NO343738B1 - Method for establishing an estimate of bending moment over time in a subsea well and an article of manufacture - Google Patents

Description

FIELD OF THE INVENTION

[0001] The present invention relates to monitoring of wellhead fatigue. More specifically, the invention relates to a method for establishing an estimate of bending moment over time in a subsea well and an article of manufacture.

BACKGROUND

[0002] Wellhead systems in the North Sea and other places are frequently subjected to large bending loads, due to shallow waters, heavy seas and semi-submersible drilling rigs. This makes fatigue of wellhead systems a challenge.

[0003] The common way of analyzing wellhead fatigue on the Norwegian offshore sector is to combine a detailed finite element model of the well with loads from a riser model. It is quite common for these analyses to produce fatigue results which indicate a short fatigue life. Although few deliberately conservative assumptions are made when in these analyses are implemented, it is often believed that the response is overestimated at low sea states and in high frequency modes. The discrepancies between the short estimated fatigue lives of well systems and the operational experience with wells that seldom fails, creates distance between the analytical and the operational environments. It is important to understand that 100% utilization of the allowable fatigue damage does not mean that the well is likely to fail.

However, the probability of failure is larger than acceptable above this criterion.

[0004] The opposite approach to a full riser simulation is to measure wellhead loads with strain gauges or similar sensors such as linear variable differential transformers. This is the most accurate method, provided that the system is well calibrated. Equipping blowout preventers with strain gauges or linear variable differential transformers (LVDTs) is, however, a complex and expensive operation. Durability, especially for the cabling of the system, is a frequent source of error.

[0005] Consequently, there is a need for alternatives that provide better information about the actual state of wellhead fatigue than simulations, but that are less complex and more cost effective than measurements using strain gauges.

SUMMARY OF THE INVENTION

[0006] The fatigue estimates of subsea wellhead systems are often conservative when based on global finite element riser simulations. To reduce the conservatism from such simulations, measurements of the actual wellhead loads have been performed on certain occasions. This is often a costly and intricate process that usually requires a subsea cable from the rig. The present invention provides an alternative method for measuring wellhead loads by the use of autonomous motion sensors, for example inertial measurement units (IMUs) and/or other sensors or combination of sensors such as accelerometers and gyroscopes, on the blowout preventer and the lower end of the drilling riser.

[0007] Inclinations from an IMU on a riser can be used to capture the loads acting on the blowout preventer from the riser. The accelerations, angular rates and inclinations from the sensor on the blowout preventer can be used to capture the dynamic response of the blowout preventer and well system. The combination of the excitation force, estimated from measurements, and the measured dynamic behavior, makes it possible to reliably estimate the wellhead bending moment, without the use of analysis models.

[0008] Accordingly, a method for establishing an estimate of bending moment over time in a subsea well has been provided. The method includes receiving sensor data from a first motion sensor unit which is provided at a blowout preventer, below the lower flex joint of the wellhead, and a second motion sensor unit which is provided at a riser, above a lower flex joint of the wellhead, determining a time series of values related to an inclination of the blowout preventer, θBOP(t), from the data received from the first motion sensor unit, determining a time series of values related to an inclination of the riser, θRiser(t), from the data received from the second motion sensor unit, determining a value related to a stiffness of the wellhead, KWH, from the respective time series, and determining a time series of values related to a wellhead bending moment, MWH(t), from the value related to the blowout preventer inclination, θBOP(t), and the value related to the stiffness of the wellhead KWH.

[0009] According to the invention, the value related to stiffness of the wellhead may be determined by calculating a time series for quasi-static bending moment using the expression

the determined times series for inclination of the blowout preventer, θBOP(t), and the determined time series for inclination of the riser, θRiser(t), performing a Fast Fourier Transformation of the calculated time series for quasi-static bending moment and the time series for the blowout preventer inclination, θBOP(t), to determine amplitude at mode I for the quasi-static bending moment, %&'(), and the inclination of the blowout preventer, %*+,-, and estimating the stiffness as

[0010] In some embodiments of the invention, the time series of values related to the wellhead bending moment, MWH(t) is determined by multiplying a time series of values related to the inclination of the blowout preventer, θBOP(t), with the value related to the stiffness of the wellhead, KWH.

[0011] According to another aspect of the invention the method for establishing an estimate of bending moment over time in a subsea well can be used for performing a measurement campaign in order to monitor wellhead fatigue in subsea wells. This method includes providing a first motion sensor on a blowout preventer, below a lower flex joint of the subsea well, providing a second motion sensor on a riser, above a lower flex joint of the subsea well, storing motion sensor data from the first and the second motion sensors in a logging unit, transferring the motion sensor data from the logging unit to a computer using a communication link, using the computer to determine a value related to a stiffness of the wellhead from the motion sensor data from the first and the second motion sensors, using the computer to determine a time series of wellhead bending moment from the determined value related to stiffness and a time series of sensor data from the first motion sensor, and using the computer to determine an estimate for wellhead fatigue based on the time series of wellhead bending moment.

[0012] In embodiments of the invention, motion sensor data from the first motion sensor is a measurement of, or can be used to calculate a measurement of an inclination of the blowout preventer, and motion sensor data from the second motion sensor is a measurement of, or can be used to calculate a measurement of an inclination of the riser.

