WO2014177210A1

WO2014177210A1 - Estimating a thickness of a deposited material on a surface

Info

Publication number: WO2014177210A1
Application number: PCT/EP2013/059116
Authority: WO
Inventors: Rainer Josef HOFFMANN; Lene Amundsen; Reidar Barfod SCHÜLLER
Original assignee: Statoil Petroleum As
Priority date: 2013-05-02
Filing date: 2013-05-02
Publication date: 2014-11-06

Abstract

A system and method for estimating a thickness of a deposited material on a surface of production equipment. A first conduit (1) is provided for conveying a first fluid, the first conduit having an inner and an outer surface and disposed at a remote location from the production equipment. A second conduit (7) is disposed adjacent to the first conduit, the second conduit arranged to convey a second fluid to simulate an environment around the production equipment. A measuring device is provided that is arranged to measure a thickness of deposited material on the inner surface of the first conduit, wherein the measured thickness in the first conduit corresponds to an estimated thickness in the production equipment. This allows the thickness of the deposited material in the production equipment to be estimated by simulating the conditions around the production equipment.

Description

Estimating a Thickness of a Deposited Material on a Surface

TECHNICAL FIELD The invention relates to the field of estimating a thickness of a deposited material on a surface, and in particular to estimating a thickness of wax deposition in subsea equipment such as a subsea pipeline.

BACKGROUND

Wax deposition at the inside wall of a pipeline for carrying fluid hydrocarbons is a severe problem in a hydrocarbon production infrastructure. When a warm hydrocarbon fluid (or mixture of fluids) oil flows through a pipeline, it comes into contact with the inner walls of the pipeline. The pipeline temperature is typically lower than that of the fluid, and this can cause wax or other hydrate agglomerates to precipitate from the fluid and adhere to the pipeline inner wall. Over time, these solid deposits on the pipeline inner wall increase in thickness and consequently will reduce the internal pipeline cross-sectional area. This leads to a loss of pressure, and ultimately to a complete blockage of the pipeline.

The rate of deposition on the inner wall of a pipeline conducting a multiphase fluid stream of hydrocarbons varies according to several parameters, such as the surrounding temperature (subterranean, air, sea water), the fluid stream temperature, the pressure inside the pipeline, the composition of the fluid stream and the distribution of phases in the fluid stream.

There are several technologies that deal with the problem of build-up of waxy deposits include pigging, chemical inhibition, and direct electrical heating. Pigging involves passing a tool through the pipeline that removes the wax from the pipeline inner wall at regular intervals. Pigging is a complex and expensive operation.

If no loop is available, a pig has to be inserted sub-sea using remote-operated vehicles.

It is also a risky operation if the thickness of the wax cannot be measured or predicted.

If more wax has been deposited than the pig diameter is designed for, this can result in a stuck pig. Chemical inhibition involves the addition of chemicals to the fluid which inhibit wax deposition. Chemical inhibition is expensive due to the fact that an additional pipeline has to be built that supplies the chemicals to the wellhead, and the chemicals themselves are expensive. Chemical inhibition is also inefficient as there are currently no chemicals available that completely eliminate wax deposition. There is always a need of additional pigging operations to remove waxy build-up. Furthermore, the chemicals that are used are typically classified as environmentally very problematic. Direct electrical heating involves heating the pipeline to maintain it at a temperature above the wax appearance temperature. Electric heating above the wax appearance temperature is very expensive due to both high installation and operational costs. Accordingly, direct electric heating is not feasible for long-distance transport. Whether or not these methods are used, it is important to be able to measure or estimate the deposition of waxy deposits in order to assess the risk of the pipeline becoming blocked or having its effective inner diameter effectively reduced.

WO 2010/087724 describes a method of measuring the thickness of deposition of wax or other materials. Heat is applied to a surface on which deposits are formed to remove the deposits. This may be in the form of a heat pulse or continuous heat. A further heat pulse is applied to the surface and to a second surface. The temperature of the two surfaces is then measured and the difference in temperature measurements, or the time of temperature decay, can be used to estimate the thickness of deposits. It will be appreciated that other techniques may be used to measure the thickness of deposits. These techniques can be used to measure wax deposition in-situ on any kind of process equipment, including subsea pipelines

For existing pipelines, it is very expensive to install additional subsea equipment or instrumentation. Such installation requires not only complex marine operations, but also digging up the pipeline, stripping it from its insulation and installing any sensors and heating or cooling equipment. SUMMARY

It is an object to provide a means of estimating the extent of deposition of a solid material such as wax in production equipment.

