US20130087388A1 - Wellbore influx detection with drill string distributed measurements - Google Patents

Wellbore influx detection with drill string distributed measurements Download PDF

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Publication number
US20130087388A1
US20130087388A1 US13/648,231 US201213648231A US2013087388A1 US 20130087388 A1 US20130087388 A1 US 20130087388A1 US 201213648231 A US201213648231 A US 201213648231A US 2013087388 A1 US2013087388 A1 US 2013087388A1
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bop
annular
pressure
drill string
gradient
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Daniel Marco Veeningen
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Intelliserv LLC
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Intelliserv LLC
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    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B47/00—Survey of boreholes or wells
    • E21B47/10—Locating fluid leaks, intrusions or movements
    • E—FIXED CONSTRUCTIONS
    • E21—EARTH OR ROCK DRILLING; MINING
    • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
    • E21B47/00—Survey of boreholes or wells
    • E21B47/06—Measuring temperature or pressure

Definitions

  • Wired or networked drill pipe incorporating distributed sensors can transmit data from discrete locations along the drill string or other wellbore tubulars to the surface for analysis.
  • a wellbore or formation fluid influx also called a “kick”
  • the blowout preventer BOP
  • a BOP may not always close in time to address all of the wellbore or formation fluid influx that is directed toward the surface rig.
  • the present disclosure relates to a method for detecting a wellbore influx with drill string distributed measurements including obtaining a first annular measurement from a first sensor disposed on a drill string. The method also includes obtaining a second annular measurement from a second sensor disposed on the drill string and computing a gradient of a first interval defined by the first and second sensors. Finally, the method includes detecting a wellbore influx based on the gradient and the first and second annular measurements.
  • Other embodiments are directed to a method for detecting a wellbore influx with drill string distributed measurements including providing a plurality of sensors distributed on a drill string with an electromagnetic network. The method also includes identifying a plurality of intervals defined between two sensors that are adjacent or have intervening sensors, and obtaining an absolute measurement at two or more of the sensors. Finally, the method includes computing a gradient of the plurality of intervals, and detecting a wellbore influx based on the gradient and the absolute measurements.
  • FIG. 1 is a schematic of a drilling rig and wellbore system for sensing borehole or formation characteristics in accordance with aspects of the disclosure
  • FIG. 2 is an enlarged schematic view of portion II-II in FIG. 1 ;
  • FIG. 3 is a cross-sectional view of a mud-gas separator
  • FIG. 4 is a schematic of a drill string with an electromagnetic network and pressure/gradient indications in accordance with the principles disclosed herein;
  • FIG. 5 is a method for detecting wellbore influx and migration above the BOP, and determining the appropriate remedial action in accordance with the principles disclosed herein;
  • FIG. 6 is a method for monitoring and controlling a well kill based on the detection of an influx in accordance with the principles disclosed herein;
  • FIG. 7 is a schematic of a drill string with an electromagnetic network and temperature/gradient indications in accordance with the principles disclosed herein;
  • FIG. 8 is another method for detecting wellbore influx and migration above the BOP, and determining the appropriate remedial action in accordance with the principles disclosed herein;
  • FIG. 9 is a schematic of a drill string with an electromagnetic network and flow rate/gradient indications in accordance with the principles disclosed herein;
  • FIG. 10 is still another method for detecting wellbore influx and migration above the BOP, and determining the appropriate remedial action in accordance with the principles disclosed herein;
  • FIG. 11 is still another method for detecting wellbore influx and migration above the BOP in accordance with the principles disclosed herein.
  • any use of any form of the terms “connect”, “engage”, “couple”, “attach”, or any other term describing an interaction between elements is not meant to limit the interaction to direct interaction between the elements and may also include indirect interaction between the elements described.
  • Reference to up or down will be made for purposes of description with “up”, “upper”, “upwardly” or “upstream” meaning toward the surface of the well and with “down”, “lower”, “downwardly” or “downstream” meaning toward the terminal end of the well, regardless of the well bore orientation.
  • the symbol “ ⁇ ” indicates minimal or no change in an associated value.
  • well construction operations refer to a wide variety of operations which may take place in a wellbore for an oil and gas well. For example, such operations may include, but are not limited, to drilling, completing, and testing a well.
  • certain components or elements are in fluid communication. By this it is meant that the components are constructed and interrelated such that a fluid could be communicated between them, as via a passageway, tube, or conduit.