[0013] The logging unit may be integral to at least one of the first and the second motion sensor or it may be a separate device connected to the first and the second motion sensor. The step of transferring the motion sensor data may then include transporting a communication link device to the vicinity of the logging unit with a remote operated underwater vehicle, establishing a communication link between the communication link device and the logging unit, and transferring the sensor data from the logging unit to the communication link device.

[0014] In some embodiments, the sensor data is temporarily stored in the communication link device and transferred to the computer after the communication link device has been returned to the surface. Alternatively, the sensor data may be transferred from the communication link device to the computer using a wire in an umbilical of the remote operated underwater vehicle.

[0015] The estimate for wellhead fatigue can be determined in a number of ways. In some embodiments, fatigue is determined by comparing the time series of wellhead bending moment to a predetermined maximum allowable bending moment for the wellhead. Fatigue may also be determined by calculating fatigue damage from the bending moment time series. In some embodiments, this is done by running the time series through a cycle counting algorithm, and for each cycle size, comparing the number of cycles to a predetermined allowable number of cycles.

[0016] In another aspect of the invention, a system for monitoring fatigue in subsea wells has been provided. The system may include a first motion sensor device which is configured to be provided at the blowout preventer, below the lower flex joint, a second motion sensor device configured to be provided on a riser, above a lower flex joint, a communication link device, and a computing device. The communication link device may be configured to receive motion sensor data from the first and the second motion sensor device and transmit the sensor data to the computing device, and the computing device may be configured to determine a value related to a stiffness of the wellhead from the motion sensor data from the first and the second motion sensors, determine a time series of wellhead bending moment from the determined value related to stiffness and a time series of sensor data from the first motion sensor, and determine an estimate for wellhead fatigue based on the time series of wellhead bending moment.

[0017] In some embodiments of the invention, the communication link device includes a logging unit to be provided at the wellhead and configured to receive sensor data from the first motion sensor device and the second motion sensor device, after which it may be transported to the surface to be connected to the computing device and to transmit the sensor data to the computing device.

[0018] In other embodiments of the invention, a logging unit may be provided at the surface and connected to the computing device. The communication link device may then be a wired communication link connected to the first and the second motion sensor device and to the logging unit at the surface, and the logging unit may be configured to receive and store sensor data from the first motion sensor device and the second motion sensor device and to transfer the sensor data to the computing device.

[0019] A system according to the invention may include different types of motion sensor devices. In some embodiments the motion sensor devices may include at least one of an accelerometer, a gyroscope, and an inclinometer. In some embodiments of the invention the first and the second motion sensor devices include an accelerometer and a gyroscope as well as a complementary filter. Low frequency components of motion may then be obtained from the accelerometer and high frequency components of the motion may be obtained from a single integration of the gyroscope data, and the two signals may be combined using the complementary filter.

[0020] The sensor devices may include a controller unit configured to perform digital signal processing implementing the single integration of the gyroscope data and the complementary filter.

[0021] In another aspect of the invention, an article of manufacture including an electronically accessible medium, such as for example a flash drive, a CD-ROM, or a magnetic storage unit, is provided. The electronically accessible medium may include instructions that that, when executed by one or more processors, cause one or more electronic systems to receive sensor data from a first motion sensor unit which is provided at a blowout preventer, below the lower flex joint of the wellhead, and a second motion sensor unit which is provided at a riser, above a lower flex joint of the wellhead, determine a time series of values related to an inclination of the blowout preventer, θBOP(t), from the data received from the first motion sensor unit, determine a time series of values related to an inclination of the riser, θRiser(t), from the data received from the second motion sensor unit, determine a value related to a stiffness of the wellhead, KWH, from the respective time series, and determine a time series of values related to a wellhead bending moment, MWH(t), from the value related to the blowout preventer inclination, θBOP(t), and the value related to the stiffness of the wellhead KWH.

[0022] The stiffness of the wellhead is determined by calculating a time series for quasi-static<bending moment using the expression>

the determined times series for inclination of the blowout preventer, θBOP(t), and the determined time series for inclination of the riser, θRiser(t), and by performing a Fast Fourier Transformation of the calculated time series for quasi-static bending moment and the time series for the blowout preventer inclination, θBOP(t), to determine amplitude at mode I for the quasi-static bending moment, AMWHo, and the inclination of the blowout preventer, AθBOP. The stiffness may then be estimated as .

[0023] The time series of values related to the wellhead bending moment, MWH(t), can be determined by multiplying a time series of values related to the inclination of the blowout preventer, θBOP(t), with the value related to the stiffness of the wellhead, KWH.

