335
1. Field of the Invention
Embodiments of the invention generally relate to measuring flow rates of components in a multiphase fluid and, more specifically, to a pump control unit coupled to an infrared phase fraction meter.
2. Description of the Related Art
Oil and gas wells often produce water along with hydrocarbons during normal production from a hydrocarbon reservoir within the earth. The water resident in the reservoir frequently accompanies the oil and/or gas as it flows up to surface production equipment. Operators periodically measure the fractions of an overall production flow stream that are water/oil/gas for purposes such as improving well production, allocating royalties, properly inhibiting corrosion based on the amount of water and generally determining the well's performance.
Production of oil with sucker-rod pumps is the most common form of artificial lifting in the world. Sucker-rod pumps are often accompanied by a local field computer called a rod pump controller, which uses sensor inputs to optimize pump performance. Rod pumps are characteristically employed in mature fields where the water-to-oil ratio of produced fluids is high and the subsequent oil production on a per-well basis is low. It is important for an operator to know the oil and water production from the well for fiscal and operational reasons. However, low production wells cannot justify expensive measurement systems.
Rod pump wells are typically tested for their oil and water production by gauging tanks or periodic routing through a test separator. The test separator is typically at a central location where a test manifold allows the user to isolate a single well at a time for testing. Therefore, a need exists for a low cost multiphase flow meter that can be located at a single well.
Rod pump controllers are able to offer gross fluid measurement but cannot compare that measurement with a real time fluid water cut measurement. Therefore, a further need exists for a system that can provide real time, accurate, and low cost multiphase measurements.
Embodiments of the present invention generally relate to measuring flow rates of components in a multiphase fluid using a pump control unit coupled to an infrared phase fraction meter.
One embodiment of the present invention provides an apparatus for determining at least one parameter (e.g., an individual phase volume or a phase flow rate) of a multiphase fluid produced by a pump. The apparatus generally includes an optical phase fraction meter configured to determine a phase fraction of the multiphase fluid and at least one processor. The at least one processor is typically configured to determine a total liquid volume or an instantaneous total liquid flow rate of the multiphase fluid produced by the pump during a time interval and to determine for the time interval at least one individual phase volume or at least one phase flow rate based on the phase fraction determined by the optical phase fraction meter and the total liquid volume or the instantaneous total liquid flow rate.
Another embodiment of the present invention provides a system for producing a multiphase fluid from a wellbore. The system typically includes a wellhead disposed at the surface of the wellbore, a pump for moving the multiphase fluid out of the wellbore to the wellhead, an optical phase fraction meter coupled to the wellhead and configured to determine a phase fraction of the fluid, and at least one processor configured to determine a total liquid volume or an instantaneous total liquid flow rate of the multiphase fluid produced by the pump during a time interval and to determine for the time interval at least one individual phase volume or at least one phase flow rate based on the phase fraction determined by the optical phase fraction meter and the total liquid volume or the instantaneous total liquid flow rate.
Yet another embodiment of the present invention is a method. The method generally includes determining, using a processor associated with a pump, a total liquid volume or an instantaneous total liquid flow rate of a multiphase fluid produced by the pump during a time interval; determining a phase fraction of the multiphase fluid using optical spectroscopy; and calculating for the time interval at least one individual phase volume or at least one phase flow rate based on the phase fraction and the total liquid volume or the instantaneous total liquid flow rate.
So that the manner in which the above recited features of the present invention can be understood in detail, a more particular description of the invention, briefly summarized above, may be had by reference to embodiments, some of which are illustrated in the appended drawings. It is to be noted, however, that the appended 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.
Embodiments of the invention generally relate to pumping systems capable of multiphase measurement using a pump control unit (e.g., a rod pump controller) or other suitable processor coupled to an infrared phase fraction meter. Embodiments of the invention provide a number of advantages over conventional pumping systems. For example, conventional pump control systems have been able to offer gross fluid measurements, but these measurements have never previously been coupled with real-time water cut measurements. Additionally, embodiments of the invention provide a system that is much cheaper than typical multiphase meters, which may be occasionally attached to a single well, especially given that a pump controller is already present in a typical pumping system. Further, embodiments of the invention measure the water cut of an individual well at the well-head, without routing the fluid to a centrally located test separator for a field of wells, such that each well may be continuously monitored.
Although embodiments of the invention are described below with respect to a sucker-rod pumping system and a rod pump controller, other embodiments may include any of various suitable pumps and any type of one or more processors associated with a pump, respectively. The pump may comprise a positive displacement pump or another type of pump. Positive displacement pumps include not only sucker-rod pumps, but also progressing cavity pumps (PCPs), which are also known as progressive cavity pumps, eccentric screw pumps, or simply cavity pumps. For some embodiments, the processor(s) may be used to control the pumps. Furthermore, one or more of the processors associated with the pump may be located at the wellsite where the pump is disposed in the wellbore for some embodiments, while for other embodiments, the processor(s) may be remote from the wellsite.