  • FIG. 1 illustrates a schematic view of a drilling operation 10 in which a borehole 36 is being drilled through a subsurface formation beneath the ocean or sea floor 26 .
  • the drilling operation 10 includes a drilling rig 20 on the ocean surface 27 and a drill string 12 which extends from the rig 20 , through a riser 13 in the ocean water, through a BOP 29 , and into the borehole 36 which is further reinforced with a casing pipe 18 for at least some distance below the sea floor 26 .
  • Drilling operation 10 also includes a choke line 74 fluidly coupling a choke manifold (see 70 in FIG. 2 ) disposed on rig 20 to the wellbore 36 at a point below the BOP 29 , and a kill line 72 extending from rig 20 to the wellbore 36 at a point below the BOP 29 .
  • a choke manifold see 70 in FIG. 2
  • Drill string 12 generally comprises a plurality of tubulars coupled end to end. Connectors or threaded couplings 34 are located at the ends of each tubular thereby facilitating the coupling of each tubular to form drill string 12 .
  • connectors 34 represent drill pipe joint connectors.
  • Drill string 12 is coaxially positioned within riser 13 above the sea floor 26 and coaxially positioned within casing 18 , and borehole 36 below the sea floor 26 .
  • an annulus 22 is formed between the outer surface of the drill string 12 and the inner surface of the riser 13 , casing 18 , and borehole 36 .
  • a bottom hole assembly 15 (BHA 15 ) is provided at the lower end of the drill string 12 . As shown in FIG.
  • BHA 15 includes a drill bit or other cutting device 16 , a sensor package 38 located near the bit 16 , a formation evaluation package and/or a drilling mechanics evaluation package 19 , a directional drilling motor or rotary steerable device 14 , and a network ready interface sub 17 .
  • BHA 15 may include different components while still complying with the principles of the current disclosure.
  • BOP 29 is configured to controllably seal the wellbore 36 . Some embodiments of BOP 29 may engage and seal around the drill string 12 , thereby closing off the annulus 22 . Other embodiments of BOP 29 may include shear rams or blades for severing the drill string 12 and sealing off borehole 36 from the riser 13 . Transitioning BOP 29 from the open to closed positions and vice versa may be controlled from the surface or subsea.
  • the drill string 12 also preferably includes a plurality of network nodes 30 .
  • the nodes 30 are provided at desired intervals along the drill string 12 .
  • Network nodes 30 essentially function as signal repeaters to regenerate and/or boost data signals and mitigate signal attenuation as data is transmitted up and down the drill string.
  • the nodes 30 may also include measurement assemblies.
  • the nodes 30 may be integrated into an existing section of drill pipe or a downhole tool along the drill string 12 .
  • Sensor package 38 in BHA 15 may also include a network node (not shown separately).
  • the term “sensors” is understood to comprise sources (to emit/transmit energy/signals), receivers (to receive/detect energy/signals), and transducers (to operate as either source/receiver).
  • the nodes 30 comprise a portion of a networked drill string data transmission system 46 that provides an electromagnetic signal path that is used to transmit information along the drill string 12 .
  • the data transmission system 46 may also be referred to as a downhole electromagnetic network or broadband network telemetry, and it is understood that the drill string 12 primarily referred to below may be replaced with other downhole tubulars.
  • the data transmission system 46 includes multiple nodes 30 installed along the drill string 12 . Communication links (not shown) may be used to connect the nodes 30 to one another, and may comprise cables or other transmission media integrated directly into sections of the drill string 12 .
  • the cable may be routed through the central borehole of the drill string 12 , routed externally to the drill string 12 , or mounted within a groove, slot, or passageway in the drill string 12 .
  • Induction coils may be placed at each connection 34 to transfer the signal being carried by the cable from one drill pipe section to another.
  • signals from the plurality of sensors in the sensor package 38 and elsewhere along the drill string 12 are transmitted to the surface 26 through a wire conductor along the drill string 12 .
  • Communication links between the nodes 30 may also use wireless connections.
  • a plurality of packets (not shown) may be used to transmit information along the nodes 30 . Further detail with respect to suitable nodes, a network, and data packets are disclosed in U.S. Pat. No. 7,207,396 (Hall et al., 2007), hereby incorporated in its entirety by reference.