BRIEF DESCRIPTION OF THE DRAWINGS

[0024] Embodiments of the invention will now be described with reference to the drawings, in which like reference numerals denote the same or corresponding elements, and in which:

[0025] FIG. 1 shows an example of a subsea oil or gas installation;

[0026] FIG. 2 shows correlation between bending moment and inclination of a blowout preventer;

[0027] FIG. 3 is a graph illustrating gain of complementary filters used for processing accelerometer and gyro measurements to inclinations;

[0028] FIG. 4 shows forces contributing to wellhead bending moment;

[0029] FIG. 5 shows a riser model used in simulations;

[0030] FIG. 6 is a graph illustrating spectra of BOP inclinations and quasi-static bending moment formula from analysis;

[0031] FIG. 7 is a graph illustrating the ratio between BOP inclination and applied load;

[0032] FIG. 8 is a graph showing true wellhead bending moment and estimated wellhead bending moment from riser simulation based on the invention;

[0033] FIG. 9 is a graph showing spectra of BOP inclinations and quasi-static bending moment formula from measurements;

[0034] FIG. 10 is a graph illustrating true wellhead bending moment and estimated wellhead bending moment with measurement data based on the invention;

[0035] FIG. 11 is a flowchart illustrating a method according to the invention;

[0036] FIG. 12 is a subsea installation of a system according to the invention;

[0037] FIG. 13 is an illustration of the external configuration of a sensor device according to the invention; and

[0038] FIG. 14 is a block diagram of the internal components of a sensor device according to the invention.

DETAILED DESCRIPTION

[0039] In the following description of various embodiments, reference will be made to the drawings, in which like reference numerals denote the same or corresponding elements. The drawings are not necessarily to scale. Instead, certain features may be shown exaggerated in scale or in a somewhat simplified or schematic manner, wherein certain conventional elements may have been left out in the interest of exemplifying the principles of the invention rather than cluttering the drawings with details that do not contribute to the understanding of these principles.

[0040] It should be noted that, unless otherwise stated, different features or elements may be combined with each other whether or not they have been described together as part of the same embodiment below. The combination of features or elements in the exemplary embodiments are done in order to facilitate understanding of the invention rather than limit its scope to a limited set of embodiments, and to the extent that alternative elements with substantially the same functionality are shown in respective embodiments, they are intended to be interchangeable, but for the sake of brevity, no attempt has been made to disclose a complete description of all possible permutations of features.

[0041] Furthermore, those with skill in the art will understand that the invention may be practiced without many of the details included in this detailed description. Conversely, some well-known structures or functions may not be shown or described in detail, in order to avoid unnecessarily obscuring the relevant description of the various implementations. The terminology used in the description presented below is intended to be interpreted in its broadest reasonable manner, even though it is being used in conjunction with a detailed description of certain specific implementations of the invention.

[0042] Reference is first made to FIG. 1 which shows a diagram of a subsea well 10 established on the ocean floor 1 and extending into the soil 2 of the sea bottom 1. The subsea well installation includes a wellhead 12, a blowout preventer (BOP) 14, a lower marine riser package (LMRP) 16, and a lower flex joint (LFJ) 18. A drilling riser 20 connects the well 10 to a drilling rig 30. The riser 20 is connected to the LFJ 18 at the well 10 and to a slip joint 32 on the surface side.

[0043] When a drilling rig 30 is subjected to heavy seas, wave-induced motion will be transferred down the riser to the wellhead 12, subjecting the components on the ocean floor to stress and fatigue, particularly at critical connections and welds.

[0044] Based on several measurement campaigns, it has been realized that there is a strong correlation between the bending load on the wellhead and the inclination of the BOP. FIG. 2 shows these two measurements plotted against each other. It will be seen that they create a narrow line indicating a linear correlation between the two.

[0045] From these observations, the wellhead bending moment can be expressed as a constant multiplied with the BOP inclination. This constant (KWH) will be referred to as the well stiffness.

[0046] Provided that the well stiffness is known, measurement of the BOP inclination can be used to estimate the bending moment, which again can be used to monitor well fatigue. The invention provides a method for finding an estimate of the well stiffness and using this estimate together with inclination measurements to monitor such fatigue.

[0047] In accordance with the principles of the present invention, inclination of the BOP can be measured with an inclinometer. Otherwise, motion sensor without the capabilities of measuring rotation directly can be combined with the known geometry of the subsea installation in order to calculate the inclination. Several types of motion sensors are known in the art, for example accelerometers, gyroscopes, magnetometers etc. In embodiments of the invention only one type of sensor is used, for example only an accelerometer or only a gyroscope. However, increased accuracy can be obtained by using a combination of several sensors, which is typical for most IMUs. In the following description, the motion sensors will be described as IMUs with the ability of providing accelerometer data as well as gyroscope data. This is not intended to be limiting on the invention, which equally well may use only one type of sensor, or other combinations of sensors provided that the data obtained are sufficient to calculate an estimate of the inclination of the BOP and the riser.

[0048] Deriving inclinations from IMU data is a robust method with little processing required. To get inclinations from the IMU data, an accelerometer can be used to obtain the low frequency components of the inclinations, and the gyro data is integrated once to represent the high frequency components. The two signals can be combined using a complementary filter, an example of which is illustrated in FIG. 3.

[0049] The effective well stiffness (KWH) is the other key parameter in determining the wellhead bending moment and thus in monitoring well fatigue. Obtaining this value from analysis is associated with large uncertainties related to both soil stiffness and template support, making it difficult to obtain a good value for the well stiffness analytically.

