GB2562993A

GB2562993A - Multiphase flow meter calibrator and sampling system

Info

Publication number: GB2562993A
Application number: GB1704087.4A
Authority: GB
Inventors: Maurer Robert
Original assignee: Individual
Current assignee: Individual
Priority date: 2017-03-15
Filing date: 2017-03-15
Publication date: 2018-12-05
Also published as: GB201704087D0

Abstract

A crude oil multiphase flow meter calibrator and an in-situ batch sampling system in which the bulk density and percentage concentration of its constituents namely sand, oil, water; gas and emulsion are determined in-situ. The sampling system 10 comprises a motorized valve system 7, 8, 14, 15, 16 separating the sampler from the main pipe 1, 5 containing the fluid to be considered, after the fluid settles and the proportion of its constituents measured the fluid is returned to the main pipe. In one embodiment the sampling system forms a bypass loop to the main oil riser. In one embodiment the measurement system comprises gamma ray sources and detectors. In other embodiments other measurement means are used such as X-ray, capacitance, ultrasonic, dielectric and microwave systems. The information may be used to manage the well output of the overall crude oil collection and processing system. The system may be used to provide instantaneous flow rate and density of the fluid to compute the mass flow rate and total flow.

Description

Background

The fiscal metering and sampling for analysis of crude oil being traded is carried out in accordance with the guide lines as set out in various internationally agreed API, ISO and related standards. However there are operational requirements that also call for these measurements for the purposes of well management and optimisation of the oil, water and gas separation facilities. In these instances the level of accuracy or measurement uncertainty need only be adequate for purpose. The most important requirement ofthe measuring instruments used apart from accuracy of information is long term reliability as defined by sayl5 to 20 years mean MTBF (mean time between failures). In this respect moving parts are kept to a minimum and the equipment used is of proven reliability

It is established practice to accurately sample crude oil in accordance with internationally agreed standards as defined by ISO 3171 to determine in particular the water content for accounting purposes. This is to establish the true percentage of bulk oil being purchased or sold. In essence an agreed amount of sample per day, week or per shipment is collected in certified sample receivers. The filled receivers are then taken to a remote certified laboratory where the contents are analysed for the water content, as well as any other required characteristics such as calorific value and sulphur content.

Summary of Invention

The object of this invention is to determine in-situ at the sampling point the following major multiphase crude oil properties - the bulk density, percentage concentration of water, oil & free gas .In addition the invention will also identify the presence of water slugs, free gas breakout, emulsion and froth. This transmitted information is of vital interest for the optimum operation at the oil gathering points or stations. Furthermore the information obtained can be used to verify and /or calibrate the output readings from the upstream located dynamic multiphase flow meter.

A further object of this invention is to avoid the use of retrieved daily and weekly filled sample receivers especially on sub -sea installations for retrospective albeit more accurate analysis for determining the characteristics of the crude oil

The major economic object of this invention will be the dispensing ofthe large test separators which are currently in use to determine the percentage concentration ofthe above mentioned constituents.

Another significant advantage is that the above measurements when coupled with the flow rate measurement of the extracted crude oil will yield the mass flow rate of the bulk multiphase fluid stream. In effect this aspect of the invention will allow for the general measurement of multiphase fluid streams

Another major advantage of this invention is that the information on the relative proportions of the multiphase stream can be stored as labelled packages in which the output signals for each constituent can be given a discrete colour code and span width in accordance with its percentage concentration. By saving these discrete packages in a suitable format they can be loaded into a Power Point type presentation. In this manner a tomographic display can be obtained for visualisation of the flow regimes with their varying constituent quantities

Description of Invention

Submitted Drawings

Fig 1 Schematic diagram of the externally rod mounted gamma ray sources and dedicated detectors surrounding a fluid with separated constituents

Fig 2 Sub-sea Installation of Multiphase Meter Calibrator/ Sampler using externally mounted sources and detectors in flushing out mode

Fig3 Sub-sea Installation of Multiphase Meter Calibrator/ Sampler using externally mounted sources and detectors in separation and constituent measuring mode

Fig 4 Sub-sea Installation of Multiphase Meter Calibrator/ Sampler using internally rod mounted integral sources and detectors in the flushing out mode

Fig 5 Schematic diagram of system with upstream mounted in-line dynamic type multiphase fluid flow meter

The use of Gamma Ray sources and detectors (Figs 1) to measure the density of the medium between them is established practice. The type of gamma ray source and its associated detector will in general be suited to the density of range of the medium being measured.