  • sensors 40 may be employed along the drill string 12 in various embodiments, including without limitation, axially spaced pressure sensors, temperature sensors, flow rate sensors, strain sensors, and others. While sensors 40 are herein described and shown disposed on the drill string 12 , it should also be noted that sensors 40 may be disposed on any downhole tubular that has an inner diameter that allows for the passage of flow therethrough while still complying with the principles of the current disclosure. For example, sensors 40 may be disposed on equipment such as but not limited to heavy weight drill pipe, drill pipe, drill collars, stabilizers, float subs, reamers, jars, or flow bypass valves.
  • the sensors 40 may also be disposed on the nodes 30 positioned along the drill string 12 , disposed on tools incorporated into the string of drill pipe, or a combination thereof.
  • the data transmission system 46 transmits information from each of a plurality of sensors 40 to a surface computer located on or near rig 20 .
  • the sensors 40 are annular pressure sensors.
  • sensors 40 are annular temperature sensors, annular flow rate sensors, and strain sensors. Additionally, in some embodiments, sensors 40 measure the conditions (e.g., pressure, temperature, flow rate, strain) within the bore of the drill string 12 .
  • nodes 30 may include booster assemblies.
  • the booster assemblies are spaced at 1,500 ft. (500 m) intervals to boost the data signal as it travels the length of the drill string 12 to prevent signal degradation.
  • sensors 40 disposed on or within network nodes 30 allow measurements to be taken along the length of the drill string 12 .
  • the distributed network nodes 30 provide measurements that give the driller additional insight into what is happening along the potentially miles-long stretch of the drill string 12 .
  • the gradients of the intervals between the various nodes 30 can also be calculated based on the change in the measured absolute values at each node 30 .
  • Information from the well site computer may be displayed for the drilling operator on a well site screen (not shown). Information may also be transmitted from the well site computer to a remote computer (not shown), which is located at a site that is remote from the well or rig 20 .
  • the remote computer allows an individual in a location that is remote from the well or rig 20 to review the data output by the sensors 40 .
  • sensors 40 and nodes 30 are shown in the figures referenced herein, those skilled in the art will understand that a larger number of sensors may be disposed along a drill string when drilling a fairly deep well, and that all sensors associated with any particular node may be housed within or annexed to the node 30 , so that a variety of sensors rather than a single sensor will be associated with that particular node.
  • BOP 29 may be actuated such that the well is closed above the wellbore influx.
  • a leading portion of the wellbore influx may have already migrated above the BOP 29 at the time the rams or seals are closed.
  • downhole distributed measurements and high speed broadband telemetry systems allow wellsite personnel to detect the migrated wellbore influx, to confirm that the BOP has sealed the annulus, and, optionally, to identify potential remedial actions for the migrated wellbore influx.
  • downhole distributed measurements on a high speed broadband telemetry system allow wellsite personnel to monitor and manage well kill operations.
  • the measurements used are independent from surface measurements.
  • fluid e.g., hydrocarbons
  • fluid enters into the annulus 22 from the inner wall of the borehole 36 at some point between the bottom of the casing and the location of the bit 16 , below the sea floor 26 and BOP 29 .
  • the formation fluids entering the borehole 36 e.g., gas, oil, water, etc.
  • the drilling fluid e.g., drilling mud
  • completion fluid the hydrostatic pressure in the annulus 22 will drop while the temperature will initially rise.
  • the influx enters the annulus 22 , it begins to volumetrically expand and reduce the confined pressure within the wellbore as it is transported upwards under the influence of the upward annular flow which is present during typical well construction operations.
  • This rapid expansion causes the hydrostatic pressure as well as the fluid temperature in the areas where the influx has migrated in the annulus 22 to be reduced.
  • the flow rate of fluid flowing through the annulus 22 will tend to increase when an influx occurs due to the addition of a large amount of fluid to the system from the formation.
  • the influx causes the buoyancy in the interval covered by the influx to be reduced.
  • the strain experienced by the drill string will increase as the effective weight of the drill string increases.
  • the strain experienced by the drill string above the influx increases at a faster rate than the strain experienced by the drill string below the leading edge of the influx. Therefore, by utilizing the various nodes 30 and sensors 40 distributed along drill string 12 and methods disclosure herein, wellsite personnel may monitor the absolute value as well as the gradient for variables such as the pressure, temperature, flow rate, and strain along the drill string to determine (1) whether an influx has occurred; and (2) the height to which the detected influx has migrated within the annulus 22 . Such personnel may then take the appropriate remedial action based on the observed measured downhole values provided by the data transmission system 46 and obtain confirmation of the effectiveness of the implemented actions.