[0050] To avoid these uncertainties in this important parameter, and in accordance with an aspect of the present invention, wellhead stiffness can be estimated with the help of measurement data. In one embodiment of the invention, one motion sensor is provided above the LFJ and one sensor is provided on the BOP in order to obtain data which can be used to estimate the well stiffness. A method for determining well stiffness based on these data will be described in further detail below.

[0051] FIG. 4 shows an embodiment of a device, wherein a first motion sensor SBOPis provided on the BOP 14 of a subsea well 10 (see Fig.1) and a second motion sensor SRiseris provided on the drilling riser 20. The sensors SBOPand SRisermay respectively comprise an accelerometer and/or a gyroscope. A gyroscope can for example be based on MEMS technology. Alternatively, a fiber optic gyroscope may be used. An accelerometer may also be based on MEMS technology, but other alternatives are well known in the art.

[0052] Examples of commercially available sensors that may be used in the implementation of the present invention include the Smart Motion Sensor SMS-3000AWG delivered by Sense Offshore AS of Trondheim, Norway. SMS-3000AWG measures motion with six degrees of freedom, including 3-axis accelerometer and 3-axis gyroscope. These sensors also include logging memory and wireless communication interface. Other sensors from the Smart Motion Sensor series may also be used in embodiments of the invention.

[0053] The sensor devices will be described in further detail below.

[0054] A number of variables are illustrated in FIG. 4. Some of them are known in advance, others can be extracted from the data provided by the motion sensors. The variables can be used to determine the bending moment on the wellhead. For static conditions, the wellhead bending moment can be expressed as:

Where:

MLFJ- LFJ moment, obtained from non-linear LFJ stiffness data, which can be provided by the manufacturer, and relative angle

T - Tension in marine riser (and drill pipe) right above LFJ. This can be provided from the rig.

V - Shear force in marine riser just above LFJ

WBOP- Weight BOP and LMRP, which are part of the rig data

H - Height from wellhead to LFJ and COG

- Angle of the riser relative to the BOP

- Angle of the BOP relative to the vertical axis (or the central axis of the wellhead when no bending load is applied)

[0055] The shear force in the riser (V) can be estimated from the Euler beam equation for a tensioned beam with end moment at x=0:

[0056] E is the elastic modulus, which is a property of the riser, and I is the second moment of area is a geometrical property of the riser’s cross section.

[0057] The shear force from the riser is an important contributor to the bending load on the wellhead. For the rig and water depth used in the simulation example described below, the total shear force on the LMRP/BOP is 60% from riser tension and 40% from riser end shear force.

[0058] The wellhead bending moment equation is valid for quasi-static conditions and requires that riser and BOP inclination is in phase. The riser’s first mode usually contains the lowest frequency content of the measured signal, making it the least influenced by the BOP and Well’s natural frequency. At this mode, the riser and bop are in phase, and little dynamic amplification of the wellhead bending moment is present.

[0059] The data provided from the two sensors SBOPand SRiserrepresent a times series of measurements for the two angles θRiser(t) and θBOP(t). These can be used to obtain a time series for the wellhead bending moment, MWHo(t). The amplitudes, A, at mode I can be extracted from these time series by performing a FFT of θΒΟΡ( t) and MWHo(t ), respectively. The location of mode I will usually be apparent in the spectrum. The isolated mode I signals can then be expressed as:

[0060] The linear correlation between wellhead bending moment and BOP inclination described above provides the following expression for the well stiffness:

[0061] In some cases, at shallow water depths, the mode I frequency is high enough to be influenced by the resonance frequency of the BOP and well. Solving the dynamic equation in the frequency domain provides the following expression for the stiffness.

Where ξ is the damping ratio and r and is defined as:

[0062] Tnis the natural period of the BOP stack and 7<’>is the period of the isolated signal. In this case the period of mode I.

[0063] In most cases, the mode I period is so much higher than the natural period of the well and BOP, that the dynamic amplification (DAF) does not make much of a difference to the wellhead stiffness estimate. Assuming no damping, ξ = 0, is acceptable in most cases. Damping can be estimated from the width of the excitation force/BOP angle spectrum, but assuming no damping results in a conservative estimate. The natural period can normally be extracted from the spectra of the ratio between BOP and loading. If this is not feasible, it can be estimated analytically. Again, the resulting stiffness estimate is not sensitive to this.

[0064] Finally, when the well stiffness is established, the wellhead bending moment time series can be generated by multiplying the BOP inclination time series with the well stiffness.

[0065] The accuracy of the methodology described above has been demonstrated in a finite element riser simulation. The model acts as a controlled environment where both input parameters and wellhead loads are known. The sensor data is extracted from the analysis at the relevant locations, run through the proposed methodology and then compared with the wellhead loads in the model.

[0066] The model represents a controlled environment, where both system parameters and the wellhead bending moment are known. The measurement data is simulated by extracting accelerations and rotational rate at the senor locations.

[0067] A riser model was created for the specific field and rig used in the measurement campaign, as illustrated in FIG. 5. The well was modeled as a rigid stick with a rotational spring located at the seabed. The water depth is 130m and the BOP stack is equipped with a 5k Oilstate lower flex joint.

