[0001] This disclosure generally relates to the field of drilling, and more particularly to a drilling system and a method for identifying a kick during drilling.

[0002] The exploration and production of hydrocarbons from subsurface formations have been widely practiced for decades. Due to the limited productivity of aging land-based production wells, there is a growing interest in hydrocarbon recovery from subsea wells. Generally, for drilling a subsea well, a rotatable drill bit attached to a drill pipe is used to create a wellbore below the seabed. The drill pipe allows control of the drill bit from a surface location, typically from an offshore platform or a drill ship. Typically, a drilling assembly is also deployed to connect the platform at the surface to the wellhead on the seabed. The drilling assembly includes a riser, a LMRP (Lower Marine Riser Package), and a BOP (Blowout Preventer). The drill pipe passes through the riser so as to guide the drill bit to the wellhead.

[0003] During well drilling, the drill bit is rotated while the drill pipe conveys the necessary power from the surface platform. Meanwhile, a drilling fluid is circulated from a fluid tank on the surface platform through the drill pipe to the drill bit, and is returned to the fluid tank through an annular space between the drill pipe and the riser, or between the drill pipe and a casing. The drilling fluid maintains a hydrostatic pressure to counter-balance the pressure of fluid coming from the well and cools the drill bit during operation. In addition, the drilling fluid mixes with material excavated during creation of the wellbore and carries the material to the surface for disposal.

[0004] Under certain circumstances, the pressure of fluid entering the well from the formation may be higher than the pressure of the drilling fluid. This may lead to an unwanted influx of fluid into the wellbore, known in the industry as a“kick”. Conventionally, the presence of a kick can be detected by a detector such as a flowmeter when the returning drilling fluid from the wellbore is greater than the flow of the drilling fluid in the drill pipe being presented to the well. There is a potential occurrence of a blowout which will cause a catastrophic equipment failure and the attendant potential harm to well operators and the environment. To prevent such catastrophic failure, it is necessary to close the shut-off valves of the blowout preventer (BOP) or to adjust the density of the drilling fluid to relieve the kick.

[0005] However, if a kick is falsely alarmed, shut-off valves of the BOP may be unnecessarily closed down, and repeatedly operating the shut-off valves will shorten the lifetime of the BOP. Therefore, a more precise kick detecting mechanism is desired to identify the occurrence of the kick so as to operate the BOP only when necessary.

[0006] Therefore, it is desirable to provide improved systems and methods to address at least one of the above-mentioned problems.

BRIEF DESCRIPTION

[0007] In one aspect of embodiments of the present invention, a drilling system is provided. The drilling system comprises a drilling assembly and a monitoring system. The drilling assembly is configured to be connected between a platform and a wellhead, for drilling a wellbore. The monitoring system comprises a detection device and a processor. The detection device is configured to obtain a characteristic parameter associated with a returned fluid from the wellbore and obtain a density parameter of the returned fluid. The processor is configured to identify an occurrence of a kick based on the obtained

characteristic parameter and the obtained density parameter.

[0008] In another aspect of embodiments of the present invention, a method for identifying a kick is provided. The method comprises: obtaining a characteristic parameter associated with a returned fluid from a wellbore configured to be drilled by a drilling system; obtaining a density parameter of the returned fluid; identifying an occurrence of a kick based on the obtained characteristic parameter and the obtained density parameter.

DRAWINGS

[0009] These and other features, aspects, and advantages of the present disclosure will become better understood when the following detailed description is read with reference to the accompanying drawings in which like characters represent like parts throughout the drawings, wherein: [0010] FIG.1 is a schematic diagram of a drilling system in accordance with one exemplary embodiment of the present disclosure;

[0011] FIG.2 is a schematic diagram of a second detection device attached to the drilling system in accordance with one exemplary embodiment of the present disclosure;

[0012] FIG.3 is a schematic diagram of a torsional wave densitometer in accordance with one exemplary embodiment of the present disclosure; and

[0013] FIG.4 is a flowchart of a method for identifying a kick in accordance with one exemplary embodiment of the present disclosure.

DETAILED DESCRIPTION

[0014] In the following description, well-known functions or constructions are not described in detail to avoid obscuring the disclosure in unnecessary detail.

[0015] The terms“first,”“second,” and the like, herein do not denote any order, quantity, or importance, but rather are used to distinguish one element from another. The terms“a” and“an” herein do not denote a limitation of quantity, but rather denote the presence of at least one of the referenced items.