The production of oil with a sucker-rod pump system 100 such as that depicted in
During the part of the pump cycle where the plunger 110 is moving upward (the “upstroke”), the traveling valve 112 is closed and any fluid above the plunger 110 in the production tubing 108 may be lifted towards the surface. Meanwhile, the standing valve 114 opens and allows fluid to enter the pump chamber 106 from the wellbore.
The highest point of the pump plunger motion may be referred to as “top of stroke” or TOS. At the TOS, the weight of the fluid in the production tubing 108 may be supported by the traveling valve 112 in the plunger 110 and, therefore, also by the rod string 102. This load causes the rod string 102 to be stretched. At this point, the standing valve 114 closes and holds in the fluid that has entered the pump chamber 106.
During the part of the pump cycle where the plunger 110 is moving downward (the “downstroke”), the traveling valve 112 initially remains closed until the plunger 110 reaches the surface of the fluid in the chamber. Sufficient pressure may be built up in the fluid below the traveling valve 112 to balance the pressure due to the column of fluid to the surface in the production tubing 108. The build-up of pressure in the pump chamber 106 reduces the load on the rod string 102; this causes the stretching of the rod string 102 that occurred during the upstroke to relax. This process takes place during a finite amount of time when the plunger 110 rests on the fluid, and the horsehead 101 at the surface allows the top of the rod string 102 to move downward.
The position of the pump plunger 110 at this time is known as the “transfer point” as the load of the fluid column in the production tubing 108 is transferred from the traveling valve 112 to the standing valve 114. This results in a rapid decrease in load on the rod string 102 during the transfer. After the pressure below the traveling valve 112 balances the one above, the valve 112 opens and the plunger 110 continues to move downward to its lowest position (“bottom of stroke” or BOS). The movement of the plunger 110 from the transfer point to the bottom of stroke is known as the “fluid stroke” and is a measure of the amount of fluid lifted by the pump 104 on each stroke. In other words, the portion of the pump stroke below the transfer point may be interpreted as the percentage of the pump stroke which contains fluid. This percentage is the pump fillage.
Typically, there are no sensors to measure conditions at the pump 104, which may be located thousands of feet underground. However, numerical methods exist to calculate the position of the pump plunger 110 and the forces acting on it from measurements of the position of and stress in the rod string 102 at the pump control unit (e.g., a rod pump controller (RPC) 116, a variable speed drive, or an RPC having a variable speed drive) located at the surface. These measurements are typically made at the top of the polished rod 118, which is a portion of the rod string 102 passing through a stuffing box 103, using strain sensors coupled to the rod 118 to measure load, for example. The RPC 116 may be used to measure pump fillage for a pump cycle, from which a total liquid flow rate may be determined.
During a pump cycle, the pump moves fluid from the highest point of the production chamber 108 through wellhead 105 into flow path 122. An optical phase fraction meter (e.g., an infrared filter photometer 120), such as a water cut meter, may be disposed within flow path 122. The photometer 120 may provide the phase fraction of water (i.e., the water cut) for the fluid in the flow path 122. By combining the water cut from the photometer 120 with the total flow rate from the rod pump controller 116, the phase flow rate for both water and oil in the flow path 122 may be determined.
In operation, light from the source 211 passes through the first sapphire plug 302 and through the fluid of the flow path 122 where the light is attenuated prior to passing through the second sapphire plug 304. Unique absorption characteristics of the various constituents of the flow path 122 cause at least some of the attenuation. The collimator 206 adjacent the second sapphire plug 304 focuses and concentrates the attenuated light into optical outputs 209 via the common connector 208. The optical outputs 209 typically include a multitude of optical fibers that are divided into groups 209a-d. Utilizing one type of standard connector, eighty-four fibers pack within the common connector 208 such that each of the four groups 209a-d comprise a total of twenty one fibers. However, the exact number of fibers and/or groups formed varies for other embodiments.
As illustrated in
Each of the four groups 209a-d connects to a respective housing 310 of one of the infrared filters 308 via a connector 306 such as an SMA connector. Each of the infrared filters 308 includes the housing 310, a narrow bandpass filter 311 and a photodiode 313. The photodiode 313 produces an electrical signal proportional to the light received from a respective one of the groups 209a-d of the optical outputs 209 after passing through a respective one of the filters 311. Preferably, a logamp circuit (not shown) measures the electrical signals to provide up to five decades of range. Each of the filters 311 filters all but a desired narrow band of infrared (or near infrared) radiation. Since each of the filters 311 discriminates for a specific wavelength band that is unique to that filter, each of the groups 209a-d represent a different channel that provides a total attenuation signal 314 indicative of the total attenuation of the light at the wavelengths of that particular filter. Thus, the signals 314a-d from the four channels represent transmitted radiation at multiple different desired wavelength bands.
