GB2263172A

GB2263172A - Flow rate monitoring.

Info

Publication number: GB2263172A
Application number: GB9200310A
Authority: GB
Inventors: Joe Allen
Original assignee: PECO MACHINE SHOP AND INSPECTI; PECO PRODUCTION TECHNOLOGY LIM
Current assignee: PECO MACHINE SHOP AND INSPECTI; PECO PRODUCTION TECHNOLOGY LIM
Priority date: 1992-01-08
Filing date: 1992-01-08
Publication date: 1993-07-14
Anticipated expiration: 2012-01-08
Also published as: GB2263172B; GB9200310D0

Abstract

A double venturi meter for determining the rate of flow of fluid in a pipe comprising a pipe section with a first internal bore size S1, a first internal constriction within the pipe section which defines a portion of the pipe section with a second internal bore size S2 which is smaller than S1 a second internal constriction within the pipe section which defines a portion of the pipe section with a third internal bore size S3 which is smaller than S1, and means for measuring at least two differences in pressure in fluid flowing in the pipe section, between points selected from those at which the internal bore size of the pipe section has the value S1, S2, and S3. The constrictions may be separated by a pipe section having the first internal bore size S1, (Fig 3). Intended for measuring flow rates of oil or gas products from a natural underground reservoir. <IMAGE>

Description

FLOW RATE MONITORING This invention relates to a meter for measuring the rate of flow of a fluid. The invention relates in particular to monitoring the rate of flow of fluid hydrocarbon products from a natural underground reservoir.

In the extraction of hydrocarbon products such as oil or gas from natural reservoirs, it is desirable to know the rate at which the fluids flow through the extraction conduit from the points of view both of management of the extraction operation and of management of the reservoir. Commonly, such reservoirs occur in locations where climate and other factors make management of the extraction process hazardous, such reservoirs generally being underground at elevated temperature and pressure in locations such as desert and sub-sea. A further complication is that the fluid extracted from natural reservoirs frequently exists in more than one phase, and it can be desirable to know the individual flow rates of the various constituent phases.For example, in the case of extraction of oil from a sub sea oil reservoir, fluid extracted from the reservoir can contain water and gas in addition to the desired oil.

The flow rates of fluids extracted from under ground hydrocarbon reservoirs are monitored using a test pipe which is laid between the point of extraction from the reservoir (known as the "wellhead") and a location from which the extraction process is controlled. For example, in the case of a sub-sea reservoir a test pipe is laid from the well-head to the rig from which extraction is controlled. Products extracted through the test pipe are split into oil, water and gas components, and the individual flow rates of the separated components are measured.

This technique for measuring flow rates, involving the use of a test pipe, has several disadvantages. Particularly significant is the expense associated with laying a dedicated test pipe from a well-head to a control location especially when the wll-head is remote from the control location as with a sub-sea reservoir.

The accuracy and frequency with which flow rates through a main extraction conduit can be estimated by carrying out measurements at a remote control location using a test pipe is limited.

Furthermore, it is often necessary to pump chemical additives into the well to inhibit the deposition of scale on the internal surfaces of the production pipe during the extraction of hydrocarbon products. Thousands of barrels of chemical additive may be pumped into the underground oil reservoir and present systems use separate monitoring means to measure the flow rate of injected chemicals.

According to one aspect of the invention there is provided a meter for determining the rate of flow of fluid in a pipe, which comprises: (a) a pipe section with a first internal bore size Sl, (b) a first internal constriction within the pipe section which defines a portion of the pipe section with a second internal bore size S2, which is less than Sl, (c) a second internal constriction within the pipe section which defines a portion of the pipe section with a third internal bore size S3, which is less than Sl, and (d) means for measuring at least two differences in pressure in fluid flowing in the pipe section, between points selected from those at which the internal bore size of the pipe section has the value Sl, S2 and S3.

The invention has the advantage that information concerning the rate of flow can be provided to operators at the control location, without the need to lay a dedicated test pipe, especially when the well-head is remote from the control location. The significant expense associated with such a test pipe is therefore avoided. Furthermore, the accuracy and frequency with which the rate of flow of hydrocarbon products from an underground reservoir can be monitored are increased significantly compared with the monitoring process previously used.