[0068] FFT was performed on the quasi-static bending moment and the BOP inclinations and is presented in FIG. 6. The amplitudes at mode I (8.74s) are extracted and inserted in the formula below. The ratio between bop inclination and the applied loading#reveals a resonance period of 1.29 seconds as shown in FIG. 7. The dynamic amplification from these values without any damping is 1.02 and confirm that the results are not sensitive to the resonance of the BOP and well, even for shallow waters like this.

[0069] The error of the estimate was estimated from the ratio between the standard deviation of the estimated and true bending moment.

[0070] The time series of the estimated and true wellhead bending moment from the analysis is shown in FIG. 8. The small underestimation of the bending moment was mainly caused by an underestimation of the shear force in the riser, which is also apparent for static rig offset simulations in the model.

[0071] As a final verification, the method has been tested on data from an actual measurement campaign where both IMU and wellhead load measurements are available. The wellhead loads were calculated based on the method described above and IMU data, and the loads were compared with the data from the wellhead load sensors. Thus, measurements from a monitoring campaign containing both motion sensors and strain based bending moment sensors have been used to verify the methodology.

[0072] It will be realized that this was not a controlled environment, and that uncertainties related to system properties and the measurements do exist.

[0073] The sea state during these measurements were the same as the one simulated in the simulated sensor data described above.

[0074] FFT of the quasi-static bending moment and the BOP inclinations were performed and the results are shown in FIG. 9. The amplitudes at mode I (8.74s) were extracted and inserted in the formula for wellhead stiffness described above. The dynamic amplification of the BOP angle in FIG. 10, reveal a resonance period at 8.74s.

[0075] The estimated bending moment together with the measured bending moment is shown in FIG 11. The error estimate, based on the standard deviations of the estimated and true time series, show a good fit, with 4% underestimation.

[0076] Having thus described the method and theoretical basis for the invention, and illustrated its usefulness, a summary will now be given with reference to the flow chart in FIG. 11. In a first step 1101, one sensor device must be provided above and one below the lower flex joint (LFJ) as described above. Following installation of the sensors, a measurement campaign is executed in order to provide the necessary sensor data. In step 1102, sensor data are received from motion sensors and stored in one or more logging units which may be part of one or both sensors, or part of a separate unit connected to the motion sensors. In some embodiments of the invention, sensors may already be in place at adequate positions, in which case the method starts with the receipt and storage of measurement data in step 1102. In a next step 1103, the sensor data are transported to the surface. This may be done in a number of ways, for example by bringing the sensors (or the separate logging unit) to the surface after the measurement campaign has been completed, or by transferring the data over a communication link to the surface during operation. In some embodiments of the invention, the data can be fetched by a communication link device carried by a remote operated underwater vehicle and configured to establish a wireless link with at least one of the sensors (or with a separate logging unit or bus master unit) when in the vicinity of that sensor, as will be described in further detail below.

[0077] In some embodiments of the invention, the logging unit is on the surface, in which case step 1103 will be performed before step 1102. However, in many cases a permanent link to the surface is undesirable, expensive, slow, and prone to damage.

[0078] When a sufficiently large dataset has been brought to the surface, well stiffness can be calculated in steap 1104, as described above. The calculation is based on measurement data representing the BOP and riser angles, or measurement data from which these angles can be derived, as well as a number of parameters relating to the installation, as described above. The calculation of stiffness is then performed using an expression for calculating wellhead bending moment under quasi-static conditions as described above.

[0079] In a next step 1105 the calculated stiffness, KWH, is combined with the time series for the BOP angle, θBOP(t), to provide a bending moment time series. The bending moment time series can be calculated using the expression presented above and repeated here for convenience,

[0080] In a final step 1106 the bending moment time series is used to determine fatigue. This can be done in a number of ways. For example, the bending moment time series can be compared with the maximum allowable bending moment for the wellhead system to find the structural utilization of the system. The bending moment time series can also be used to calculate fatigue damage of the wellhead system. A standard approach for calculating the fatigue damage is by running the time series through a cycle counting algorithm and then for each cycle size, comparing the number of cycles with the allowable number of cycles. The curve of allowable number of cycles for each bending moment size is often referred to as an M-N curve. Such curves can be established for a wellhead system by applying standard analysis methods and fatigue curves from international codes and standards.

[0081] In some embodiments of the invention, the bending moment time series may in itself be the desired output of the method, in which case the method stops after step 1105.

[0082] Reference is now made to FIG. 12, which illustrates a system configured to operate in accordance with the principles of the invention. A subsea well 10 is established on the ocean floor 1 and extending into the soil 2 of the ocean floor 1. The subsea well installation includes a wellhead 12, a blowout preventer (BOP) 14, a lower marine riser package (LMRP) 16, and a lower flex joint (LFJ) 18. A drilling riser 20 connects the well 10 to a drilling rig (not shown). The riser 20 is connected to the LFJ 18.

[0083] A first sensor device 40 is attached to the subsea installation, in this case to the LMRP 16 just below the LFJ 18. In addition to the first sensor device 40, an additional sensor device 41 is provided on the riser 20 just above the LFJ 18.

