Patent Application
20150330205
The subject matter generally relates to systems in the field of oil and gas operations wherein a marine diverter having a sealing element is located above a telescopic joint.
U.S. Pat. Nos., and Publication Nos. 7,997,345; 6,470,975; 5,205,165; 8,347,983; WO2013/037049; 3,976,148; 4,440,239; 8,347,982; 4,626,135; and a paper entitled “Real Time Data from Closed Loop Drilling Enhances Offshore HSE” from WORLD OIL, published March 2013, at pgs. 33-42 are incorporated herein by reference for all purposes in their respective entireties. Each and every patent, application and/or publication referenced within each respective referenced patent is also incorporated herein by reference for all purposes in its respective entirety.
For the referenced U.S. Pat. No. 7,997,345, the RCD is above the marine diverter, which is bolted to the bottom of the drilling rig rotary table beams. The height of the I-beams (distance from diverter top to bottom of rotary table) differs from drilling rig to drilling rig, but in most cases, having the RCD within that height interferes with tools usually set in the rotary table (e.g. slips, tongs, bushings, etc.).
The disclosure relates to a system and method for determining whether a kick or loss has occurred from a well in real time in the oilfield industry, wherein the well has a marine diverter having a rotating control device assembly (or RCD). The rotating control device may include a bearing assembly and seal(s) suspended inside and fixed relative to the marine diverter body. Further, the RCD assembly may be located above a riser telescopic joint and a packer seal. The packer seal may have a first position wherein the packer seal is open and a second position wherein the packer seal is closed on an outer body of or connected to the RCD assembly to provide pressure sealing between an interior and an exterior of a riser. The marine diverter system may measure flow rate in real time of a drilling fluid entering the wellbore and provide a means of measuring flow rate of the drilling fluid out of the wellbore and riser into a mud rig system. The marine diverter system may further determine displacement and velocity of displacement of rig heave motion on a drilling rig in real time and use the foregoing process or steps, given a known internal diameter of the riser and a known external diameter of a drill pipe, and employing a drilling fluid volume balance equation: (Volumetric flow rate-in)−(Volumetric flow rate-out)−(Change in riser annular Volume per unit time)=X, to determine whether the kick or loss has occurred in real time.
As used herein the terms “determining” or “determine” shall also refer to modelling or otherwise calculating, computing, detecting, inferring, deducing and the like, in particular of a condition, quality or aspect of a wellbore unless otherwise expressly excluded or limited elsewhere herein. Similarly, as used herein the term “measuring” or “measure” shall also refer to modelling unless otherwise expressly excluded or limited elsewhere herein.
As used herein the terms “kick-loss”, “kick/loss” or “kick or loss” are used interchangeably within the disclosure and shall refer to any entry or influx, or loss of formation fluid into the wellbore during drilling operations, or any abnormal pressure or fluid fluctuations or changes in the wellbore and the like.
The exemplary embodiments may be better understood, and numerous objects, features, and advantages made apparent to those skilled in the art by referencing the accompanying drawings. These drawings are used to illustrate only typical exemplary embodiments of this invention, and are not to be considered limiting of its scope, for the invention may admit to other equally effective exemplary embodiments. The figures are not necessarily to scale and certain features and certain views of the figures may be shown exaggerated, in scale, or in schematic in the interest of clarity and conciseness.
a is depicts a similar schematic view to
a depicts a schematic view of another embodiment of a marine diverter system.
b depicts a schematic view of another embodiment of a marine diverter system.
The description that follows includes exemplary apparatus, methods, techniques, and instruction sequences that embody techniques of the inventive subject matter. However, it is understood that the described exemplary embodiments may be practiced without these specific details.
b depict schematic views of a marine diverter MD proximate a drilling rig DR above the surface of the water at a marine well site. In such a system, limited space or clearance may exist between the marine diverter MD and tools/components forming part of or emanating from the rotating table. Such limited space may prohibit or quantify the available clearance for the mounting of a rotating control device (RCD) 10 to the top of the marine diverter MD. Moreover, during rig heave and given a telescopic tubular joint 80 to compensate for heave, upward relative heave will cause a decrease in flow-out volume over time through the marine diverter MD, and downward relative heave will cause an increase in flow-out volume over time through the marine diverter MD above a telescopic tubular joint 80.