Preferably, the internal bore size S2, in the first constriction, is less than that in the second constriction. The fluid flowing through the meter may pass through the constriction with the smallest internal bore size first, and then the constriction with the larger internal bore size. However, a similar arrangement in which the fluid flows through the constriction with the larger bore size first may be employed to measure fluid flow rates effectively.

The flow meter may include four devices for measuring absolute pressure at selected points within the pipe section which has internal bore sizes with the values Sl, S2 and S3.

The flow meter may include two devices for measuring differential pressure between pairs of respective points within the pipe section which has internal bore sizes with the values SX, S2 and 53.

The present invention is applicable to monitoring the rates of flow from reservoirs located close to a control location (as in the case with land and platform wells) where the frequency with which monitoring can take place can be a particular advantage.

Additionally, the invention can be applied to reservoirs located remote from a control location (as is the case with sub-sea wells) where the frequency with which monitoring can take place, and avoiding the need to lay a dedicated test line, are advantages over previously used techniques.

The products whose flow rate is measured by the invention may comprise gas, liquid, and mixtures of the two. The invention finds application in the extraction of a fluid from a reservoir by injection into the reservoir of another fluid, for example gas or water injection wells. When the products include liquid components, the components may be immiscible, for example comprising oil and water phases. When the extracted products comprise gas and liquid components, it is particularly preferred that the pipe section in which the flow rate meter is incorporated be positioned at a location at which the pressure to which the products are subjected is greater than the bubble point pressure of the liquid, so that the products whose flow rate is measured consists only of liquid (which may consist of immiscible components).This makes it possible for the step of separating components of the extracted products into gas and liquid phases, which has taken place at the control location at the proximal end of the test pipe in previously used monitoring techniques, to be avoided.

The present invention will find particular application in the extraction of hydrocarbon products from underground reservoirs which are located below a seabed. In such applications, control locations are frequently provided at some significant distance from the reservoirs in question, making the use of a test pipe between the reservoirs and the respective control locations, particularly disadvantageous. Furthermore, the pressures to which the extracted products are subjected at the point of extraction are particularly high. This makes it possible for the flow rate of products which include a gas component to be measured on just a liquid phase in which the gas component is dissolved, in the manner discussed above.

The invention has the significant advantage that the bore through which the hydrocarbon products flow is not obstructed by any component of the meter, as would be the case if, for example the meter comprised an impeller which is caused to rotate by movement of fluid past it. The lack of any obstruction in the bore is particularly significant when, as is generally the case in the present invention, the measurement of fluid flow rate takes place on the pipe through which products are extracted from the reservoir, since it allows access to be gained to the reservoir for example with equipment such as might be required for reservoir measurements.A further advantage of the use of such a flow meter is that, in the absence of moving parts such as an impeller, it is relatively insensitive to rough treatment such as it might be exposed to when incorporated within a pipe section in the vicinity of the underground reservoir. The meter is therefore significantly more robust than other designs presently available and would have a longer service life reducing time lost for repairs or replacement.

The first and second constrictions may be separated by a portion of the pipe section in which the internal bore size of the pipe section has the value S. Pressure differential information obtained from the two constrictions can enable the individual oil and water flow rates to be determined. Pressure difference measuring means measures differences in pressure in fluid within the pipe section at each of the constrictions, between points at which the internal bore size of the pipe section has the value Sj and S2 or S3 as the case may be.

Preferably, the internal bore size of the pipe section at all points between the first and second constrictions has a value which is between S2 and S3. Ideally, there should be a gradual transition between the regions of different sized bores. This can allow the meter to operate efficiently and not impede the flow of fluids therethrough, and also to allow the meter to effectively monitor the flow of injected fluids, such as chemical additive to prevent the deposition of scale, though this is not essential to the operation of the device.

The pressure difference measuring means may measure differences in pressure in fluid within the pipe section at each of the constrictions, between points at which the internal bore size of the pipe section has the value Sl and S2 or S3 as the case may be.