[0016] Moreover, in this specification, the suffix“(s)” is usually intended to include both the singular and the plural of the term that it modifies, thereby including one or more of that term (e.g.,“the element” may include one or more elements, unless otherwise specified). Reference throughout the specification to“one embodiment,”“another embodiment,”“an embodiment,” and so forth, means that a particular element (e.g., feature, structure, and/or characteristic) described in connection with the embodiment is included in at least one embodiment described herein, and may or may not be present in other embodiments.

Similarly, reference to“a particular configuration” means that a particular element (e.g., feature, structure, and/or characteristic) described in connection with the configuration is included in at least one configuration described herein, and may or may not be present in other configurations. In addition, it is to be understood that the described inventive features may be combined in any suitable manner in the various embodiments and configurations. [0017] In some instances, the approximating language may correspond to the precision of an instrument for measuring the value. Further, as used herein, the terms“disposed on” refers to components disposed directly in contact with each other or indirectly.

[0018] Referring now to FIG.1, a schematic diagram of a drilling system 100 is illustrated in accordance with one exemplary embodiment of the disclosure. In embodiments of the invention, the drilling system 100 is configured to drill wells for exploration and production of hydrocarbons. Non-limiting examples of the wells include onshore wells and offshore wells. In one specific example, the drilling system 100 is configured to drill offshore wells.

[0019] As is illustrated in FIG.1, the drilling system 100 generally includes a platform 101 at a water surface and a drilling assembly 103 connecting between the platform 101 and a wellhead 105. The platform 101 may include a drill ship or an offshore tower.

[0020] The drilling assembly 103 includes a proximal end 102 linked to the platform 101 and a distal end 104 linked to the wellhead 105. More specifically, the drilling assembly 103 connecting at downside of the platform 101 is at least partially immersed in the seawater and is used to excavate a wellbore 132. In one embodiment, the drilling assembly 103 includes a drill string 110, a drill bit 114, a riser 111, a blowout preventer (BOP) 115, and a lower marine riser package (LMRP) 113.

[0021] In one embodiment, the drill string 110 includes a drill pipe formed from lengths of tubular segments connected end to end. The drill bit 114 is disposed onto a distal end of the drill string 110. The drill bit 114 is rotated by the drill string 110 to perform the drilling below the seabed 107 so as to form the wellbore 132.

[0022] The riser 111 extends substantially vertically from the platform 101 to the wellhead 105. The riser 111 may include a plurality of riser segments and the riser segments are connected with each other via a plurality of riser joints (not shown). The riser 111 is configured to accommodate the drill string 110 and allow the drill string 110 to extend within the riser 111 along a length direction of the riser 111.

[0023] During the drilling, the drill string 110 rotates the drill bit 114 and tethers the drill bit 114 to the platform 101. Meanwhile, a drilling fluid 112 is circulated from a fluid tank (not shown) of the platform 101 through the drill string 110 to the drill bit 114, and is returned to the platform 101 as a returning drilling fluid through an annular space 122 formed between the drill string 110 and a conduit. In one embodiment, the conduit may comprise the riser 111 for purposes of example. In another embodiment, the conduit may comprise a casing (not shown).

[0024] The drilling fluid 112 (also referred to as a drilling mud) maintains a hydrostatic pressure to counter-balance the pressure of fluid in the formation and cools the drill bit 114 while also carrying excavated materials, to the surface. Excavated materials include crushed and cut rock formed during drilling of the wellbore 132. The drilling fluid 112 from the platform 101 may include adventitious water, oil, and/or other additives in addition to the initial drilling fluid composition.

[0025] The returning drilling fluid may include mixture of the drilling fluid 112 and materials excavated during formation of the wellbore 132. On the platform 101, the returning drilling fluid may be treated, for example, it may be filtered to remove excavated solids and then re-circulated.

[0026] As mentioned above, in certain applications, the pressure of the fluid in the formation may be higher than the pressure of the drilling fluid 112, which may cause a kick. When a kick happens, a formation fluid 117, typically including oil and gas mixture, enters the wellbore 132 and mixes with the returning drilling fluid, which results in a greater returning fluid 116. If uncontrolled, the returning fluid 116 from the wellbore 132 flowing in the annular space 122 may result in a blowout on the platform 101 when burst out of the drilling assembly 103. As used herein the term“returning fluid” may refer to the returning drilling fluid, mixture of the returning drilling fluid with the formation fluid 117, or the formation fluid 117 flowing through the annular space 122.

[0027] As is shown in FIG.1, the LMRP 113 is located at a distal end of the riser 111 and is placed adjacent to the BOP 115 or above the BOP 115. The LMRP 113 includes a connector 127 configured to couple the LMRP 113 to the riser 111. With the use of the LMRP 113, the platform 101 can be separated from the wellbore 132 by disconnecting the connector 127.