  • a diverter 60 is disposed at or near the ocean surface 26 and is configured to allow the fluid flowing up the annulus 22 to be dumped or diverted overboard via an outlet 61 when desired.
  • a mud-gas separator 50 is disposed on rig 20 . Fluid flowing up the annulus 22 may be routed to mud-gas separator 50 via a valve 51 or similar device. As shown in FIG. 3 , mud-gas separator 50 comprises a vessel 52 with an inlet 53 , a gas outlet 55 , and a processed fluid outlet 57 . In order to separate the hydrocarbon gas from the drilling fluid, the mud-gas separator 50 includes a plurality of baffles 54 disposed within the vessel 52 .
  • baffle 54 within the vessel 52 also includes a pipe nipple 56 in order to discourage the formation of gas pockets between the baffles and the inner walls of vessel 52 .
  • the inlet 53 includes a bend 53 a. This bend discourages gas from flowing back through the inlet after it has been separated out from the incoming fluid.
  • drilling fluid or mud that exits outlet 57 still contains at least some amount of hydrocarbons (e.g., oil or gas).
  • This processed fluid may be routed to a mud-degasser (not shown) to further remove any remaining dissolved hydrocarbons. It should also be noted that other embodiments of mud-gas separator 50 may have different flow paths and may arrange the inlets and outlets differently while still complying with the principles of the current disclosure.
  • Separator 50 may have operational limits which cannot be exceeded.
  • the mud-gas separator 50 will typically have a maximum flow rate capacity.
  • the gas or hydrocarbon will exit via outlet 57 and will be routed both to atmosphere and the mud pit (not shown) thereby producing a risk of combustion.
  • the influx flow will be substantial enough such that the incoming flow from the annulus 22 should be diverted via diverter 60 in lieu of lining up the mud-gas separator 50 .
  • a single barrel of fluid at the BOP may expand to more than 15 barrels at the surface for a well in 5 , 000 feet water depth.
  • wellsite personnel are challenged with making the correct decision between lining up the mud-gas separator 50 or using the diverter 60 without adequate information to determine whether the operational limits of the mud-gas separator 50 will be exceeded.
  • the embodiments described herein may be used to predict the appropriate remedial measure to be taken and minimize the hazard described above.
  • an exemplary drill string 112 similar to drill string 12 includes annular pressure sensors 142 , 144 , 146 , 148 , a BOP 129 , and drill bit 116 .
  • drill string 112 includes pressure sensor 145 that measures the pressure of the inner bore of the drill string 112 , rather than in the annulus (e.g., annulus 22 ).
  • pressure sensor 145 measures the pressure of the inner bore of the drill string 112 , rather than in the annulus (e.g., annulus 22 ).
  • other embodiments may not include sensor 145 while still complying with the principles disclosed herein.
  • sensors disposed on a drill string may simultaneously measure multiple variables, such as for example, pressure and temperature, while still complying with the principles disclosed herein.
  • variables such as for example, pressure and temperature
  • annular sensors 142 , 144 , 146 , 148 measure pressure and allow wellsite personnel to measure both the absolute pressures (shown in FIG. 4 as #P) at each sensor, as well as the change in readings in an interval defined by two individual sensors.
  • the amount of change between two individual sensors is referred to as a gradient (shown in FIG. 4 as ⁇ P).
  • the symbol #P ⁇ indicates that there is no or a minimal change in the absolute pressure for a particular sensor and the symbol ⁇ P ⁇ indicates that there is no or a minimal pressure gradient for a given set of sensors (e.g., sensors 142 , 144 , 146 , 148 ) at that given point in time.
  • FIG. 4 notes the changes in both the absolute values as well as the gradients of pressure measured by the sensors 142 , 144 , 146 , 148 .
  • An increase is noted by an upward facing arrow while a decrease is noted by a downward facing arrow, and the relative magnitude of the increase/decrease is shown by the size of the associated arrow.
  • the deepest or lowermost positioned annular pressure sensor 142 is the first sensor to measure a pressure decrease, which is indicated in FIG. 4 by a downward facing line arrow.
  • the gradient between sensors 142 and 144 is also decreasing due to the fact that the sensor 142 is measuring a pressure decrease while the sensor 144 is not. This decrease in the pressure gradient between sensors 142 and 144 is indicated in FIG.
