Field of the invention

The present invention relates to monitoring the flow rate of drilling fluid return in order to detect drilling fluid gain or loss during hydrocarbon well drilling. In particular, the present invention relates to a method of monitoring drilling fluid return flow rate when drilling a hydrocarbon well during which the drilling fluid is circulated down through a drill string, up through an annulus of the hydrocarbon well, through a wellhead diverter, through a flowline to a solids control and active mud system and back down through the drill string, wherein the drilling fluid, between the wellhead diverter and the solids control and active mud system, is routed through a drilling fluid flow rate monitoring system.

The present invention also relates to a drilling fluid flow rate monitoring system. Background

During drilling of oil and gas subsea wells 1, e.g. during production or exploration drilling, a closed loop circulating system for drilling fluids is normally used. Fig. 1 schematically discloses such a system. The system comprises a drill string 2 which runs inside a drilling riser 3. At the bottom end of the drilling string 2 is a bottom hole assembly 4 comprising a drill bit for breaking up the rock formation 5 during drilling. During drilling, drilling fluid is pumped down the drill string 2 to the bottom hole assembly 4 and is returned up a well annulus 6 with drilled cuttings. At the surface, the drilling fluid is routed via a diverter 7 and a flowline 8 to a solids control system 9, where the drilling fluid is conditioned for reuse. From the solids control system 9 the drilling fluid is routed to mud tanks 10, from which the drilling fluid is pumped back down the drill string 2 via a stand pipe manifold 11 using pumps 12. During drilling, the well 1 on the seabed 13 needs to be monitored to detect gain, i.e. influx of fluid from the rock formation into the well, and loss, i.e. outflow of drilling fluid into the rock formation.

Conventional well control involves monitoring the volume of the drilling fluid in the mud tanks 10. Taking into account changing hole geometry and loss of drilling fluid in the solids control system, an increase of drilling fluid volume in the mud tanks may indicate a gain situation, whereas a decrease of volume may indicate a loss situation.

In addition to monitoring the volume of drilling fluid in the mud tanks 10, conventional well control also involves monitoring the drilling fluid level in the flowline 8, e.g. using a flow paddle or a radar measurement system, whereby the stability of the flow of drilling fluid out of the well can be monitored. The volume of the drilling fluid in the mud tanks 10 can be measured quite accurately, but the time-response may be slow. This normally leaves monitoring of the drilling fluid level in the flowline 8 as the primary source for early gain/loss detection.

However, various properties of the drilling fluid, e.g. viscosity, particle size distribution, cuttings content, density, etc., vary continuously during drilling and measuring the drilling fluid level in the flowline is a challenge. In particular, a fluid height measurement requires an assumption of the fluid velocity profile in order to infer a flow rate. Unfortunately, one can expect the fluid flow profile in the flowline to change significantly with fluid properties like density and rheology. Therefore, whereas sudden and considerable change in the drilling fluid return flow can normally be detected using fluid level measurement, more subtle changes in the return flow can be difficult to detect, especially when drilling at low flow rates.

Kicks (influx of gas and fluid from formations into the well) frequently occur during connections and tripping. During drilling and circulation, friction loss from drilling fluids flowing up the annulus of the well adds to the bottom-hole pressure. This contribution to the bottom-hole pressure is normally termed Equivalent Circulation Density or ECD. When the mud pumps are shut off, the ECD is reduced to zero and the only barrier towards the formation pressure is the drilling fluid column in the well.

Advanced algorithms and downhole models are currently being developed and tested for automated drilling and kick/loss detection. The accuracy of such models depend on the quality of the input parameters such as the return flow of the drilling fluid. When a stable circulation rate is established, the signal from the flowline sensor, e.g. the flow

paddle/radar signal, is filtered to level out abnormal peaks and natural

variations/inaccuracy of the instrument. LeBlay et al: "A New Generation of Well Surveillance for Early Detection of Gains and Losses When Drilling Very High Profile Ultradeepwater Wells, Improving Safety, and Optimizing Operating Procedures (SPE 158374)", SPETT 2012 ENERGY

CONFERENCE AND EXHIBITION, 11.06.2012, pages 1-10, DOI: 10.2118/158374-MS, ISBN: 978-1-61-399244-9, discloses a system comprising an alternative apparatus for measuring drilling fluid return flow. The apparatus comprises a Coriolis flow sensor which is positioned in a bypass which diverts part of the drilling fluid return flow from the flowline, through the Coriolis flows sensor and back to the flowline.