The pressure difference measuring means may measure differences in pressure in fluid within the pipe section at each of the constrictions, between points at which the internal bore size of the pipe section has the value S3 and Sl or S2 as the case may be.

The pressure difference measuring means may measure differences in pressure in fluid within the pipe section at each of the constrictions, between points at which the internal bore size of the pipe section has the value S2 and Sl or S3 as the case may be.

It is necessary to measure at least two differences in pressure of the fluid flowing in the pipe section, between points selected from those at which the internal bore size of the pipe section has the value Sl, S2 and S3. From this information, and as long as the flow meter is inclined to the horizontal, it is possible to ascertain the overall flow rate, individual flow rates of the liquid components and the relative proportions of the liquid phase products flowing in the pipe. This is especially useful for the assessment of multi-phase liquids typically found in underground oil reservoirs as it allows the individual flow rates of the phases of the products within the pipe section to be calculated, without any need to separate the individual phases and then calculate the flow rates which is the current practice.

Generally, the pipe section of the meter has an internal bore which is approximately circular in cross-section.

Embodiments of the present invention will now be described, by way of example only, with reference to the accompanying drawings, in which: Figure 1 is a schematic drawing of a preferred embodiment of flow meter according to the present invention utilising a multibore; Figure 2 is a schematic drawing of an embodiment of flow meter according to the present invention utilising a multibore construction; and, Figure 3 is a schematic drawing of an embodiment of flow meter according to the present invention utilising twin venturi.

Referring to the drawings, Figure 1 shows an embodiment of flow meter according to the present invention which comprises a pipe section 1 through which hydrocarbon products are received from an underground reservoir, and are discharged to a pipe for transportation from the reservoir, for example to the surface if the reservoir is below ground level. Two constrictions, 2 and 3, are provided on the internal surface of the pipe section 1.

Two differential pressure measurements are taken at positions spaced apart along the length of the pipe section 1 with the use of a sensor or transducer. A first differential pressure measurement is made between the pipe section 1 and the constriction 2, as indicated by AP2 in the drawing. A second differential pressure measurement is made between the second constriction 3 and the pipe section 1, as indicated by APX in the drawing. It is preferable, though not essential, that the transitions 4 between the different sizes of bore occur gradually. This ensures optimum efficiency of the flow characteristics of the meter.The included angle of these transition regions should not be greater than about 200, especially not greater than about 15 , thereby enabling the flow meter to measure flow rates of fluids in the pipe travelling in either direction.

The rate of flow of the combined liquid phases in the pipe section 1 can be determined from either of the pressure differential measurements between the pipe section 1 and the constrictions 2 or 3. Having a second pressure differential measurement between the second constriction and the pipe section 1 enables the relative proportions of two immiscible liquid components of products flowing through the pipe section 1 to be calculated, provided that the densities of the individual liquid components are known. The information provided by the two pressure change measurements therefore allows the individual flow rates of the immiscible phases of the liquid products to be calculated.

When the products flowing through the pipe section 1 comprise two immiscible liquid phases and a gas component, the pipe section with associated gauges will be located such that the pressure under which products within its flow is greater than the bubble point, so that the gas component remains dissolved in the liquid phases. The products flowing through the pipe section past the measurement points are therefore in liquid phases only. The pressure change measurements allow the rate of flow of the combined liquid phases to be measured.

Figure 2 shows a flow meter according to the present invention which has an identical configuration of constriction as that shown in Figure 1 but with the differential pressure measurements taken at different locations. One differential pressure measurement is made between the second constriction 12 and the pipe section 10, as indicated in the drawing by tPl, and another differential pressure measurement is made between the first constriction 11 and the second constriction 12, as indicated in the drawing by AP2. The flow rate of the individual liquid phases flowing in the pipe are determined from these pressure change measurements in a similar way to that indicated above.

Figure 3 shows a further embodiment of flow meter according to the present invention in which the first constriction 20 is separated from the second constriction 21 by a uniform bore region 22. The internal bore size in this region can be the same as that in the pipe on either or both sides of the flow meter.