[0084] The additional sensor device 41 may be connected to the first sensor device 40 using a wired connection 42, for example in accordance with the ANSI standard RS-485 (also known as TIA-485), and for that purpose each sensor device 40, 41 may have at least one wired communication port in accordance with that standard. At least one of the sensor devices, for example the first sensor device 40, may in addition have a wireless communication port, as will be described in further detail below, along with further details of the individual sensor devices.

[0085] A communication link device 50 is configured to be carried by a remote operated underwater vehicle (ROV) 52. The ROV 52 is controlled from the surface over an umbilical 54.

[0086] When the communication link device 50 is brought to the vicinity of the first sensor device 40, a wireless communication link can be established with the first sensor device over corresponding wireless communication ports in the first sensor device 40 and in the communication link device 50. The communication ports may communicate using infrared (IR), for example at 890 nm, although other possibilities may be contemplated, including laser and acoustical waves and even radio waves, due to the short range between the sensor device 40 and the link device 50 when wireless communication is established. Using IR, the range may be between 0.5 and 1.0 m with a bit rate of 57,600 bps.

[0087] The communication link device 50 includes a wired communication port which enables communication with a computer. A controller, for example a CPU, is configured to control the communication ports and any local memory in the communication link device 50 to establish the wireless connection when the first sensor device 40 is sufficiently close, to receive sensor data over the established wireless communication link, and to transmit the data over the wired communication port to the computer.

[0088] According to a first embodiment, a wired communication link is established over a cable included in the ROV umbilical 54, and data is transferred to the computer as it is received by the communication link device 50, although some or all of the data may be buffered locally in a memory in the communication link device 50 before it is transmitted.

[0089] According to another embodiment, the communication link device 50 includes a memory configured to hold all the received sensor data until the link device 50 is brought to the surface to be connected to a computer over the wired communication port.

[0090] In some embodiments the communication link device is capable of operating in both modes.

[0091] The wired communication port may be another RS-485 port, but other possibilities exist. For data transfer subsequent to retrieved of the communication link device 50 to the surface, possibilities that cannot be used while submerged include USB, and additional wireless ports can also be provided, such as Bluetooth, Zigbee, WiFi and others.

[0092] Reference is now made to FIG. 13, which is an illustration of the external configuration of a sensor device which can be used in embodiments of the invention. The device 40 includes a casing 43 which holds the electronic components. The casing 43 may be made from stainless steel and sealed by O-rings. An optical window 44, which may be made from polycarbonate, is provided in order to enable establish wireless communication with the IR communication port inside the casing. The optical window 44 may be configured such that refraction is minimized and such that light received from the outside is concentrated in front of the IR receiver on the inside in order to increase receiver sensitivity and thus operating range.

[0093] In embodiments where the wireless communication ports are not optical, the optical window may be replaced by components required for the type of wireless communication link used, as will be readily understood by those with skill in the art.

[0094] A first waterproof connector 45 provides the physical communication interface of a first wired communication port, for example using the RS-485 standard, which can be used to establish communication with additional sensors 41. This communication port can be configured to receive sensor data from the additional sensor devices 41 in order to forward them to a communication link device 50 over the wireless communication link. In addition to sensor data, the port may also be used to transfer instructions and configuration parameters, as well as clock related information for synchronization purposes.

[0095] Another waterproof connector 46 may also be provided. This connector may be the physical interface of a communication port 46 used to establish a permanent communication link to the surface, for example by being connected to an acoustical modem (not shown). Alternatively, in some embodiments, this communication port may be connected to additional sensor devices 41, providing additional configuration options.

[0096] In some embodiments one or both connectors 45, 46 may also be used to deliver power from the batteries in the sensor device 40 to an external device, or from an external device to the sensor device 41.

[0097] A wire loop 47 is provided at the top end of the casing 43. The wire loop provides an easy way to handle the sensor device 40 using the ROV 52 if it should be necessary to remove the sensor device 40 from its receptacle (not shown) in order to replace it or bring it back to the surface for downloading of data, provide service such as battery replacement, and bring it back to the subsea installation.

[0098] Finally, the casing 43 may include a guiding pin facilitating correct placement in the receptacle, and a sacrificial zinc anode protecting the sensor device 40 from corrosion.

[0099] The receptacle, which is not illustrated in the drawing, may be funnel shaped and permanently attached to the subsea installation at a location which it is desirable to monitor motion.

[0100] The additional sensor devices 41 may have all the external features described above. However, if the additional sensor devices 41 lack some functionality, some features may be omitted, for example the optical window 44 or one of the physical connectors 45, 46.

[0101] Turning now to FIG. 14, the internal electronic components of a sensor device 40 consistent with the principles of the invention will be described.

[0102] A sensor device according to the embodiment illustrated in FIG. 14 includes a first accelerometer 81 capable of measuring acceleration along three axes and a first gyroscope 82 capable of measuring rotation around three axis. One or more communication ports 83 are provided as well as a logging unit 84 and a wireless communication port 85. A controller, for example a CPU, is configured to receive sensor data from the accelerometer 81 and the gyroscope 82, to store sensor data in the logging unit 84, and transmit sensor data over the wireless communication port 85.