[0028] The BOP 115 is located between the LMRP 113 and the wellhead 105. The BOP 115 includes one or more shut-off valves 125, which are usually configured redundantly in stacks and may be used to seal, control, and monitor wells. When a kick is suspected to have occurred, the annular space 122 may be partly sealed by closing the shut-off valves 125 of the BOP 115 to stop the returning fluid 116 from moving upward to the platform 101. As such, the hydrostatic balance is regained through circulation of drilling fluid 112 in the riser 111. Under some circumstances, the shut-off valves 125 of the BOP 115 can be closed completely, which means that both the channel for the drilling fluid 112 and channel for the returning fluid 116 are cut off and the wellbore 132 is sealed.

[0029] It is necessary to identify the occurrence of the kick before operating the BOP 115, so as to extend the lifetime of the BOP and/or avoid enormous losses that may be caused by sealing the well. Thus, it is desirable to provide for greater certainty in identifying the occurrence of the kick to mitigate the effects of both real kick and false positives.

[0030] In one embodiment, a monitoring system 129 for precisely identifying an occurrence of a kick is provided by the present invention. As is shown in FIG.1, the monitoring system 129 includes a first detection device 109 and a second detection device 119 disposed between the proximal end 102 and the distal end 104 of the drilling assembly 103. In this embodiment, the first detection device 109 and the second detection device 119 are shown as separate detection devices for purposes of example. However, the monitoring system 129 should be not limited to comprise the separate detection devices. In another embodiment, the first detection device 109 and the second detection device 119 may be integrated within a single detection device without departing from the spirit of the present invention.

[0031] As shown in FIG.1, the first detection device 109 is disposed on the LMRP 113 and the second detection device 119 is disposed on the riser 111. In some embodiments, either of the first detection device 109 and the second detection device 119 can be disposed on the LMRP 113, the BOP 115, any other parts of the riser 111 or the casing. In other embodiments, the first detection device 109 can be disposed on the platform 101 and the second detection device 119 can be disposed on the LMRP 113, the BOP 115 or any other parts of the riser 111.

[0032] More specifically, the first detection device 109 is configured to obtain a characteristic parameter associated with the returning fluid 116. The characteristic parameter of the returning fluid 116 may include any parameters related to the occurrence of the kick, such as an acoustic velocity, a volumetric flow rate, a pressure of the returning fluid 116 and etc. Because when a kick is occurring, a density parameter of the returning fluid 116 will change due to the mixed influx, the density parameter of the returning fluid 116 is one of parameters that needs to be monitored to identify the occurrence of the kick. The density parameter of the returning fluid 116 may comprise a density of the returning fluid 116 or a density change of the returning fluid 116. Considering these, the second detection device 119 is configured to obtain a density parameter of the returning fluid 116.

[0033] In some embodiments, the monitoring system 129 further includes a processor (not shown). In some embodiments, the processor may be placed on the platform 101. In some embodiments, the processor may also be placed on the other parts of the drilling system 100 such as the drilling assembly 103. The processor is configured to identify the occurrence of the kick based on the obtained characteristic parameter associated with the returning fluid 116 and the obtained density parameter of the returning fluid 116. In one embodiment, the processor is configured to generate a first alarm signal based on the obtained characteristic parameter and generate a second alarm signal based on the obtained density parameter.

[0034] For example, if a measured volumetric flow rate of the returning fluid 116 is greater than a predetermined volumetric flow rate of the drilling fluid 112, the first alarm signal is generated. In some embodiments, the first alarm signal can be generated by observing the volume of the fluid in the fluid tank. More specifically, when the fluid level in the fluid tank rises quickly which means the amount of returning fluid 116 flowing into the fluid tank is greater than the amount of drilling fluid 112 flowing out of the fluid tank, the first alarm signal is generated. In one embodiment, the processor analyzes the density parameter of the returning fluid 116 and generates the second alarm signal according to the analyzed result. In one embodiment, when the analyzed result indicates that the returning fluid 116 comprises an unwanted influx of fluid, the second alarm signal is generated.

[0035] The monitor system 129 of the present invention may monitor the characteristic parameter associated with the returning fluid 116 as a first indicator of kick occurrence and monitor the density parameter of returning fluid 116 as a second indicator of kick occurrence. By combining the first indicator and the second indicator of kick occurrence, the monitor system 129 of the present invention can increase greatly the accuracy of predicting kick occurrence, reduce false alarm, and further improve operating efficiency of the drilling system 100. The drilling system 100 of the present invention can work more reliably by reducing false alarm.