Increasing focus on efficiency in the drilling industry has initiated the thoughts behind this new method for measuring return flow from the well during drilling, with increased accuracy compared to traditional technology. Measurement of return flow is an important parameter for early indication of abnormal situations downhole (gain or loss of drilling fluid), as well as an important input parameter in advanced drilling automation

methods/algorithms and automated/enhanced kick detection currently in use and under development. A substantial part of downtime related to well control problems is related to gain/loss and thus return flow measurement. The measurement is a direct indication of potential downhole loss or gain and is continuously monitored during drilling and circulation of drilling fluid through the wellbore. An objective of the present invention is to provide a method and a system for accurately monitoring the circulation of the drilling fluid through the wellbore.

Another objective of the present invention is to provide a system and a method of using available technology in existing systems to achieve improved measurement of return flow, which method is applicable for new-builds as well as for integration or retrofitting into existing drilling systems.

These and other objectives are obtained by the method and the system specified in the patent claims.

Summary of the invention

The method according to the invention may comprise the steps of:

- routing the drilling fluid through at least one measuring tank and at least one tank pump of the drilling fluid flow monitoring system, which at least one tank pump is arranged downstream of the at least one measuring tank;

- monitoring the drilling fluid level in the at least one measuring tank;

- monitoring the flow rate of drilling fluid going through the at least one tank pump; and - establishing the drilling fluid return flow rate based on the monitored fluid level in the at least one measuring tank and the monitored flow rate through the at least one tank pump.

The drilling fluid flow monitoring system comprising the at least one measuring tank and the at least one tank pump is arranged between the wellhead diverter and the solids control and active mud system. Consequently, the at least one measuring tank is arranged downstream of the wellhead diverter but upstream of the solids control and active mud system and also upstream of the mud tanks.

The step of monitoring the flow rate of the drilling fluid going through the at least one tank pump may comprise monitoring the flow rate using a flowmeter system arranged downstream of the at least one tank pump.

The flowmeter system may comprise a Coriolis type flowmeter.

If the flowmeter system is arranged downstream of the at least one tank pump and comprises a Coriolis type flowmeter, the tank pump will assist flow through the Coriolis unit. This allows a small diameter Coriolis unit to be used, which requires less space than the large 14-16" units which are normally used in gravity assisted applications. Due to the pressure drop over the Coriolis unit, a large diameter Coriolis units may require a build-up of drilling fluid in the flow line before the flow increase can be detected. This effect may be alleviated using a small diameter Coriolis unit. Also, a system comprising a small diameter Coriolis unit may be less exposed to solids build-up and plugging due to a higher velocity through the Coriolis unit.

The at least one tank pump may be a metering pump and the step of monitoring the flow rate of the drilling fluid going through the at least one tank pump may comprise monitoring the flow rate of the metering pump.

The at least one tank pump may be regulated to keep the drilling fluid in the at least one measuring tank at a predetermined level.

The at least one measuring tank may, during tripping in and out of the drill string, be used as a trip tank.

The drilling fluid flow rate monitoring system may comprise:

- at least one measuring tank arranged to receive drilling fluid from a wellhead diverter; - at least one tank pump arranged downstream of the at least one measuring tank to receive the drilling fluid from the at least one measuring tank and to deliver the drilling fluid to a downstream solids control and active mud system;

- at least one level indicating transmitter arranged at the at least one measuring tank for measuring the level of the drilling fluid in the at least one measuring tank;

- a pump flow rate monitoring system for monitoring the flow rate of the drilling fluid going through the at least one at least one tank pump; and

- a control system for establishing the flow rate of the drilling fluid received by the at least one measuring tank from the wellhead diverter based on:

- the fluid level in the at least one measuring tank as monitored by the at least one level indicating transmitter; and

- the flow rate of the drilling fluid going through the at least one tank pump as monitored by the pump flow rate monitoring system.