If only one wavelength is interrogated without comparison to other wavelengths, absorbance-based attenuation associated with that one wavelength cannot be readily distinguished from other non-absorbance-based attenuation that can introduce errors in an absorbance measurement. However, using multiple simultaneous wavelength measurements provided by the signals 314a-d from the different channels enables non-wavelength-dependent attenuation, such as attenuation caused by common forms of scattering, to be subtracted out of the measurements. An appropriate algorithm removes these non-absorbance background influences based on the fact that the non-wavelength-dependent attenuation provides the same contribution at each wavelength and hence at each channel regardless of wavelength-dependent absorbance. Thus, comparing the signals 314a-d from each channel at their unique wavelengths enables correction for non-wavelength-dependent attenuation.
Additionally, selection of the filters 311 determines the respective wavelength for each of the multiple simultaneous wavelength measurements associated with the signals 314a-d from the different channels. Accordingly, the different channels enable monitoring of wavelengths at absorbent peaks of the constituents of the flow path 122, such as water absorbent peaks in addition to oil absorbent peaks, based on the wavelengths filtered. To generally increase resolution, a minute change in the property being measured ideally creates a relatively large signal. Since the relationship between concentration and absorption is exponential rather than linear, large signal changes occur in response to small concentration changes of a substance when there is a low cut or fraction of the substance being measured based on attenuation of the signal from the channel(s) monitoring the wavelengths associated with an absorbent peak of that substance. In contrast, small signal changes occur in response to concentration changes of the substance when there is a high cut of the substance being measured by the same channel(s).
Accordingly, the different channels provide sensitivity for the meter across a full range of cuts of the substance within the flow, such as from 0.0% to 100% phase fraction of the substance. For example, channel(s) with wavelengths at water absorbent peaks provide increased sensitivity for low water fractions while channel(s) with wavelengths at oil absorbent peaks provide increased sensitivity for high water fractions. Thus, the channel(s) with the highest sensitivity can be selected for providing phase fraction results or averaged with the other channels prior to providing the results in order to contribute to the sensitivity of the meter.
Another benefit of the multiple simultaneous wavelength measurements provided by the signals 314a-d from the different channels includes the ability to accurately calibrate the photometer 120 with a small amount of pure fluid. Thus, calibration of the photometer 120 need not require a reference cut. Selection of wavelengths as disclosed herein for the channels reduces sensitivity to different types of oil in order to further simplify calibration. For example, oils which are light in color or even clear have an optimal absorbance peak around a wavelength of 1750 nanometers, but black oils have stronger absorbance around a wavelength of 1000 nanometers. If two of the four channels include filters at these wavelengths, then the algorithm can determine the optimal choice at the calibration stage rather than requiring a hardware change for different oil types.
Preferred embodiments of the photometer 120 may use the broadband source 211 and the filters to isolate wavelengths associated with the channels. However, other embodiments of the photometer 120 may include separate narrow band sources, tunable filters, and/or a single tunable source that is swept for the desired wavelengths of the channels.
In general, a first wavelength band 405 includes wavelengths within a range of approximately 900 nanometers (nm) to 1200 nm, for example about 950 nm, where there is an oil absorbent peak. A second wavelength band 406 includes wavelengths centered around 1450 nm where there is a water absorbent peak. A trough around 1650 nm provides another interrogation region where a third wavelength band 407 generally is centered. A fourth wavelength band 408 generally includes a peak centered about 1730 nm that is fundamentally associated with carbon-hydrogen bonds of the oil 401, 402 and the condensate 404. A fifth wavelength band (not shown) includes wavelengths centered around 1950 nm where there is another water absorbent peak. The substantial similarities and/or differences in the absorbance of the different phases at each of the bands 405-408 further enables their differentiation from one another with the infrared filter photometer 120.
At step 520, a phase fraction of the multiphase fluid may be determined using optical spectroscopy. For example, the processor (e.g., the rod pump controller 116) may calculate a phase fraction of at least one phase (e.g., a water cut) based on absorbance measurements made by the infrared filter photometer 120. These absorbance measurements are described in greater detail below with respect to determining the water cut.
Water cut measurements (i.e., water cut (water/total liquid ratio) only with no measure of the gas phase volume) may be made throughout a wide range of free gas phase content in the stream. Three exemplary flow regimes may be defined as i) dispersed gas bubble in liquid; gas-liquid slugs; and dispersed liquid in gas. The first two flow regimes cover flows where about 0-95% gas volume fraction (GVF) exists while the last regime includes about 95-99.99% GVF.