[0036] In one embodiment, the second detection device 119 is a device for measuring a density parameter of fluid. In this embodiment, the second detection device 119 is configured to measure a density of the returning fluid 116. Referring to FIG.2, a schematic diagram of a second detection device 119 attached to the drilling system 100 in accordance with one exemplary embodiment of the present is shown. In the illustrated embodiment, the second detection device 119 includes a torsional wave densitometer. The torsional wave densitometer 119 has a strong interaction of torsional wave energy and the surrounding fluid (i.e. the returning fluid 116). In the illustrated embodiment, the torsional wave densitometer 119 is assembled on the riser 111.

[0037] The torsional wave densitometer 119 includes a transducer 201, an electronic driving circuit 207, a first wave guide 203 and a second wave guide 205. The drilling assembly 113 includes a chamber 221 for accommodating the transducer 201 and the electronic driving circuit 207. The chamber 221 is an enclosed space and the returning fluid 116 is isolated from the chamber 221. The drilling assembly 103 includes a cavity 223 for accommodating the first wave guide 203 and the second wave guide 205. The first and second wave guides 203 and 205 are submerged in the returning fluid 116. The torsional wave densitometer 119 can be powered by a power source assembled on the BOP 115 or a power source assembled on the platform 101. Therefore, less space is needed and small changes are required when machining the riser 111, the LMRP 113, or the BOP 115 when the torsional wave densitometer 119 is assembled on any one of them.

[0038] In some embodiments, the first wave guide 203 and the second wave guide 205 are set with different cross-sectional geometries. In some embodiments, the first wave guide 203 and the second wave guide 205 are machined as a single solid wave guide with two sections of different cross-sectional geometrics. In the illustrated embodiment of FIG.3, the first wave guide 203 includes a circular cross-section and the second wave guide 205 includes a square cross-section.

[0039] The transducer 201 is driven by the electronic driving circuit 207 for generating a torsional wave traveling in the first wave guide 203 and the second wave guide 205. The first wave guide 203 and the second wave guide 205 are immersed in the returning fluid 116 and are actuated at one end to guide the torsional wave which propagates through the first wave guide 203 and the second wave guide 205 with a velocity that varies in a manner dependent on the returning fluid 116.

[0040] The electronic driving circuit 207 includes a pulser/receiver and an

intervalometer. A continuous or pulsed DC electric current is generated by the electronic driving circuit 207 and is passed axially along the first wave guide 203 and the second wave guide 205 in the form of a torsional wave. Similarly, the torsional echo is returned along the second wave guide 205 and the first wave guide 203, and the returned torsional wave can be detected by the transducer 205. The first wave guide 203 and the second wave guide 205 are configured to provide a wave path for the torsional wave and the return torsional wave.

[0041] Referring to FIG.3, a schematic diagram of a torsional wave densitometer in accordance with one exemplary embodiment is shown. FIG.3 shows the trace of the electric signal corresponding to echoes A, B of excitation pulses received from the top face 211 of the second wave guide 205 and the bottom face 213 of the second wave guide 205, respectively. The interval tAB between the two echoes A, B is a flight time of the torsional wave in the second wave guide 205. The flight time t _AB depends on the densities of the waveguide and the surrounding fluid (i.e. the returning fluid 116), on the fluid viscosity, and on the shape of the waveguide. Therefore, after detecting the flight time t _AB , knowing the material density of the second wave guide 205, and calculating the fluid viscosity, the density of the returning fluid 116 is calculated.

[0042] FIG.3 is an example of a transducer for applying a torsional wave to a sensor body. Such a wave may also be created by other appropriate types of piezoelectric transducer. It will be understood that any such torsional wave transducer, or other known transducer having appropriate characteristics for the waveguide may be employed. Under high pressure and high temperature, the torsional wave densitometer is suitable for measuring the density of the returning fluid 116.