The system according to the invention may be arranged to route return drilling fluid flowing in a return line connected between the wellhead diverter and the downstream solids control and active mud system via the at least one measuring tank, i.e. from the return line, to the at least one measuring tank and back to the return line. By monitoring the fluid level in the least one measuring tank and monitoring and controlling the flow rate of the drilling fluid going through the at least one tank pump, the total return flow rate of the drilling fluid can be accurately calculated, displayed and trended in a stand-alone or integrated process control system. The pump flow rate monitoring system may be arranged downstream of the at least one tank pump and may comprise a flowmeter and the flowmeter may be a Coriolis type flowmeter.

The at least one tank pump may be a metering pump and the pump flow rate monitoring system may comprise the metering pump.

The metering pump may receive control signals from the at least one level indicating transmitter to keep the drilling fluid in the at least one measuring tank at a predetermined level. Alternatively, the at least one tank pump may be controlled by a variable frequency drive (VFD) which receives control signals from the at least one level indicating transmitter to keep the drilling fluid in the at least one measuring tank at a predetermined level.

One aspect of the invention uses existing systems in combination with some new components and controls to achieve improved drilling fluid control. In particular, the system according to the invention can be based on prior art trip tank systems, wherein trip tanks are used as measuring tanks. Consequently, one aspect of the present invention resides in utilising a conventional trip tank system not only during tripping, but also for monitoring the flow rate of the drilling fluid return during drilling.

The system according to the invention is beneficially integrated into the drilling control system which already controls and monitors the equipment in use (trip tanks, pumps, level indication, etc.), e.g. by installing volumetric trip tank pumps, VFD drive on conventional centrifugal trip tank pumps or a throttle valve on the outlets of the conventional centrifugal trip tank pumps.

Description of the drawings

Fig. 1 discloses a layout of a typical prior art drilling fluid circulation system. Fig. 2 discloses a layout of a typical prior art trip tank system.

Fig. 3 discloses a first embodiment of a drilling fluid flow monitoring system according to the invention.

Fig. 4 discloses a second embodiment of a drilling fluid flow monitoring system according to the invention. Fig. 5 discloses a third embodiment of a drilling fluid flow monitoring system according to the invention.

Fig. 6 discloses a fourth embodiment of a drilling fluid flow monitoring system according to the invention. Fig. 7a to 7c disclose further embodiments of a drilling fluid flow monitoring system according to the invention.

Detailed description of the invention

During drilling, drilling mud follows the drilling mud return conduit, or flowline, from the diverter 7 to the solids control and active mud system (cf. Fig. 1). However, as is known in the art, during tripping the drill string 2 in and out of the well 1 , the drilling mud is circulated via a trip tank system to maintain well control.

There are several possible variations in number of trip tanks, pumps, design of piping, etc. of the trip tank system, but the main functionality of the system remains the same. The trip tank(s) are designed and instrumented to ensure a high level of control of the volume in the tank(s) to enable detection of small flow variations when circulating over the wellhead diverter during tripping out/in of the well and when circulating over the wellhead to detect loss/gain in the well (so called "flow-check").

Fig. 2 discloses a layout of a typical prior art trip tank system 21 which is connected to the flowline 23 between the wellhead diverter 25 and the solids control and active mud system 27. In the disclosed embodiment, the system 21 comprises two trip tanks 29a, 29b and two trip tank pumps 31, 33. The trip tank pumps 31, 33 are typically centrifugal pumps. The system 21 comprises a plurality of trip tank inlet valves 35a, 35b, 37 allowing one or both of the tanks 29a, 29b to be connected to the flowline 23 via a trip tank system inlet conduit 24. The system 21 also comprises a plurality of trip tank outlet valves 41a, 41a', 41b, 41b' allowing either trip tank 29a, 29b to be connected to either trip tank pump 31, 33. The system 21 further comprises trip tank pump outlet valves 43, 45 connecting the pumps 31, 33 to a trip tank system outlet conduit 47. The valves 35a, 35b, 37, 41a, 41a', 41b, 41b', 43 and 45 allow any combination of trip tank and trip tank pump to be incorporated into the trip tank system loop. Level indicating transmitters 49a, 49a', 49b, 49b' are arranged in the trip tanks 29a, 29b for measuring the mud level in the tanks. A flowline valve 51 is arranged between the trip tank inlet conduit 24 and the trip tank outlet conduit 47.