According to a first aspect, there is provided a system for estimating a thickness of a deposited material on a surface of production equipment conveying a first fluid that may give rise to deposition. A first conduit is provided for conveying the first fluid, the first conduit having an inner and an outer surface and disposed at a remote location from the production equipment. A second conduit is disposed adjacent to the first conduit, the second conduit arranged to convey a second fluid to simulate an environment around the production equipment. A measuring device is provided that is arranged to measure a thickness of deposited material on the inner surface of the first conduit, wherein the measured thickness in the first conduit corresponds to an estimated thickness in the production equipment. This allows the thickness of the deposited material in the production equipment to be estimated by simulating the conditions around the production equipment. The conditions of production equipment that may otherwise be difficult to access (such as subsea production equipment) can therefore be estimated.

As an option, the production equipment is subsea hydrocarbon production equipment and the first fluid comprises a fluid hydrocarbon. As a further option, the production equipment is a subsea pipeline for conveying fluid hydrocarbons. An example of a deposited material is wax or hydrates precipitated from the fluid hydrocarbon.

The second fluid is optionally seawater, in which case the system is provided with a pump arranged to pump seawater through the second conduit. The second conduit therefore simulates the same sort of conditions as production equipment located in seawater.

As an option, the second conduit forms an annulus around the first conduit.

A heat exchanger is optionally located upstream of the measuring device. The heat exchanger is arranged to substantially match the temperature of the first fluid in the first conduit with corresponding fluid in the production equipment. This ensures that conditions in the first conduit substantially match the conditions ithe production equipment.

An insulation material is optionally disposed around the first conduit. This allows production equipment conditions to be simulated. For example, the production equipment ma be a pipeline that is buried in the sea bed. The type and thickness of insulation is therefore chosen to simulate the insulating properties of the sea bed.

An exemplary measuring device includes a heating element adjacent to the first conduit for providing a heat pulse to the first conduit, and a temperature sensor for measuring a temperature of the first conduit. The temperature after a predetermined time after the end of the heat pulse can be correlated with a thickness of deposited material. The heating element may be disposed between the insulation material and the first conduit. The first conduit optionally has any of the same dimensions and the same angle of inclination as the production equipment. This is because deposition in the production equipment may be affected by these factors. For example, if the geometry of the production equipment at a certain point is such that the fluid flow slows down, then deposition may occur more rapidly. Matching the geometry and angle of the production equipment allows the conditions of the production equipment to be more accurately simulate by the first conduit.

According to a second aspect, there is provided a method of estimating a thickness of a deposited material on a surface of production equipment. A first fluid is conveyed through a first conduit. The first conduit has an inner and an outer surface and is disposed at a remote location from the production equipment. A second fluid is conveyed through a second conduit disposed adjacent to the first conduit to simulate an environment around the production equipment. A thickness of deposited material is measured on the inner surface of the first conduit. The measured thickness in the first conduit corresponds to an estimated thickness in the production equipment, allowing an estimation of deposition in the production equipment to be made without requiring access to the production equipment.

An example of production equipment is a subsea pipeline, and the first fluid comprises fluid hydrocarbons. In this case, the deposited material may include wax or hydrates precipitated from the fluid hydrocarbon. Furthermore, seawater may be pumped through the second conduit allowing subsea conditions to be simulated.

As an option, the method includes locating a heat exchanger upstream of the measuring device, the heat exchanger arranged to substantially match the temperature of the first fluid in the first conduit with first fluid in the production equipment.

As a further option, the method includes disposing an insulation material around the first conduit. This allows simulation of insulating conditions around the production equipment, such as the presence of insulation or burial in sand.

An optional method for determining the thickness in the first conduit is to provide a heat pulse to the first conduit using a heating element adjacent to the first conduit. A temperature of the first conduit is measured. After a predetermined time after the end of the heat pulse, a temperature of the first conduit is determined, the determined temperature is correlated with a thickness of deposited material.

An alternative optional method for determining the thickness in the first conduit is to provide a heat pulse to the first conduit using a heating element adjacent to the first conduit and obtain a plurality of temperature measurements of the first conduit over a predetermined time period. A set of temperature measurements is determined during a time period in which the temperature measurement fall, and a time constant is obtained from the set of temperature measurements. The time constant is then correlated with a thickness of deposited material. The time constant is optionally obtained from a logarithm of each temperature measurement of the set of temperature measurements.