[0043] However, the second detection device 119 of the present invention should be not limited to use the torsional wave densitometer. In another embodiment, the second detection device 119 may also use an ultrasonic device to measure a density parameter of the returned liquid 116. In this embodiment, the ultrasonic device is configured to measuring a density of the returning fluid 116 based on a propagation property of an ultrasonic signal in the returning fluid 116. The propagation property of the ultrasonic signal may comprise a propagation velocity or a propagation energy. In one embodiment, the ultrasonic device may comprise an ultrasonic density meter for purposes of example. The ultrasonic density meter may include one or more ultrasonic transducers and an ultrasonic pulser and receiver for energizing one or more ultrasonic transducers. In one embodiment, the one or more ultrasonic transducers may be disposed on the riser 111. For example, the one or more ultrasonic transducers may be disposed on an outer surface or an inner surface of the riser 111. In another embodiment, the one or more ultrasonic transducers may be disposed on the casing. In one embodiment, the ultrasonic density meter includes one ultrasonic transducer for purposes of example. The ultrasonic pulser and receiver are configured to transmit an ultrasonic signal to the annular space 122 through the ultrasonic transducer and receive an ultrasonic signal through the ultrasonic transducer.

[0044] By measuring the time ^ of the ultrasonic signal from being transmitted to being received, because a ultrasonic beam path ^ of the ultrasonic signal propagated in the returning fluid 116 is known, a propagation velocity ^ of the ultrasonic signal in the returning fluid 116 is obtained as following:

[0045] In addition, it is known that the propagation velocity ^ of the ultrasonic signal in the returning fluid 116 varies as a function of the density ^ of the returning fluid 116, as shown in the equation (2), wherein ^ represents a compression coefficient.

[0046] From the equation (2), the density ^ of the returning fluid 116 can be obtained according to the propagation velocity ^ of the ultrasonic signal in the returning fluid 116.

[0047] Therefore, the ultrasonic density meter can measure the density ^ of the returning fluid 116 based on the propagation velocity ^ of the ultrasonic signal in the returning fluid 116. The ultrasonic density meter is simple in structure and is easier to measure the density ^ of the returning fluid 116. [0048] The above is only one of arithmetics using the ultrasonic device to measure the density parameter of the returned liquid 116. However, the present invention may also use other arithmetics to measure the density parameter of the returned liquid 116.

[0049] Certainly, the second detection device 119 of the present invention may also comprise other types of devices for measuring a density parameter of fluid, such as a Coriolis flow meter, a float ball type densitometer, a resonant shell densitometer, a tuning fork densitometer, a gamma-ray densitometer, a differential pressure densitometer and the like.

[0050] Furthermore, the present invention also provides a method for identifying a kick. FIG.4 illustrates a flow chart of a method for identifying a kick in accordance with one exemplary embodiment of the present invention. As shown in FIG.4, the method 400 for identifying the kick in accordance with one exemplary embodiment of the present invention includes the steps as following:

[0051] At block 401, a characteristic parameter associated with a returning fluid 116 from a wellbore 132 configured to be drilled by a drilling system 100 is obtained. In one embodiment, the characteristic parameter associated with the returning fluid 116 may be measured by using the first detection device 109.

[0052] At block 403, a density parameter of the returning fluid 116 is obtained. In one embodiment, the density parameter of the returning fluid 116 may be measured by using the second detection device 119. For example, a torsional wave densitometer may be used to measure the density parameter of the returning fluid 116 based on a torsional wave.

Alternatively, an ultrasonic device such as an ultrasonic density meter may also be adopted to measure the density parameter of the returning fluid 116 based on a propagation property of an ultrasonic signal in the returning fluid 116. The details how to measure the density parameter of the returning fluid 116 using the torsional wave densitometer or the ultrasonic density meter have been described in detail above.

[0053] At block 405, an occurrence of a kick is identified based on the obtained characteristic parameter associated with the returning fluid 116 and the obtained density parameter of the returning fluid 116. In one embodiment, a first alarm signal is generated based on the obtained characteristic parameter, and a second alarm signal is generated based on the obtained density parameter. In one embodiment, by analyzing the obtained density parameter of the returning fluid 116, when the analyzed result indicates that the returning fluid 116 includes an unwanted influx of fluid, the second alarm signal is generated.

[0054] The method for identifying the kick according to the present invention may monitor the characteristic parameter associated with the returning fluid 116 as a first indicator of kick occurrence and monitor the density parameter of returning fluid 116 as a second indicator of kick occurrence. By combining the first indicator and the second indicator of kick occurrence, the method of the present invention can increase greatly the accuracy of predicting kick occurrence, reduce false alarm, and further improve operating efficiency of the system.

[0055] While the disclosure has been illustrated and described in typical embodiments, it is not intended to be limited to the details shown, since various modifications and

substitutions can be made without departing in any way from the spirit of the present disclosure. As such, further modifications and equivalents of the disclosure herein disclosed may occur to persons skilled in the art using no more than routine experimentation, and all such modifications and equivalents are believed to be within the spirit and scope of the disclosure as defined by the following claims.