In order to obtain the optimum accuracies there may be a mixture of different source /detector types to differentiate the different phases in the crude oil i.e. water, oil & gas

With reference to Fig 1 the externally mounted gamma ray sources (1) are rod mounted and encased in a rectangular enclosure (2) which is welded to the flanged body of the multiphase meter calibrator/ batch sampler body (3). The dedicated detectors (5) are similarly mounted in the welded on rectangular enclosure (6). Junction Box (11) will transmit the output from each detector generally in a 4-20mA or any other suitable signal for processing into the required information format. The pictorial representation of the gamma rays is shown at (4). The separated constituents are shown pictorially as sand (7),oil(8), water(9) and gas (10)

Fig 2 shows the Sampler/Calibrator body (10) with its externally mounted dedicated gamma ray sources or emitters (11) and detectors (12) in flushing out mode with crude oil circulating through it via the inlet open valves (7) and (8) back into the main riser (3). Fig 2 also shows the calibrator/batch sampler body (10) being preferably connected to a take-off point (6) between the bottom (2) fixed orifice section and the top (3) variable orifice section of a typical Choke Valve assembly (4). This is the most likely position to obtain a fully representative portion of the main flow from the oil well (1) up the riser (5). The large differential pressure between these two points(6) and (15) will cause a representative portion of the crude emanating from the oil well (1) to pass through into the phase separation cylinder /calibrator (10) and back into the main riser (5)

The number of emitter and detectors pairs will vary in accordance to the requirements for the installation. The information obtained from the detectors (12) is transmitted electronically is via suitable sub-sea electrical couplings (13) to the remote signal processing centre on the top-side platform (not shown) for processing and use.

The Calibrator/ Sampler (10) is typically connected at the bottom to the choke valve (4) assembly take off point (6) via a motorised isolation valve (7) a motorised flow control valve(8) followed by a non-return valve (9). The top of the Calibrator /Sampler is connected back into the main riser (5) via a non- return valve (14) a motorised flow control or on /off valve (15) and a motorised isolation valve (16). The exact pipework connecting the Calibrator/Sampler will vary according to the installation requirements including ease of removal/installation via a remote operated vehicle.

Mode of Operation

With reference to Fig 3 the crude oil which in Fig 2 was circulating through by-pass loop of the Calibrator/Sampler (10) installation by having the bottom valves (5) & (7) open as well as top valves (15) and (16) open is now trapped by closing the top bypass valve (15). The now stationary entrapped crude will start to separate out into its constituents or phases with the highest density constituent sand (21) on the bottom followed by the water ( 22), oil (23) emulsion (24) and the lowest density constituent i.e. gas (25) on top.

In practice the layers will not be that clearly defined as shown in Fig 3 but the overall accuracy will be within the boundaries to allow well management to be optimised. In a similar manner this collected data over say a 24 hour period data will allow for the dynamic multiphase flow meter to be either verified or calibrated

Settlement time tests with Crude has shown that the sand, water ,oil and gas take approx. 6-12 minutes to settle out to an acceptable separation limit for well management control. Obviously longer times will allow a more defined separation layers between the different phases. In a high pressure application the gas will in general be dissolved in the oil. Free gas coming from the well will if captured by the by-pass loop be trapped at the top of the calibrator separator. Tests have further shown that separation times are severely curtailed by the viscosity of the oil.

A disadvantage of taking the sample from this part of the choke valve is that due to the shearing action that takes on the oil/water emanating from the reservoir there is a distinct possibility of a stable oil/water emulsion being formed. For the sampler system to work effectively the phases need to separate out relatively quickly. Provision must therefore be made available to inject a chemical de-emulsifier. Trace heating facility may also need to be installed to lower the oil viscosity to allow entrapped water droplets to coalesce and separate out

On completion of the different phase measurements and their verification, the motorised valve (16) is opened to allow for the flushing out of the separated constituents from the receiver (10) and the ingress of a fresh sample aliquot for separation and analysis. It must be understood that different crude oils from different oil wells and sometimes from the same well will have different settling out times.