As an option, the method further includes, prior to measuring a thickness of deposited material on the inner surface of the first conduit, stopping or reducing a rate of conveying of the second fluid through the second conduit.

The first and second conduits are optionally on a topside hydrocarbon production facility.

According to a third aspect there is provided a computer device for estimating a thickness of a deposited material on a surface of production equipment. The computer device includes a processor for controlling a rate of conveying a second fluid through a second conduit disposed adjacent to a first conduit for conveying a first fluid in order to simulate an environment around the production equipment. The processor is further arranged to determine a thickness of deposited material on an inner surface of the first conduit, wherein the measured thickness in the first conduit corresponds to an estimated thickness in the production equipment.

As an option, the processor is further arranged to control a temperature of a heat exchanger located upstream of a measuring device. The heat exchanger is arranged to substantially match the temperature of the first fluid in the first conduit with first fluid in the production equipment.

As an option, the processor is further arranged to control a heat pulse provided to the first conduit using a heating element adjacent to the first conduit. It can then obtain a temperature measurement at the first conduit after a predetermined time after the end of the heat pulse, determine a temperature of the first conduit, and correlate the determined temperature with a thickness of deposited material.

As an alternative option, the processor is further arranged to control a heat pulse provided to the first conduit using a heating element adjacent to the first conduit, obtain a plurality of temperature measurements of the first conduit over a predetermined time, determine a set of temperature measurements during a time period in which the temperature measurement fall, obtain a time constant from the set of temperature measurements, and correlate the time constant with a thickness of deposited material. As a further option, the processor is arranged to obtain the time constant from a logarithm of each temperature measurement of the set of temperature measurements.

The computer device optionally comprises a database correlating any of known times, time constants and temperatures with deposited material thicknesses.

According to a fourth aspect, there is provided a computer program comprising computer readable code which, when run from a computer readable medium in the form of a memory in a processor on a computer device, causes the computer device to behave as the computer device as described above in the third aspect. According to a fifth aspect, there is provided a computer program product comprising a non-transitory computer readable medium and a computer program as described above in the fourth aspect, wherein the computer program is stored on the computer readable medium.

BRIEF DESCRIPTION OF DRAWINGS

Figure 1 illustrates schematically a subsea pipeline between a sender facility and a receiver facility;

Figure 2 illustrates schematically a sea-water filled annulus disposed around a pipeline; Figure 3 illustrates schematically a sea-water filled annulus disposed around an insulated pipeline;

Figure 4 illustrates schematically a sea-water filled annulus disposed around a pipeline along with a heat exchanger;

Figure 5 illustrates schematically a pipeline having two measurement sections;

Figure 6 illustrates schematically a cross section view of heating elements and a sea- water filled annulus disposed around a pipeline;

Figure 7 is a graph showing temperature against time for different deposited wax thicknesses;

Figure 8 is a flow diagram showing steps in determining wax thickness;

Figure 9 illustrates schematically heat flux from a heating element around a measurement section of a pipeline;

Figure 10 illustrates schematically heat flux from a heating element around a measurement section of an insulated pipeline;

Figure 1 1 illustrates schematically heat flux from an insulated heating element around a measurement section of a pipeline;

Figure 12 is a flow diagram illustrating an exemplary embodiment; and

Figure 13 illustrates schematically in a block diagram an exemplary computer device. DETAILED DESCRIPTION

In order to avoid having to install measuring equipment on subsea production equipment, it is proposed to simulate a subsea environment on subsea production equipment and monitor deposition of materials. The techniques described below can be used for monitoring deposition of any kind of material in any kind of production equipment. For simplicity, the following description gives the example of the material being wax that precipitates from a fluid hydrocarbon such as oil, and the subsea production equipment being a production pipeline carrying the oil. However, it will be appreciated that the same techniques could be used for monitoring deposition of one or more solid materials in any kind of production equipment that carries one or more fluids.