  • the sensors 146 , 148 higher in the drill string 112 measure a further increasing drop in both the absolute pressure, as well as the gradients between all the measurement sensors or stations.
  • the BOP 129 is closed.
  • the portion of the influx 147 disposed below the now closed BOP 129 is being compressed within the sealed annulus, and the portion of the influx 147 disposed above the now closed BOP 129 is continuing to expand upward toward the sea surface 27 .
  • the annular pressure measurements and gradients below the BOP 129 are increasing (indicated by upward facing arrows), and the annular pressure measurements and gradients above the BOP 129 continue to decrease due to the migration and volumetric expansion of the influx as it rises to the surface.
  • FIG. 5 wherein a method 100 for detecting wellbore influx and migration above the BOP (e.g., BOP 129 ), and determining the appropriate remedial action is shown. Though depicted sequentially as a matter of convenience, at least some of the actions shown can be performed in a different order and/or performed in parallel. Additionally, some embodiments may perform only some of the actions shown. Finally, in some embodiments some or all of the steps disclosed below may be performed manually by a person or persons, or may be performed, at least partially, by a computer.
  • BOP e.g., BOP 129
  • the method 100 begins by collecting the pressure readings from the various sensors (e.g., sensors 142 , 144 , 146 , 145 , and 148 ) throughout the drill string and computing the gradient for an interval between two of the various sensors at 150 .
  • the method 100 next includes a first decision box 152 , where it is determined whether there is an annular pressure decrease being observed at the sensors. If “no” then pressure measurements are recollected and analyzed at 150 . If “yes” then a second decision box 154 determines whether there is an annular pressure gradient decrease being observed in the sensor interval. If “no” then pressure measurements are recollected and analyzed at 150 . If “yes” then a third decision box 155 determines whether an absolute bore pressure decrease is being observed.
  • pressure measurements are recollected and analyzed at 150 . If “yes” then a determination is made at 151 that there is an influx in the wellbore and it has advanced or migrated to the sections or intervals where the pressure decreases in 152 , 154 , and 155 have been observed.
  • method 100 only one or some of the decision boxes 152 , 154 , 155 may be present while still complying with the principles disclosed herein.
  • some embodiments of method 100 may allow for analysis of the queries listed in decision boxes 152 and 154 while omitting the query listed in decision box 155 while still complying with the principles disclosed herein.
  • the method next includes a decision box 156 which inquires as to whether the sensors disposed above the BOP (e.g., sensor 146 ) are registering or observing pressure decreases as described above in 152 , 154 , 155 . If “yes”, than a determination is made that the wellbore influx is above the BOP and is inside the riser (e.g., riser 13 ) at 158 . If, on the other hand, the sensors disposed above the BOP are not registering pressure decreases as described above in 152 , 154 , 155 , then a determination is made that the influx is still below the BOP at 157 .
  • the sensors disposed above the BOP e.g., sensor 146
  • method 100 includes a decision box 159 wherein it is determined whether an absolute pressure increase is being observed below the BOP. If “no” then a determination is made at 163 to either actuate the BOP or, if the BOP has already been actuated, that the BOP has not adequately sealed the annulus. If “yes” then a determination is made at 161 that the BOP has successfully actuated and has sealed the annulus.
  • the determination at 160 as to whether the pressure and/or pressure gradient decline rate is high or low comprises comparing the observed values to a pre-determined threshold limit.
  • This threshold limit may be determined based on various factors such as but not limited to the operational capacity of the mud-gas separator (e.g., separator 50 ), the environmental conditions present at the well, and the properties of the drilling fluid or underground formation.
  • the determinations at 152 , 154 , 156 , 160 further comprise additional sensor intervals above the BOP and analysis thereof.
  • additional above-BOP sensors and pressure gradient intervals can be measured and analyzed to enhance the measurement of the absolute pressure decrease at 152 , the annular pressure decrease at 154 , and the pressure and/or gradient decline rate at 160 .
  • the enhanced measurements may then be used to refine the determination of a wellbore influx above the BOP at 151 , whether the influx is above or below the BOP at 156 , and the remedial measures taken at 162 , 164 .
  • the additional sensor and sensor intervals allow a more refined analysis of the pressure and gradient decline rates above the BOP.
  • the sensor intervals discussed above and throughout this disclosure may be defined by a pair of immediately adjacent sensors or by sensors at other points along the drill string or tubular that are not immediately adjacent to one another.
  • the number of intervals available for measurement and analysis will depend upon the number of sensors placed along the drill string 112 .