Fig. 2 discloses the trip tank system 21 in an inactive state, i.e. in a state where the trip tank system 21 is bypassed by keeping the valves 35a, 35b, 37, 43 and 45 closed, and the flowline valve 51 open. This is the state a conventional trip tank system is in during drilling. When the system 21 is activated, e.g. when tripping the drill string in or out of the well, the flowline valve 51 is closed and a suitable combination of valves 35a, 35b, 37, 41a, 41a', 41b, 41b' 43 and 45 are opened, allowing the drilling fluid to be circulated via one or both of the trip tanks 29a, 29b by at least one of the trip tank pumps 31, 33. As has been previously discussed, one aspect of the present invention resides in utilising a conventional trip tank system not only during tripping, but also for monitoring the flow rate of the drilling fluid return during drilling. Fig. 3 discloses a first embodiment of such a drilling fluid flow rate monitoring system 61. The system 61 is similar to the system 21 disclosed in Fig. 2 and like reference numerals indicate like features. However, the system 61 also comprises a pump flow rate monitoring system 63 which is arranged to measure the flow rate of the drilling fluid going through the pumps 31, 33. The pump flow rate monitoring system 63 comprises a flowmeter 65 which is arranged in the fluid path of conduit 47. The flowmeter 65 may for example be a Coriolis type flowmeter.

By monitoring the drilling fluid level in the tanks 29a, 29b using the level indicating transmitters 49a, 49a', 49b, 49b' and also monitoring the flow rate of the drilling fluid going through the pumps 31, 33 using the pump flow rate monitoring system 63, the flow rate of the drilling fluid return, i.e. the flow rate of the drilling fluid emerging from the well head diverter 25, can be established accurately and in a responsive fashion. In a steady- state situation, i.e. in a situation where the flow rate of the drilling fluid return is constant, the system 61 maintains the drilling fluid level in each tank 29a, 29b at a predetermined level, in which case the flow rate of the drilling fluid return at each point in time is given directly by the flow rate monitored by the flowmeter 65. However, if there is a change in the flow rate of the drilling fluid return, this will rapidly be detected by the transmitters 49a, 49a', 49b, 49b', since in such a situation the level in the tanks 29a, 29b will change.

If the transmitters 49a, 49a', 49b, 49b' detect an increasing fluid level, this indicates that the flow rate of the drilling fluid return is higher than the flow rate monitored by the flowmeter 65, whereas a decreasing fluid level indicates that the flow rate of the drilling fluid return is lower than the flow rate monitored by the flowmeter 65. Knowing the geometry of the tanks 29a, 29b and the rate of change of the fluid level, it is possible to adjust the flow rate monitored by the flowmeter 65 to arrive at the true flow rate of the drilling fluid return, i.e. the flow rate of the drilling fluid emerging from the wellhead diverter 25. The monitored signals from the level indicating transmitters 49a, 49a', 49b, 49b' and the pump flow rate monitoring system 63 are sent to a controller 100 where the signals are processed accordingly to yield the flow rate of the drilling fluid return.

In the disclosed embodiment, the pumps 31, 33 are variable frequency drive pumps which are controlled by variable frequency drives (VFDs) 74, 76. The VFDs 74, 76 are connected to the level indicating transmitters 49a, 49a', 49b, 49b'. In order not to obscure other features in Fig. 3, VFD 74 is disclosed to be connected only to transmitters 49b and 49b'. However, it is understood that VFD 76 is also connected to transmitters 49a and 49a'. Likewise, VFD 76 is connected to transmitters 49a, 49a', 49b and 49b', although this is also not explicitly disclosed in Fig. 3 in order not to obscure other features in the figure. The VFDs 74, 76 receive control signals from the transmitters 49a, 49a', 49b, 49b' which are a function of the fluid level in the tanks 29a, 29b. This allows the VFDs 74, 76 to control the pumps 31, 33 to maintain a predetermined fluid level in the tanks 29a, 29b during drilling. Consequently, as has been discussed above, in a dynamic flow rate situation, i.e. when the flow rate of the drilling fluid return changes or fluctuates over time, the flow rate is established based on monitored signals from the transmitters 49a, 49a', 49b, 49b' and the flowmeter 65.

In Fig. 3 only tank 29b is disclosed to be active. However, the skilled person realises that the system is equally functional if both tanks 29a and 29b are active, or if only tank 29a is active.