Wax deposition is measured in the simulated environment, and these measurements can be used to estimate the degree of wax deposition in the subsea environment. In order to obtain an accurate estimate, it is important that the simulated environment has conditions as close as possible to those encountered in the subsea environment. Conditions to be considered include:

Same bulk oil temperature;

· Same pipeline inner wall temperature;

Same flow rate (for single-phase flow) and phase fractions (for multiphase flow); Same flow regime (in case of multiphase flow); and

Same diameter of pipeline. Figure 1 shows a subsea pipeline 1 connecting a sender facility 2 to a receiver facility 3. The subsea pipeline is predominantly located below the sea surface 4. Simulated environments (termed herein "measurement sections") 5, 6 may be located at the sender facility 1 and/or the receiver facility 3. Measurement section 5 is an upstream measurement section, and measurement section 6 is a downstream measurement section.

Turning to Figure 2, a downstream measurement section is illustrated. This is disposed above the surface 4 of the sea in order to facilitate installation. The measurement section comprises an annulus 7 disposed around a section of the pipeline 1 . The annulus is filled with seawater. A pump 8 is used to keep seawater circulating in the annulus 7 around the pipeline 1 . By adjusting the flow rate of the seawater, the same thermal conditions in measurement section 6 can be generated as are encountered in a subsea section of the pipeline 1 . The measurement section includes a pipe of the same diameter as the subsea pipeline 1 . By using the same oil flow as that in the subsea pipeline 1 the same flow conditions are ensured (for single- phase flow). Wax deposition in the measurement section 6 will therefore correspond to wax deposition in the subsea section of the pipeline, even where production conditions vary. Where the pipeline carries a multiphase flow, the measurement section must also have the same angle of inclination as the part of the subsea pipeline that is being simulated in order to ensure that the fluid flow in the measurement section 6 is fully developed.

Wax deposition is therefore measured in the measurement section 6 that simulates subsea conditions, and it can be assumed that the measured wax deposition will correspond to wax deposition in the subsea section of the pipeline that is being simulated.

Note that an upstream measurement section 5 would have similar features to those described above for the downstream measurement section 5.

Various modifications can be made to the measurement section. Referring to Figure 3, there is illustrated a similar measurement section 6 to that illustrated in Figure 2. In Figure 3, insulation 9 is disposed around the pipeline 1 in the measurement section 6 to simulate conditions in the subsea environment. For example, it the pipeline 1 is buried subsea then the surrounding material will insulate the subsea pipeline 1 , which will adjust the inner wall temperature. Insulation 9 is used to provide the same degree of insulation as the conditions of the pipeline 1 .

It is also appreciated that the temperature of the oil as it exits the subsea pipeline may not be the same as the temperature of the oil at the subsea pipeline that is being simulated. If the oil temperature at the measurement section 6 is different to the oil temperature at the point of the subsea pipeline 1 being simulated, then a heat exchanger 10 may be provided upstream of the measurement section, as illustrated in Figure 4. This is used to ensure that the oil temperature in the measurement section is the same as the oil temperature in the subsea section of the pipeline being simulated. Note that the embodiments shown in Figures 2 and 3 can be combined, so that both insulation 9 and a heat exchanger 10 are provided.

In some circumstances, it may be required to estimate the wax deposition at different points in the subsea pipeline that are subjected to different conditions (temperature, flow rate and so on). Figure 5 shows apparatus for handling this. In this case, a first measurement section is provided that includes a pump 8 for controlling the flow of seawater in the annulus 7, and a downstream heat exchanger 10 for controlling the temperature of the oil flowing through the measurement section 6. This allows simulation of the conditions at one point in the subsea pipeline 1 .

Furthermore, a second pump 12 is provided for circulating seawater around a second annulus 1 1 disposed around a further section of the subsea pipe 1 in the measurement section. The geometry of the pipe (angle of inclination, diameter, type and thickness of insulation etc.) may also need to be changed to correspond to the section of the pipeline 1 being simulated. A further heat exchanger 13 may also be provided to raise or lower the temperature of the oil to correspond to the conditions in the subsea section being simulated. It will be appreciated that any technique may be used to measure the thickness of wax deposition. By way of example, one such technique is described in WO2010/087724, and illustrated in Figure 6 in which heating elements 14 and temperature sensors 15 are disposed around the pipeline 1 in the measurement section 6. The heating element 14 is switched on for a short time (short enough not to melt the wax). After it has been switched off, the generated heat dissipates into the oil pipe 1 . Since wax is thermally insulating, any wax layer deposited on the inner wall of the pipeline 1 will delay the temperature decline. This delay in the temperature decline can be related to the thickness of the deposited wax layer, as shown in Figure 7. The temperature is measured at a certain time (400 seconds in the example of Figure 7) and from this the thickness of the wax deposit can be determined.