  • an annular pressure sensor may be disposed every 1,000 feet in the drill pipe section.
  • four annular pressure sensors may be disposed thereon (e.g., sensors 142 , 144 , 146 , 148 ).
  • the four corresponding measurements will have six different potential intervals and therefore allows for a computation of six gradients, wherein each gradient is associated with one of the intervals.
  • five measurement sensors will yield 10 corresponding intervals.
  • FIGS. 6 wherein a method 200 for monitoring and controlling a well kill based on the detection of an influx is shown. Though depicted sequentially as a matter of convenience, at least some of the actions shown can be performed in a different order and/or performed in parallel. Additionally, some embodiments may perform only some of the actions shown. Finally, in some embodiments some or all of the steps disclosed below may be performed manually by a person or persons, or may be performed, at least partially, by a computer.
  • a well kill operation involves pumping heavy “kill mud” into the wellbore.
  • kill mud There are various ways to place kill mud in the well to regain control.
  • a dynamic well kill involves pumping kill mud into the wellbore via the inner bore of the drill string. Such a well kill method may not require the activation of the BOP 29 since the aim is to replace the original drilling fluid with the kill mud in the wellbore while maintaining a sufficient bottomhole pressure through applying a dynamic friction pressure to prevent any further influx of formation fluid into the wellbore.
  • a conventional well kill initially requires activation of the BOP 29 .
  • kill mud is pumped down the drill string and up the annulus where the pressure exerted on the formation is sufficient to stop any further influx from occurring therefrom.
  • the kill mud, original drilling/completion fluids, and formation fluids are then directed up the annulus, through the choke and into the choke line 74 , thereby bypassing the riser 13 .
  • the fluid mixture then advances up the choke line toward the choke manifold 70 , where it may be processed accordingly.
  • the well kill may be accomplished by a method known as “bullheading” wherein kill mud displaces the influx and original drilling or completion fluid into the formation, such that no fluid returns to the surface 26 .
  • the BOP 29 remains open and the kill mud is pumped down the drill string 12 , while in others the BOP 29 is closed and the kill mud is pumped down a kill line 72 into the annulus 22 .
  • the fracture pressure of the formation will typically decrease with decreasing depth such that it will be at its lowest value near the sea floor 26 .
  • the fracture pressure of the formation at the bottom of the casing e.g., casing 18
  • the casing shoe will typically be the upper limit for the pressure during either type of well kill as the influx and mud is circulated up the annulus (e.g., annulus 22 ).
  • the pressure at the casing shoe is estimated by determining the pressure at the choke and then adjusting that pressure reading by subtracting the assumed hydrostatic pressure of the fluid column between the choke and the casing shoe.
  • the embodiments described herein can be used to more accurately determine the pressures near the cashing shoe by interpolation of direct measurements of the annular pressure at discrete positions along the wellbore and such that better management of the well kill operations can be achieved.
  • method 200 initially begins with a decision to kill the well at 250 .
  • This decision may be independent or may directly flow from a determination (e.g., determination 161 in method 100 ) that the BOP has actuated and has sealed the annulus due to a detected wellbore influx.
  • method 200 contains a first decision box 252 determining whether a bullheading well kill method, previously described, is being utilized. If “yes” then a determination is made at 253 to pump the kill mud down the kill line into the wellbore at a sufficient pressure to force the formation fluids, original drilling/completion fluids, and the kill mud into the formation.
  • the injected kill mud will normally have a higher density that both the original drilling/completion fluid as well as the formation fluids.
  • the absolute pressure as well as a pressure gradient will increase where the leading edge of the kill mud is located at a given time.
  • method 200 provides for a decision box 255 determining whether there is an observed pressure gradient increase in an interval below the actuated BOP. If “yes” then the progress of the injected kill mud has been identified at the interval experiencing the increase in the associated pressure gradient at 257 . If “no” then kill mud continues to be pumped down the kill line at 253 .
  • method 200 requires the well kill to proceed at 254 by pumping the kill mud down the drill string such that it may then be routed into the wellbore, up the choke line, and into the choke manifold as is consistent with a conventional well kill process, previously described.
  • kill mud is pumped down the drill string and returns are taken from the annulus at 254 .
  • the measurement sensors above and below the casing shoe are identified and the associated pressure readings from those sensors are collected at 256 .
  • the annular pressure at the casing shoe is interpolated by comparing the pressure measurements collected above the casing shoe to those measurements collected from below the casing shoe at 258 .