For full range water cut (0-100%) with three phase streams (e.g., oil, water, and gas) where gas can represent about 0-95% GVF, absorbance measurements performed using the photometer 120 correspond to a function which may be defined as:
A
i
==a
oi
x
o
+a
wi
x
w
+S (1)
where:
Ai=total absorbance at wavelength i and includes chemical (absorption) and physical (scattering) effects;
aoi=absorption coefficient for oil at wavelength i;
awi=absorption coefficient for water at wavelength i;
xo=pathlength of oil;
xw=pathlength of water; and
S=scatter contribution to overall absorbance (wavelength independent).
Theoretically, there is also a gas term (agixg, where agi=absorption coefficient for gas at wavelength i and xg=pathlength of gas), but the absorption by gas is negligible (i.e., agi≈0), so the gas term drops out from the equation.
Making three separate absorbance measurements for three different wavelengths enables solving for three unknowns (xo, xw, and S) in Equation 1. This allows for the potential of increased effective pathlength due to scattering. This approach works for flow regimes without gas or with the dispersed gas bubbles in liquid (flow regime i) to enable calculation of the water cut based on the pathlength of water xw relative to the total pathlength xw+xo. The wavelengths are chosen such that the various fluid constituents (e.g., oil and water) have different absorption profiles, in order to differentiate between the constituents.
For the gas-liquid slugs (flow regime the photometer 120 may apply a weighting factor to the measured water cut using the liquid content in the sensor gap. The total liquid pathlength (xw+xo) can drop to 0 if there is no liquid in the sensor gap. Integrating the product of instantaneous water cut and total liquid pathlength over a period of time (e.g., 30 min.) and dividing by the cumulative total pathlength over that time provides a liquid weighted water cut rather than a time-averaged water cut. Therefore, applying Equation 1 as described above during these selected intervals associated with liquid slugs passing across the meter enables an improved calculation for the water cut, which is independent of the quantity of gas.
After determining the phase fraction of the multiphase fluid at step 520, at least one individual phase volume or at least one phase flow rate based on the phase fraction and the total liquid volume or the instantaneous liquid flow rate may be calculated for the time interval at step 530. For some embodiments, a pump control unit (e.g., the rod pump controller 116) may perform this calculation. For some embodiments, calculating the individual phase volume for the time interval may comprise integrating the calculated phase flow rate over the time interval.
The rod pump controller 116 does not calculate flow rate at any particular point in the pump stroke. Instead, the rod pump controller 116 determines the amount of pump fillage on the downstroke, which tells the controller the volume of fluid that will be brought up on the subsequent upstroke. The pump fillage on the downstroke may be determined from measurements of the load on the rod string 102 and position of the pump plunger 110 to obtain the transfer point (and hence, the volume in the pump chamber 106 during the subsequent upstroke) as described above with respect to
The infrared filter photometer 120 may provide an instantaneous water cut regardless of whether the fluid in the flow path 122 is flowing. Thus, the rod pump controller 116 may only record data from the photometer 120 during each upstroke 604 and then apply those readings to the pump fillage for that stroke. The period 606 represents the proper time for taking valid readings from the photometer 120. Because the water cut will likely vary over the course of the upstroke 604, the measurements taken by the infrared filter photometer 120 may most likely be averaged in some manner by the rod pump controller 116 at the end of each upstroke 604.
For other embodiments, the rod pump controller 116 may use the position of the pump plunger 110 (i.e., rod position data) to determine the velocity of the polished rod 118 (i.e., rod velocity) as a function of time. For example,
Returning to
In summary, the combination of the infrared filter photometer and the processor associated with the pump offers a complete package to provide operators with accurate well-testing data from equipment mounted at the well head. Inferred production from the pump processor may be employed to determine daily volume totals, and measurements from the photometer may be utilized to determine what percentage of that total volume is oil and water.
Embodiments of the invention provide a number of advantages over typical pump systems. For example, previous pump control systems have been able to offer gross fluid measurements, but those measurements have never been coupled with real-time water cut measurements. Additionally, embodiments of the invention provide a system that is much cheaper than typical multiphase meters, which may be occasionally attached to a single well, especially given that a pump controller is already present in a typical pump system. Further, embodiments of the invention measure the water cut of an individual well at the wellhead, without routing the fluid to a centrally located test separator for a field of wells, such that each well may be continuously monitored.
While the foregoing is directed to embodiments of the present invention, other and further embodiments of the invention may be devised without departing from the basic scope thereof, and the scope thereof is determined by the claims that follow.