In some techniques, the temperature T(measurement) is obtained at a fixed time t(measurement), and this is converted to a wax thickness as shown in Figure 7. A disadvantage of this method is that any disturbances or noise in the temperature measurement are directly translated into the wax thickness.

It has been determined that the temperature decline can be accurately modelled using an exponential function, as shown in Equation 1 .

T(t) oc e^~f Eq. (1 ) Where T(t) is temperature after a certain time, t is time, and τ is a time constant that is a measure of the steepness of the decline and can thus be correlated with a wax thickness. Figure 8 shows the steps for obtaining an estimate of the wax thickness, with the following numbering corresponding to that of Figure 8.

S1 . Oil is allowed to flow through the pipeline 1 in the measurement section. It may be allowed to flow for some time to allow precipitated wax deposits to form on the inner wall of the pipeline 1 . S2. A pulse of heat at a known temperature and for a known time is applied to the pipeline 1 .

53. The temperature response after the heat pulse is measured to obtain a graph of temperature against time.

54. The portion of the graph in which the temperature is falling is used.

55. A logarithm of the falling part of the graph is taken. As the temperature decay is logarithmic, this leads to a linear plot of temperature as a function of time.

56. The gradient of the linear plot is determined to find the time constant.

57. The time constant is correlated with the wax thickness using a pre-determined look-up table. The look-up table is generated from a computer model taking into account the known geometry and thermal properties of the measurement section and varying oil bulk temperature and oil flow rate as parameters.

Figure 9 shows a cross section through a pipeline 1 wall having heating elements 14 disposed in the seawater annulus 7. Water 16 in the annulus flows in the direction shown by the arrow (although it will be appreciated that the flow of water may be in the same direction as the flow of oil), and is separated from the interior of the pipeline by a steel pipeline wall 17. On the opposite side of the wall 17 to the annulus 7, oil 18 flows in the direction shown by the arrow, and a layer of wax 19 has built up between the flow of oil 18 and the steel wall 17. The approach described above requires an annulus filled with seawater to simulate subsea conditions. As shown in Figure 9, a problem with this approach is that a significant part of the heat generated by the heating elements 14 is be used to warm up the water (Q(water)) and therefore does not travel through the wax layer into the oil (Q(oil)). This problem worsens with increasing wax deposit thickness, so the ratio between Q(water) and Q(oil) will increase. As the wax thickness builds up, it reaches a point where the measurement signal no longer changes with changing wax thickness because almost all of the energy provided by the heating elements 14 goes into the water annulus 7. This limits the use of the instrument to a certain upper wax thickness.

One way to mitigate this problem is to reduce or stop the flow of water 16 in the annulus 7 during the measurement procedure. This will reduce the heat transfer coefficient from the heating elements to the water 16, because the water is still, and so reduce Q(water).

An alternative or additional way to mitigate this problem is to empty the water annulus 7 of water 16 before the measurement process (e.g. by blowing pressurized air through the annulus 7). This reduces the heat transfer coefficient by 1 -2 orders of magnitude, correspondingly reducing Q(water) and thus increasing Q(oil) and the measurement accuracy.

The problem of reduced measurement accuracy due to heat loss to the annulus 7 becomes significantly larger if insulation 9 is applied to the outside of the steel pipeline wall 17, as shown in Figure 10. As described above, this insulation 9 may be used in order to simulate the same inner wall temperature inside the pipeline 1 as is present in the corresponding inner wall temperature in the subsea section of the pipeline 1 to be simulated. However this insulation 9 significantly reduces the heat flux Q(oil), thus restricting the measurable wax thickness. As shown in Figure 1 1 , this problem may be addressed by applying the insulation 9 on the outside of the heating elements 14 with respect to the pipeline 1 . In this way, the insulation 9 reduces the heat flux Q(water). The insulation thickness around the heating elements 14 must be adjusted to ensure that the total insulation effect is still the same as without the heating elements (so that the inner wall temperature is not changed). Turning now to Figure 12, a flow diagram shows steps of an exemplary embodiment. The following numbering corresponds to that of Figure 1 1 :

58. A pipeline in the topside measuring section is provided that has dimensions and/or an angle of inclination that corresponds to the dimensions and/or angle of inclination of the section of subsea pipeline to be simulated, and oil (or other hydrocarbons) flows through it.