  • some embodiments of method 200 may allow for an increase in the displacement rate of the kill mud, even if the pressure at the casing show is above the pre-determined threshold at 260 , in order to maintain a minimum required bottomhole pressure necessary to prevent further influx from occurring in the wellbore.
  • the determination at 260 is that the interpolated annular pressure at the casing shoe is below the pre-determined threshold, a determination is made at 264 to increase the displacement rate or pumping of the kill mud in order to increase the operational efficiency of the well kill process. As a result, the pumping parameters of the kill mud are adjusted, thereby reinitiating the analysis at 254 .
  • the pressure threshold at 260 may be influenced by a variety of factors.
  • factors may include the fracture pressure of the formation at its weakest point, the fracture pressure of the formation at the casing shoe (which may be the same as the fracture pressure at the weakest point), the pressure rating of the equipment being used, and the specific characteristics of the well.
  • other factors may be considered while still complying with the principles disclosed herein.
  • an exemplary drill string 312 similar to drill string 12 includes annular temperature sensors 342 , 344 , 346 , 348 , a BOP 329 , and drill bit 316 .
  • drill string 312 includes temperature sensor 345 that measures the temperature of the inner bore of the drill string 312 and the temperature in the annulus (e.g., annulus 22 ).
  • sensor 345 measures the temperature of the inner bore of the drill string 312 and the temperature in the annulus (e.g., annulus 22 ).
  • Annular temperature sensors 342 , 344 , 346 , 348 allow wellsite personnel to measure both the absolute temperatures (shown in FIG. 7 as #T) at each sensor as well as the change in readings in an interval defined by two individual sensors.
  • the amount of change between two individual sensors is referred to as a gradient (shown in FIG. 7 as ⁇ T).
  • ⁇ T The amount of change between two individual sensors
  • the symbol #T ⁇ indicates that there is no or a minimal change in the absolute temperature for a particular sensor
  • the symbol ⁇ T ⁇ indicates that there is no or a minimal temperature gradient for a given set of sensors (e.g., sensors 342 , 344 , 346 , 348 ) at that given point in time.
  • FIG. 7 notes the changes in both the absolute values as well as the gradients of temperature measured by the sensors 342 , 344 , 346 , 348 .
  • An increase is noted by an upward facing arrow while a decrease is noted by a downward facing arrow, and the relative magnitude of the increase/decrease is shown by the size of the associated arrow.
  • the gradient between sensors 342 and 344 is also increasing due to the fact that the sensor 342 is measuring a temperature increase while the sensor 344 is not.
  • This increase in the temperature gradient between sensors 342 and 344 is indicated in FIG. 7 with an upward facing block arrow next to the temperature gradient, ⁇ T, between the sensors 342 , 344 .
  • the influx 347 migrates to shallower depths, which may, in some cases, be above the BOP 329 .
  • the gas that has been mixed into the other wellbore fluids as a result of the influx, separates from the other fluids in the annulus and begins rapidly expanding. Due to this rapid volumetric expansion, the temperature begins decreasing, thereby causing temperature sensors disposed nearby to begin registering decreases in the absolute temperature as well as the computed gradients. It should also be noted that the volumetric expansion and therefore the associated temperature decrease occurs at shallower depths for oil based drilling fluids than for water based drilling fluids.
  • the second deepest annular temperature sensor 344 measures an annular temperature decrease, thereby triggering a decrease in the gradient between sensors 344 and 346 .
  • sensor 346 also measures a decreasing temperature, and the gradient between the measurement sensors 346 , 348 is also decreasing.
  • the BOP 329 is closed. Accordingly, the portion of the influx 347 disposed below the now closed BOP 329 is being compressed within the sealed annulus, while the portion of the influx 347 disposed above the BOP 329 is continuing to expand upward toward to the sea surface 27 . Therefore, the temperature sensors 346 , 348 disposed above the BOP continue to register decreases in both the absolute temperature and the associated gradients. Furthermore, as a result of both the pressure increase of the fluids below the BOP 329 and the thermal conduction of the now static fluid at that depth, the sensors disposed below the BOP 329 measure an increase in both the absolute temperature and the associated gradients for those measurements.