[0103] The accelerometer 81 may, as already mentioned, be based on MEMS technology and configured to measure acceleration along three axes. The accelerometer 81 can be configured with a measurement range of /-2 g, which makes the sensor well suited for measuring the gravity component, and thus be used as an inclinometer. When used as an inclinometer to measure Pitch and Roll at 10 Hz sampling rate (5 Hz bandwidth), the noise level (weakest signal that can be measured) has been found to be in the order of 0.04 degrees (rms).

[0104] The accelerometer 81 can be configured to measure acceleration up to /-16g and can thus be used for other applications such as vibrations and shock effects.

[0105] The gyroscope 82, which in one embodiment is based on MEMS technology, may be configured with a default measuring range of /-250 deg/sec. In many applications, the ability to measure slow moving objects such as platform, risers, BOP etc., is very important. The noise level of the gyroscope when sampling at 10 Hz (5Hz bandwidth) has been found to be the order of 0.015 º/s rms. Other technologies known in the art, such as fiber optic gyroscope technology, may also be used

[0106] One communication port 83 is illustrated in FIG. 8, but in some embodiments, there may be several. The communication port 83 is connected to an external connector 45, 46 and is configured to transmit and/or receive sensor data.

[0107] In some embodiments, the bitrate is set to 57,600 bps, and the communication is half duplex (transmission and reception cannot take place simultaneously). In some embodiments the sensor device may be powered through this port with a voltage between 5V and 24V. An internal batter in the sensor (not shown) will not be in use when the sensor device is supplied through this port, even though the battery is connected.

[0108] Several design options are available regarding the number of wired communication ports. According to one embodiment, one port is used to transmit data to the surface, for example by connecting the port to an acoustical modem, or even bringing a cable all the way to the surface if the situation otherwise allows for that. Another port can be used to transfer sensor data between sensor devices that are interconnected. Such that they can be logged in only one device and such that sensor data from all sensor devices can be transferred to a communication link device 50 over only one wireless communication link.

[0109] The logging unit 84 may be a flash memory circuit, for example a MicroSD® card. In some embodiments, raw data from the accelerometer 81 and gyroscope 82 can be stored in the MicroSD card with a sampling/logging frequency 10Hz. The system may then be prepared for 5, 20, 25 and 40Hz. At 10Hz, logging capacity allows continuous logging for 5.7 months using a 2GB MicroSD card and several years using a 32GB MicroSD card. If one sensor device is configured to receive and store sensor data from additional sensor devices, this will of course impact the memory usage in that sensor device.

[0110] In some embodiments, the wireless communication port 85 is a half-duplex infrared communication port with a bit rate of 57,600 bps. This port can be used for configuration of the sensor before mobilization, or to terminate a logging campaign when the senor has been demobilized. More importantly, the infrared port can be used for online communication with a communication link device 50 carried by a ROV. A topside computer can send commands to, and receive response from the sensor device over the ROV’s umbilical as long as the ROV holds the communication link device 50 within the operating range, which, as mentioned above, typically may be between 0.5 m and 1 m.

[0111] As also mentioned above, in some embodiments the communication link device 50 may be configured to operate autonomously, without any communication link to the surface. According to this alternative, data or instructions meant for the sensor device 40 will have to be pre-stored in the communication link device 50 before it is transported to the installation, and data retrieved by the communication link device 50 from the sensor device 40 will be temporarily stored in the communication link device until it is brought back to the surface.

[0112] Typically, a measurement campaign is designed to provide data that will be analyzed after the campaign has been completed. It may therefore not be desirable, or necessary, to fetch all the data stored in the logging unit 84 over the wireless port 85 while the measurement campaign is ongoing. Instead, it may desirable to obtain real-time access to parameters such as instant inclination (for example Roll and Pitch), to download statistical data from the start of the logging campaign, or to download raw data from a limited period of time, for example the last 24 hours.

[0113] The infrared port may be based on components intended for mobile phones, digital cameras, notebook computers etc., and comply with the IrDA physical layer low power specification (9.6 – 115.2kbits/s). Such components are readily available from many providers.

[0114] The controller unit 86 is, according to some embodiments, a powerful low-power 32 bits microcontroller with a capacity of 51 DMIPS (Mega Instructions Per Second, based on the Dhrystone benchmark method). This means that the sensor device may be capable of performing substantial signal processing algorithms in addition to storing raw data, without sacrificing significant service life. Signal processing algorithms may be adapted for standalone sensor devices 40, for a Master and Slave pair of sensor devices 40, 41 or for several sensor devices 40, 41 in a bus configuration. In the latter case, one of the sensor devices 40 may be configured to operate as a bus master. Among the calculations, the controller 86 may be configured to perform are statistics and calculation of inclination from raw data. The controller 86 may also be configured to access specific raw data, for example for a limited time window, and transfer these data over the wireless communication port 85, or real time transmission of raw data over the wireless communication port 85.

[0115] According to some embodiments, the controller unit 86 includes a built-in real-timeclock. If the sensor was logging prior to a power failure, the controller unit may be programmed to copy the last timestamp on the logging file to the real-time-clock. The clock may also be set by a user.