An additional reason to drill with a closed marine diverter MD system is in the exemplary scenario in the presence of risk of abnormal pressure zones where a surprise kick (e.g. shallower than one would expect) may get past the subsea blowout preventer (or BOP) and into the marine riser 90 before the rig crew may have time to implement secondary well control by closing the BOP. The ‘abnormal pressure risk’ is not that normally associated with what is known as a ‘shallow gas hazard’ and is usually encountered on fixed offshore rigs and platforms when drilling in shallow gas fields. Instead, on floaters, the ‘abnormal pressure risk’ may be associated with migration of gas along a fault line to shallower depths or a gas pocket (such as, for example, taught at http://www.geophysicsrocks.com/our-technology/technology-at-work/drill-oil/shallow-hazard-example/ which is incorporated herein by reference). Here, the value of the subject exemplary embodiments would be quick detection of well flow and where modest amounts (less than 500 psi or pounds per square inch) of surface back pressure applied immediately may suppress flow, buying time to add mud weight, and/or access whether or not the kick could be circulated out safely with a dynamic kill (hydrostatic pressure and pump rate friction pressure). A candidate for drilling ahead with a closed marine diverter MD system would be one where the operator or regulatory may have doubts about the ability to detect such a drilling hazard via a pre-drill seismic risk analysis (such as, for example, a pre-drill seismic risk analysis to detect shallow subsurface geologic hazards such as faults, gas charged sediments, buried channels, and abnormal pressure zones.
b depict a system and method for determining whether a kick or loss has occurred from a well or wellbore WB in real time in the oilfield industry, wherein the well has a marine diverter MD having a rotating control device assembly (or RCD) 10. The rotating control device 10 may include a bearing assembly 12 and a seal(s) 13 suspended inside and fixed relative to the marine diverter body MD. Further, the RCD assembly 10 may be located above a riser telescopic joint 80 and a packer seal 34. The packer seal 34 may have a first position wherein the packer seal 34 is open and a second position wherein the packer seal 34 is closed on an outer body of or connected to the RCD assembly 10 to provide pressure sealing between an interior and an exterior of a riser 90. The telescopic joint 80 may include an outer barrel 84 and an inner barrel 86. The marine diverter MD system may also include a pressure transducer 52.
The marine diverter MD system may measure flow rate in real time of a drilling fluid entering the wellbore WB and provide a means of measuring flow rate of the drilling fluid out of the wellbore WB and riser into a mud rig system. The marine diverter MD system may further determine displacement and velocity of displacement of rig heave motion on a drilling rig DR in real time and use the foregoing process or steps, given a known internal diameter of the riser 90 and a known external diameter of a drill pipe 8, and employing a drilling fluid volume balance equation: (Volumetric flow rate-in)−(Volumetric flow rate-out)−(Change in riser annular Volume per unit time)=X, to determine whether the kick or loss has occurred in real time. The step of determining whether the kick or loss has occurred in real time includes determining whether the modified volumetric flow balance, or X, does or does not equal zero.
In addition, the marine diverter MD system may plot a magnitude or height of marine heave on a drilling rig DR according to real time for creating a graph 140 of rig heave. The marine diverter MD system may also plot a flow volume according to real time for creating a graph 160 of flow out. The plotting of a magnitude or height of the marine heave according to real time and the plotting of flow volume according to real time may be correlated (or the graphs 140, 160 overlaid over each other) to determine whether the kick or loss has occurred in real time.
The
The marine diverter MD system may further include a device 50 mounted to or in communication with any fixed portion of the drilling rig DR, wherein the device 50 may be configured to measure vertical displacement of the marine diverter MD. The device 50 may be, by way of example only and not limited to, a gyro accelerometer, a linear accelerator, a GPS device/system, or an optical laser. The device 50 may be mounted or in communication with the drilling rig DR (such as, proximate to the marine diverter MD). A flow meter 60 may be mounted to a diverter flow line 62 connected to the marine housing 30;
The marine diverter MD system may detect a kick or loss from a well WB in the oilfield industry, by acquiring data from a device 50 which is configured to measure vertical displacement of the marine diverter MD proximate a marine diverter MD and interpreting the data acquired from the device 50 as a first representation 140 of height or magnitude over time of marine heave. Subsequently, data may be acquired from a flow meter 60 proximate the marine diverter MD and at least partially downstream of a telescoping slip joint 80 and interpreting the data acquired from the flow meter 60 for determining a second representation 160 of changes in volumetric flow over time downstream of a telescoping slip joint 80. Then, the first representation 140 may be compared to the second representation 160 in order to detect whether a kick or loss has occurred from a well WB. Alternatively, the data interpreted as a height over time of marine heave and the data interpreted as change in volumetric flow may be compared to detect whether a kick or loss has occurred without having a first and/or second representation of the respective data.
The
The passageway 25 has a diameter configured to house a bearing assembly 12 having a first position wherein the bearing assembly 12 is disengaged from the marine diverter MD, and a second position wherein the bearing assembly 12 is engaged with and the marine diverter MD. The bearing assembly 12 includes a proximal end 16 and a distal end 17. The bearing assembly 12 may be mounted to the first end portion 28 and housed at least partially within the passageway 25, wherein the outer race 14 of the bearing assembly 12 may be configured to traverse the passageway 25. The first end portion 28 may include a flange 28a. Further, one or more bearing assembly(ies) 12 may be oriented in an inverted position, as is depicted in the
The marine diverter MD system may further include an assembly for fastening 40 the flange 28a to the outer race 14. The assembly for fastening 40 may be optionally, by way of example, but not limited to: a clamp, a hydraulic clamp, a J-latch, a latching dog or internal-external threading.