The flowmeter system 63 comprises valves 67, 69, 71 arranged down-steam, up-stream and in parallel to the flowmeter 65, allowing the flowmeter 65 to be by-passed via a bypass conduit 73. When in a non-drilling mode, e.g. during tripping in and out of the drill string, the valves 67 and 69 can be closed and valve 71 opened, allowing the flowmeter 65 to be by-passed and the system 61 to be operated as a conventional trip tank system.

Fig. 4 discloses a second embodiment of a drilling fluid flow rate monitoring system 75 according to the invention. System 75 operates in the same way as system 61, i.e. the flow rate of the drilling fluid return is established based on the monitored fluid level in the tanks 29a, 29b and the monitored flow rate of the drilling fluid going through the pumps 31, 33. However, in this embodiment the valve 77 arranged down-stream of the flowmeter 65 is a variable throttle valve which receives control signals from the transmitters 49a, 49a', 49b, 49b'. The predetermined levels in the tanks 29a, 29b are maintained by varying the through-put area of the throttle valve 77 based on the signals from the transmitters 49a, 49a', 49b, 49b', in which case the pumps 31, 33 need not be VFD controlled, but can be conventional, non-VFD controlled centrifugal pumps.

Fig. 5 discloses a third embodiment of a drilling fluid flow rate monitoring system 79 according to the invention. In this embodiment the conventional trip tank pumps have been exchanged for volumetric pumps 81, 83, i.e. metering pumps having a flow rate which can be controlled. By receiving control signals from the transmitters 49a, 49a', 49b, 49b', the metered flow rate of the pumps 81, 83 can be controlled to maintain the predetermined fluid level in the tanks 29a, 29b. Since the flow rate from the tanks 29a, 29b is controlled by the volumetric pumps 81, 83 and thereby is known, there is no need to arrange a flowmeter in the flow path of conduit 47. Consequently, the flow meter system 63 of the above-discussed systems 61 and 75, i.e. the first and second embodiments, can be dispensed with.

Fig. 6 discloses a fourth embodiment of a drilling fluid flow rate monitoring system 85 according to the invention. In this embodiment a volumetric pump 87 is arranged in parallel to the conventional trip tank pumps 31, 33 and a pump outlet valve 89 connects the pump 87 to the outlet conduit 47. Tank outlet valves 91a, 91b allow tanks 29a and/or 29b to be brought into fluid communication with pump 87 during drilling. By receiving control signals from the transmitters 49a, 49a', 49b, 49b', the metered flow rate of pump 87 can be controlled to maintain the predetermined fluid level in tanks 29a and/or tank 29b. Since the flow rate from the tanks 29a, 29b is controlled by the volumetric pump 87, and consequently is known, there is no need to arrange a flowmeter in the flow path of conduit 47 in order to establish the flow rate of the drilling fluid going through pump 87.

When in a non-drilling mode, e.g. during tripping in and out of the drill string, the valves 91 and 93 are closed and a suitable combination of valves 41a, 41a', 41b, 41b', 43 and 45 are opened, allowing the system 85 to operate as a conventional trip tank system.

The above-discussed systems 61, 75, 79 and 85 are based on a conventional trip tank system and can be realised by simple modifications of such a system. Also, systems 61, 75, 79 and 85 can all be operated as a conventional trip tank system when in non-drilling mode. However, it is understood that the drilling fluid flow rate monitoring system can be realised as a stand-alone system which has no other function than to establish the flow rate of the drilling fluid return.

Figs. 7a to 7c disclose three embodiments of a system according to the invention having only one measuring tank and one tank pump. Such systems may be suitable as

"standalone" systems. The working principles of the systems 101, 102 and 103 disclosed in Figs. 7a to 7c are the same as for the previously discussed systems 85, 61 and 75, respectively.

The system according to the invention can be retrofitted on existing drilling systems for use on smaller well hole sections as well as engineered onto new builds. Also, the system according to the invention is applicable for all kinds of conventional drilling, both on- and offshore.

In the preceding description, various aspects of the apparatus according to the invention have been described with reference to the illustrative embodiment. For purposes of explanation, specific numbers, systems and configurations were set forth in order to provide a thorough understanding of the apparatus and its workings. However, this description is not intended to be construed in a limiting sense. Various modifications and variations of the illustrative embodiment, as well as other embodiments of the apparatus, which are apparent to persons skilled in the art to which the disclosed subject matter pertains, are deemed to lie within the scope of the present invention as defined by the following claims.