Figure 4 describes the same installation system as Fig 2 but with the use of internal mounted axially aligned integral type gamma ray sources and sensors (18, & 19), The operational mode will be as described previously

Although this invention has described the use of nucleonic detectors in which the absorption of gamma rays is measured, it does not preclude the use of other suitable detectors callable of resolving the small density differences between the various phases. The present common alternative detectors include X-ray, capacitance, ultrasonic or microwave based technology the ultrasonic type in which the speed of sound is measured in different mediums

Multiphase Flow Rate Measurement

Fig 5 shows schematically shows the installation of a dynamic Multiphase type Flow meter (30) whose output can be calibrated by the various methods as outlined above . Although the use of a separate commercially available flow velocity device mounted upstream of the sampling system as shown, it should yield the more accurate measurement of bulk velocity to allow for the computation of the mass flow by multiplying the flowmeter output signal with that from the densitometers,. However it may at times be more convenient to perform this task in the sampling system itself. After separation takes place the density of the water (22 Fig 3 ) will be the predominant measurement at the bottom of the Receiver (10- Figs 2,3 ,4) and the predominant measurement at the top of the receiver (10) will be that of the lighter oil or free gas (25- Fig 3).

When valve (16) is opened bulk crude oil will enter the Receiver during the first flushing out mode of operation. The bottom set of sensors will notice the rapid change in density from water to oil/water mixture. As the incoming oil mixture passes the top set of detectors the change in density readings will again be noted. By measuring the time between these two events over a set distance that velocity and hence the flow rate can be determined. The accuracy will depend on the frequency response of the detectors and on the fact the flow velocity through the receiver (10) will approximately mimic the velocity in the main oil riser pipe. The overall error may be acceptable for operational requirements

For installations where insufficient differential pressure is unavailable to cause the necessary circulation then the use of a suitable process pump (29-Fig 5) can be installed between the isolation valve (7) and the control valve (8) at the inlet of the receiver (10).

This invention is not limited to sub-sea use.

Claims

1 A batch type sampler for multiphase fluid streams which is controlled via a motorised open/close valve system between the top of the sampler and the main pipe from which the sampled fluid is taken from a lower elevated inlet and returned back to the main riser after the different phases have settled out and their relative proportions measured. The measurement of the relative proportions can be used for either or both to optimise the well management system as well as to calibrate an upstream mounted in-line dynamic multiphase type flowmeter

2 For claim 1 to accurately determine the constituents of the main flow out of the well, the inlet porting to the batch Multiphase sampler/ separator and Multiphase flowmeter calibrator is taken directly from a convenient side outlet of a the main riser where the sampled flow is most likely to be representative of the main flow

3 For claims 1 &2 to meet the objectives of representativity of the sampled flow, the most likely point to obtain a fully representative sample flow will be between the upper and lower orifice sections of a standard commercially available choke valve

4 A method of claim 1, 2 & 3 is the use dedicated gamma ray sources and associated detectors allow for the passage of the separated phases to be timed as they pass through the main measuring body. This will enable the velocity of the by-pass sample flow rate which should be approx, equal to that in the main riser flow to be measured. This measured value can be used to verify the accuracy of the dynamic multiphase flowmeter situated upstream of the calibrator/batch sampling system

5 A claim that the method as explained in claim 4 can be used to determine the overall the bulk density of the sampled stream which together with the velocity measurement will give the mass flow rate of each batch. These measurements can thus be used to verify the accuracy of the dynamic multiphase flowmeter situated upstream of the calibrator/batch sampling system

6 A further embodiment of claim 5 will compare the average of the batch mass flow measurements which after summation over a given time period with the mass flow measurements obtained from the dynamic in line multiphase flow meter. In this manner the multiphase fluid batch sampler can be used to calibrate the upstream installed in-line dynamic multiphase flowmeter

7 A further embodiment of the invention will facilitate the collection of discrete pages of information showing the relative proportions of the crude oil to allow for a tomographic display of the flow pattern changes over a given time period or number of separation cycles as each phase can be electronically colour coded

8 A further embodiment of the invention will allow for the transmission of information regarding the flow pattern and constituents at the wellhead to the surface operators will allow for well management procedures to be optimised by prior warning of flow pattern changes including water slugs, gas break-out and the formation of emulsion

9 A further embodiment of the invention will be the use or alternative emitted/detector system to the gamma ray devices described for illustration in the patent. Thus this patent covers the use of |X-ray, capacitance, ultrasonic and dielectric and microwave type devices which are sensitive to the medium between the emitted source and the detectors measuring the modulated outputs