The marine diverter MD system may also include a means for compiling data sensed by the device 50 and by the flow meter 60 in communication with both the device 50 and the flow meter 60 and a computational means for determining whether a kick or loss has occurred. The computational means may be configured to create a plot in the form of a graph.
The diverter flow line 62 may be connected to the marine housing 30 over a diverter outlet 32 and may also be connected to an accumulator 70. Said accumulator 70 may be a U-tube 72. The flow meter 60 may also be connected to the diverter flow line 62 downstream of the U-tube 72. Further, the diverter seal insert (or bearing assembly adaptor, as the case may be) 20 may also define a lubrication port 100 (see
a further depicts a cartridge 120 mounted above the bearing assembly 12 and at least partially within the passageway 25 and a plurality of wipers 122 contained within the cartridge 120, as part of the marine diverter MD system. The plurality of wipers 122 may include at least one packer 124 and further, the plurality of wipers 122 may define at least one annular space 126. The annular space 126 may be configured for lubrication and/or for pressure cascading. The marine diverter MD system may also include an accumulator 128 that is in fluid communication with the annular space 126.
b illustrates a bearing assembly 12 including an outer race 14, where the outer race 14 defines a plurality of radially spaced through-holes 130 extending parallel to the central axis.
The bearing assembly 12 and the first end portion 28 may also be collectively configured to prevent the bearing assembly 12 from falling entirely through the passageway 25 into the marine housing 30 and potentially further.
The annular packer seal 34 of the marine housing 30 may be configured for operative and selective closing on the outer race 14 of the bearing assembly 12, for operative and selective closing on the sleeve 102, and/or for operative and selective closing on the drill string 8 and/or tool joint 9, i.e. the drill string 8 may be inclusive of a tool joint 9 (to selectively effect dual barrier protection) depending on the needs of the particular marine diverter MD system.
To convert a diverter used above a riser in the oilfield drilling industry between an open mud-return system and a closed and pressurized mud-return system, a bearing assembly 12 may first be traversed into a passageway 25 defined in a marine diverter housing 30 for avoiding interference with a rotary table tool of a drilling rig DR. The bearing assembly 12 may be fastened within and traverse to the passageway 25. The diverter flow line 62 exiting the diverter in a filled state may be maintained. A second bearing assembly 12 may be traversed into the passageway 25 in the marine diverter housing 30. The second bearing assembly 12 may be suspended via an outer race 14 within the passageway 25 and below the first bearing assembly 12.
To detect or infer kick-loss in the oilfield industry, data may be acquired as a first data set from a gyro accelerometer (or other device) 50 proximate a marine diverter MD. The first data set acquired from the gyro accelerometer (or other device) 50 may then be plotted as a wave function representing height or magnitude versus time in real time representing a first signature 140 of marine heave. Data is then acquired as a second data set from a flow meter 60 proximate the marine diverter MD and downstream of a telescoping slip joint 80. The second data set acquired from the flow meter 60 is plotted or calculated as part of a second wave function representing volumetric flow per unit measurement of time representing a second signature 160 for changes in volumetric flow over time downstream of a telescoping slip joint 80. The first signature 140 is then compared to the second signature 160 in order to detect a kick or loss from a well. Alternatively, the first data set and the second data set may be compared in order to detect a kick or loss from a well without plotting the respective data sets.
Alternatives include that the rotatable sealing elements 13 may be actively or passively sealed as the case may be; a bearing assembly adaptor 22 may be needed, as the case may be; the embodiments disclosed may be used in various embodiments of marine drilling rigs DR (taught or reference by the art cited in the background). In the case of a closed diverter system, the drill string 8 with tool joints 9 may still be stripped in or out and/or with drilling through the rotatable inner race 15 and rotatable seals 13, without tearing seals, whilst operating for an early kick or loss detection.
While the exemplary embodiments are described with reference to various implementations and exploitations, it will be understood that these exemplary embodiments are illustrative and that the scope of the inventive subject matter is not limited to them. By way of example only, in another embodiment whereby pipe rotates relative to a non-rotating seal 13, the RCD(s) 10 may be replaced by a pressure control device 10a. Many variations, modifications, additions and improvements are possible.
Plural instances may be provided for components, operations or structures described herein as a single instance. In general, structures and functionality presented as separate components in the exemplary configurations may be implemented as a combined structure or component. Similarly, structures and functionality presented as a single component may be implemented as separate components. These and other variations, modifications, additions, and improvements may fall within the scope of the inventive subject matter.
| Number | Date | Country | |
|---|---|---|---|
| 61992755 | May 2014 | US |