[0116] In some embodiments a hardware based real-time-clock with battery backup, can be provided instead of or as a supplement to the real-time-clock in the controller unit.

[0117] A sensor device 40, 41 configured to be used in embodiments of the invention may be equipped with a number of “safety net” features that will reduce the risk of logging corrupted data or losing data in case of an adverse event. Relevant (but very unlikely) adverse events could be a short drop in battery voltage (causing a reboot), a software lockup or software bug that causes the watchdog reset to reboot the sensor, or electromagnetic interference.

[0118] The most important safety net feature is the ability to resume logging if the sensor reboots during logging. Normal logging is initiated with a start command and all relevant systems parameters are stored in a text file in the logging unit 84. If the sensor device reboots after an adverse event, the system parameters may be restored before logging is resumed again.

[0119] Batteries are not shown in the block diagram of FIG. 14, but internal batteries may be provided in the form of a dual D-cell, 3.6V Thionyl Chloride Lithium battery of type SL-2790. Maximum battery capacity of the sensor device can be achieved by using two such batteries in parallel, each with a theoretical capacity of 38000mAh in room temperature and 34000mAh at zero degrees Centigrade. Maximum expected battery capacity in a subsea application is thus 68000mAh. Many other alternatives are, of course, available and consistent with the principles of the invention.

[0120] According to an alternative embodiment of the invention, a system includes respective sensor devices above and below the LFJ and one additional device operating as a bus master and connected to the sensor devices. In this embodiment, the bus master has no sensors of its own, but operates only to direct traffic on the bus that connects the sensors to each other and to the bus master and with the communication link device 50 over a wireless link. Such a bus master may be configured substantially as shown in FIG. 13 and FIG. 14, but without the accelerometer 81 and the gyroscope 82. In some embodiments the bus master is configured to log data received from the sensor devices. In alternative embodiments the bus master operates only to establish communication links and do not log data locally.

Claims (6)

1. CLAIMS 1. Method for establishing an estimate of bending moment over time in a subsea well (10), characterized in that the method comprising: receiving sensor data from a first motion sensor (40) unit which is provided at a blowout preventer (14), below the lower flex joint (18) of the wellhead, and a second motion sensor (41) unit which is provided at a riser (20), above a lower flex joint of the wellhead; determining a time series of values related to an inclination of the blowout preventer (14), θBOP(t), from the data received from the first motion sensor (40) unit; determining a time series of values related to an inclination of the riser (20), θRiser(t), from the data received from the second motion sensor (41) unit; determining a value related to a stiffness of the wellhead, KWH, from the respective time series; and determining a time series of values related to a wellhead bending moment, MWH(t), from the value related to the blowout preventer (14) inclination, θBOP(t), and the value related to the stiffness of the wellhead KWH. 2. The method according to claim 1, wherein the value related to stiffness of the wellhead is determined by: calculating a time series for quasi-static bending moment using the expression
2. the determined times series for inclination of the blowout preventer (14), θBOP(t), and the determined time series for inclination of the riser (20), θRiser(t); performing a Fast Fourier Transformation of the calculated time series for quasi-static bending moment and the time series for the blowout preventer inclination, θBOP(t), to determine amplitude at mode I for said quasi-static bending moment, , and said inclination of the blowout preventer P; and estimating the stiffness as
3. 3. The method according to claim 1, wherein the time series of values related to the wellhead bending moment, MWH(t) is determined by multiplying a time series of values related to the inclination of the blowout preventer (14), θBOP(t), with the value related to the stiffness of the wellhead, KWH.
4. 4. An article of manufacture, characterized in that the article comprising an electronically accessible medium to provide instructions that, when executed by one or more processors, cause one or more electronic systems to: receive sensor data from a first motion sensor (40) unit which is provided at a blowout preventer (14), below the lower flex joint of the wellhead, and a second motion sensor (41) unit which is provided at a riser (20), above a lower flex joint (18) of the wellhead; determine a time series of values related to an inclination of the blowout preventer (14), θBOP(t), from the data received from the first motion sensor (40) unit; determine a time series of values related to an inclination of the riser (20), θRiser(t), from the data received from the second motion sensor (41) unit; determine a value related to a stiffness of the wellhead, KWH, from the respective time series; and determine a time series of values related to a wellhead bending moment, MWH(t), from the value related to the blowout preventer (14) inclination, θBOP(t), and the value related to the stiffness of the wellhead KWH.
5. 5. The article according to claim 4, wherein the stiffness of the wellhead is determined by: calculating a time series for quasi-static bending moment using the expression

   the determined times series for inclination of the blowout preventer (14), θBOP(t), and the determined time series for inclination of the riser (20), θRiser(t); performing a Fast Fourier Transformation of the calculated time series for quasi-static bending moment and the time series for the blowout preventer (14) inclination, θBOP(t), to determine amplitude at mode I for said quasi-static bending moment, and said inclination of the blowout preventer (14), ; and estimating the stiffness as
6. 6. The article according to claim 5, wherein the time series of values related to the wellhead bending moment, MWH(t), is determined by multiplying a time series of values related to the inclination of the blowout preventer (14), θBOP(t), with the value related to the stiffness of the wellhead, KWH.