59. Seawater is pumped through the annulus 7 around the measuring section. The rate of pumping is controlled to simulate as closely as possible the conditions at the subsea section of pipeline.

510. If necessary, a heat exchanger 10 is used to control the temperature of the oil flowing through the measuring section in order to ensure that the temperature is substantially the same as that of the oil flowing in the subsea section.

51 1 . If necessary, the pump 8 stops pumping seawater through the annulus 7, and the seawater in the annulus 7 may be evacuated. S12. The wax thickness in the measuring section is measured using any suitable technique, such as that shown in steps S1 to S7 of Figure 8.

In order to control the system and to determine the wax thickness in the measuring section, a computer device 20 is provided. An exemplary computer device is illustrated schematically in Figure 13.

The computer device 20 has a processor 21 that can be used to control the pump 8 and the heat exchanger 10 (and any additional pumps 12 and heat exchangers 13). The computer device 20 also has an in/out device 22 for communicating with the pump 8 and a further in/out device 23 for communicating with the heat exchanger 10. A further in/out device 24 is used to communicate with a measuring device 25 that provides a heat pulse to the measuring section and measures the temperature response of the pipeline in the measuring section. The processor 21 is also arranged to determine a thickness of deposited wax on an inner surface of the pipeline in the measuring section using a technique described above in Figure 8, or any other suitable technique. The thickness of wax in the measuring section corresponds to the thickness of wax in the subsea pipeline that is being simulated.

The computer device 20 may also be provided with a non-transitory computer-readable medium in the form of a memory 26. The memory 26 may be used to hold a database 27 that stores obtained data and correlations between time, temperatures, time constants, and wax thickness. The memory 26 may also be used to store a computer program 28 which, when executed by the processor 21 , causes the computer device to behave as described above. Note that the program 28 may be stored on an external non-transitory computer readable medium 29 such as a Compact Disk, a memory stick, a Digital Versatile Disk and so on.

It will be appreciated by a person of skill in the art that various modifications may be made to the embodiments described above without departing from the scope of the present disclosure. For example, the above description refers to wax deposits in a subsea pipeline arising from wax precipitating out from oil. It will be appreciated that the same techniques can be used to measure the thickness of deposition of any kind of material on any kind of production equipment, not limited to hydrocarbon production.

Claims

CLAIMS:

1 . A system for estimating a thickness of a deposited material on a surface of a production equipment, the system comprising:

a first conduit for conveying a first fluid, the first conduit having an inner and an outer surface and disposed at a remote location from the production equipment;

a second conduit disposed adjacent to the first conduit, the second conduit arranged to convey a second fluid to simulate an environment around the production equipment;

a measuring device arranged to measure a thickness of deposited material on the inner surface of the first conduit, wherein the measured thickness in the first conduit corresponds to an estimated thickness in the production equipment.

2. The system according to claim 1 or 2, wherein the production equipment is subsea hydrocarbon production equipment and the first fluid comprises a fluid hydrocarbon.

3. The system according to claim 2, wherein the production equipment is a subsea pipeline for conveying fluid hydrocarbons.

4. The system according to claim 2 or 3, wherein the deposited material comprises wax precipitated from the fluid hydrocarbon.

5. The system according to any one of claims 1 to 4, wherein the second fluid is seawater, the system further comprising a pump arranged to pump seawater through the second conduit.

6. The system according to any one of claims 1 to 5, wherein the second conduit forms an annulus around the first conduit.

7. The system according to any one of claims 1 to 6, further comprising a heat exchanger located upstream of the measuring device, the heat exchanger arranged to substantially match the temperature of the first fluid in the first conduit with first fluid in the production equipment.

8. The system according to any one of claims 1 to 7, further comprising an insulation material disposed around the first conduit.

9. The system according to any one of claims 1 to 8, wherein the measuring device comprises:

a heating element adjacent to the first conduit for providing a heat pulse to the first conduit; and

a temperature sensor for measuring a temperature of the first conduit, such that the temperature after a predetermined time after the end of the heat pulse can be correlated with a thickness of deposited material.

10. The system according to claim 9 where dependent upon claim 7, wherein the heating element is disposed between the insulation material and the first conduit.