Two differential pressure measurements are taken between the constriction 20 and the pipe section 23, as indicted in the drawing by AP2; and another differential pressure measurement between the constriction 21 and the pipe section 23, as indicated in the drawing by AP. The flow rate of the combined and individual liquid phases flowing in the pipe are determined from these pressure change measurements in a similar way to that already discussed, a calculated example of which is shown below.

EXAMPLE The relative proportions and flow rates of a two phase liquid extracted from an underground reservoir is calculated as follows, reference being made to Figure 3. In the drawings, the pipe section is inclined at an angle (0) to the vertical. Upstream of the flow meter the bore of the pipe is SX, at the first constriction, the bore of the pipe is S2, and at the second constriction, the bore of the pipe is 53. One pressure change gauge or sensor measures the pressure change AP1 and the second pressure change gauge or sensor measures the pressure change AP2.

The distance between the first pair of points is Ll, and the distance between the second pair of points is L.

As a first step in the calculation, one calculates the density of the two phase liquid which flows along the pipe, according to the following equations: At position 1

At position 2

where

s S1 ss2 S1 CD represents the discharge coefficient, and g has a value 9.8 ms2.

Equating 1 and 2 and solving for #m yields:

The proportion of water (WF) in the mixture can be calculated from knowledge of the density of the mixture, together with knowledge of the densities of water and oil, according to the formula: WF = P #w - #0 The overall flow rate (Q) may be calculated by substituting the value of Pm into equation 1 or 2 above.

From the overall flow rate Q, individual flow rates for the oil and water phases (QO and Qw respectively) may be calculated from the equations below: Qo = Q (1 - WF) Q = Q.WF

Claims

CLAIMS: 1. A meter for determining the rate of flow of fluid in a pipe, which comprises: (a)a pipe section with a first internal bore size Sl, (b)a first internal constriction within the pipe section which defines a portion of the pipe section with a second internal bore size S2, which is less than Sl, (c)a second internal constriction within the pipe section which defines a portion of the pipe section with a third internal bore size S3, which is less than Ss, and (d)means for measuring at least two differences in pressure in fluid flowing in the pipe section, between points selected from those at which the internal bore size of the pipe section has the value Si, S2 and S3.
2. A meter as claimed in claim 1, which includes four devices for measuring absolute pressure at selected points within the pipe section which has internal bore sizes with the values Sl, S2 and S3.
3. A meter as claimed in claim 1, which includes two devices for measuring differential pressure between pairs of respective points within the pipe section which has internal bore sizes with the values S,, S2 and S3.
4. A meter as claimed in any one of claims 1 to 3, in which the first and second constrictions are separated by a portion of the pipe section in which the internal bore size of the pipe section has the value Sl.
5. A meter as claimed in claim 4, in which the pressure difference measuring means measures differences in pressure in fluid within the pipe section at each of the constrictions, between points at which the internal bore size of the pipe section has the value Sl and S2 or S3 as the case may be.
6. A meter as claimed in any one of claims 1 to 3, in which the internal bore size of the pipe section at all points between the first and second constrictions has a value which is between S2 and S3.
7. A meter as claimed in any one of claims 1, 2, 3 or 6, in which the pressure difference measuring means measures differences in pressure in fluid within the pipe section at each of the constrictions, between points at which the internal bore size of the pipe section has the value Sl and S2 or S3 as the case may be.
8. A meter as claimed in any one of claims 1, 2, 3 or 6, in which the pressure difference measuring means measures differences in pressure in fluid within the pipe section between points at which the internal bore size of the pipe section has the value S3 and SX or S2 as the case may be.
9. A meter as claimed in any one of claims 1, 2, 3 or 6, in which the pressure difference measuring means measures differences in pressure in fluid within the pipe section between points at which the internal bore size of the pipe section has the value S2 and Sl or S3 as the case may be.
10. A meter as claimed in any one of the preceding claims, in which the pipe section has an internal bore which is approximately circular in cross-section.