1 1 . The system according to any one of claims 1 to 10, wherein the first conduit has any of the same dimensions and the same angle of inclination as the production equipment.

12. A method of estimating a thickness of a deposited material on a surface of a production equipment, the method comprising:

conveying a first fluid through a first conduit, the first conduit having an inner and an outer surface and disposed at a remote location from the production equipment; conveying a second fluid through a second conduit disposed adjacent to the first conduit to simulate an environment around the production equipment;

measuring a thickness of deposited material on the inner surface of the first conduit, wherein the measured thickness in the first conduit corresponds to an estimated thickness in the production equipment.

13. The method according to claim 12, wherein the production equipment is a subsea pipeline and the first fluid comprises fluid hydrocarbons.

The method according to claim 13, wherein the deposited material comprises precipitated from the fluid hydrocarbon.

15. The method according to any one of claims 13 or 14, the method comprising pumping seawater through the second conduit.

16. The method according to any one of claims 12 to 15, further comprising a heat exchanger located upstream of the measuring device, the heat exchanger arranged to substantially match the temperature of the first fluid in the first conduit with first fluid in the production equipment.

17. The method according to any one of claims 12 to 16, further comprising disposing an insulation material around the first conduit.

18. The method according to any one of claims 12 to 17, the method comprising: providing a heat pulse to the first conduit using a heating element adjacent to the first conduit;

measuring a temperature of the first conduit;

after a predetermined time after the end of the heat pulse, determining a temperature of the first conduit; and

correlating the determined temperature with a thickness of deposited material.

19. The method according to any one of claims 12 to 17, the method comprising: providing a heat pulse to the first conduit using a heating element adjacent to the first conduit;

obtaining a plurality of temperature measurements of the first conduit over a predetermined time;

determining a set of temperature measurements during a time period in which the temperature measurement fall;

obtaining a time constant from the set of temperature measurements; and correlating the time constant with a thickness of deposited material.

20. The method according to claim 19, wherein the time constant is obtained from a logarithm of each temperature measurement of the set of temperature measurements.

21 . The method according to any one of claims 12 to 20, further comprising, prior to measuring a thickness of deposited material on the inner surface of the first conduit, stopping or reducing a rate of conveying of the second fluid through the second conduit.

22. The method according to any of one of claims 12 to 21 , further comprising locating the first and second conduits on a topside hydrocarbon production facility.

23. A computer device for estimating a thickness of a deposited material on a surface of a production equipment, the computer device comprising

a processor for controlling a rate of conveying a second fluid through a second conduit disposed adjacent to a first conduit for conveying a first fluid in order to simulate an environment around the production equipment;

the processor being further arranged to determine a thickness of deposited material on an inner surface of the first conduit, wherein the measured thickness in the first conduit corresponds to an estimated thickness in the production equipment.

24. The computer device according to claim 23, wherein the processor is further arranged to control a temperature of a heat exchanger located upstream of a measuring device, the heat exchanger arranged to substantially match the temperature of the first fluid in the first conduit with first fluid in the production equipment.

25. The computer device according to any one of claims 23 or 24, wherein the processor is further arranged to control a heat pulse provided to the first conduit using a heating element adjacent to the first conduit, obtain a temperature measurement at the first conduit, after a predetermined time after the end of the heat pulse, determine a temperature of the first conduit, and correlate the determined temperature with a thickness of deposited material.

26. The computer device according to any one of claims 23 or 24, wherein the processor is further arranged to control a heat pulse provided to the first conduit using a heating element adjacent to the first conduit, obtain a plurality of temperature measurements of the first conduit over a predetermined time, determine a set of temperature measurements during a time period in which the temperature measurement fall, obtain a time constant from the set of temperature measurements, and correlate the time constant with a thickness of deposited material.

27. The computer device according to claim 26, wherein the processor is arranged to obtain the time constant from a logarithm of each temperature measurement of the set of temperature measurements.

28. The computer device according to any one of claims 25, 26 or 27, further comprising a database correlating any of known times, time constants and temperatures with deposited material thicknesses.

29. A computer program comprising computer readable code which, when run from a computer readable medium in the form of a memory in a processor on a computer device, causes the computer device to behave as the computer device as claimed in any one of claims 23 to 28.

30. A computer program product comprising a non-transitory computer readable medium and a computer program as claimed in claim 29, wherein the computer program is stored on the computer readable medium.