  • FIG. 8 wherein a method 300 for detecting wellbore influx and migration above the BOP, and determining the appropriate remedial action is shown. Though depicted sequentially as a matter of convenience, at least some of the actions shown can be performed in a different order and/or performed in parallel. Additionally, some embodiments may perform only some of the actions shown. Finally, in some embodiments some or all of the steps disclosed below may be performed manually by a person or persons, or may be performed, at least partially, by a computer.
  • the method 300 begins by collecting the temperature readings from the various sensors (e.g., sensors 342 , 344 , 346 , and 348 ) throughout the drill string and string and computing a gradient for an interval between two of the various sensors at 350 .
  • the method 300 next includes a first decision box 352 determining whether an annular temperature increase is being observed at the sensors. If “no” then temperature measurements are recollected and analyzed at 350 . If “yes” then a second decision box 354 determines whether there is an annular temperature gradient increase being observed in the sensor interval. If “no” then temperature measurements are recollected and analyzed at 350 .
  • the method 300 directs for temperature readings from the various sensors (e.g., sensors 342 , 344 , 346 , and 348 ) throughout the drill string to be collected and to compute a gradient for an interval between two of the various sensors at 353 .
  • the method 300 next includes a decision box 356 determining whether an annular temperature decrease is being observed at the sensors. If “no” then temperature measurements are recollected and analyzed at 353 . If “yes” then another decision box 358 determines whether there is an annular temperature gradient decrease being observed in the sensor interval. If “no” then pressure measurements are recollected and analyzed at 353 .
  • a determination at 355 is made that the gas dissolved in the fluid flowing up the annulus has begun to separate out or break out of the solution at the lowest point where a temperature decrease has been detected and has expanded or migrated to the all of the sections or intervals where the temperature decreases in 356 and 358 have been observed.
  • only one of the decision boxes 356 , 358 may be included while still complying with the principles disclosed herein.
  • a decision box 360 inquires as to whether the sensors disposed above the BOP (e.g., sensors 346 , 348 ) are observing temperature decreases as described above in 356 and 358 . If “yes”, than a determination is made that the wellbore influx is above the BOP and is inside the riser (e.g., riser 13 ) at 359 . If, on the other hand, the sensors disposed above the BOP are not observing temperature decreases as described above in 356 and 358 , then a determination is made that the influx is still below the BOP at 357 .
  • the sensors disposed above the BOP e.g., sensors 346 , 348
  • method 300 includes a decision box 362 wherein it is determined whether there is an absolute temperature increase being observed below the BOP. If “no” then a determination is made at 361 to either actuate the BOP or, if the BOP has already been actuated, that the BOP has not adequately sealed the annulus. If “yes” then a determination is made at 363 that the BOP has successfully actuated and has sealed the annulus.
  • observing an absolute temperature decrease in a sensor just below the actuated BOP allows a determination to be made that the BOP has not adequately sealed the annulus. This determination is based on the fact that fluids are likely leaking or flowing past the actuated BOP in the annulus thereby causing a temperature reduction just below the actuated BOP.
  • the determination at 364 as to whether the temperature and/or temperature gradient decline rate is high or low comprises comparing the observed values to a pre-determined threshold limit.
  • This threshold limit may be determined based on various factors such as but not limited to the operational capacity of the mud-gas separator (e.g., separator 50 ), the environmental conditions present at the well, and the properties of the drilling fluid or underground formation.
  • the determinations at 351 , 352 , 354 , 356 , 358 , 360 , and 364 further comprise additional sensor intervals above the BOP and analysis thereof.
  • additional above-BOP sensors and pressure gradient intervals can be measured and analyzed to enhance the measurement of the absolute temperature increases/decreases at 352 and 356 , the annular temperature increases/decreases at 354 , 358 and 360 , and the temperature and/or gradient decline rate at 364 .
  • the enhanced measurement may then be used to refine the determination of a wellbore influx above the BOP at 359 and the remedial measures taken at 365 and 367 .
  • an exemplary drill string 412 similar to drill string 12 includes annular flow rate sensors 442 , 444 , 446 , 448 , a BOP 429 , and a drill bit 416 .
  • drill string 412 includes flow rate sensor 445 that measures the flow rate in the inner bore of the drill string 412 and the flow rate in the annulus (e.g., annulus 22 ).
  • flow rate sensor 445 that measures the flow rate in the inner bore of the drill string 412 and the flow rate in the annulus (e.g., annulus 22 ).
  • Annular flow rate sensors 442 , 444 , 446 , 448 allow wellsite personnel to measure both the flow rate at each sensor (shown in FIG.
  • FIG. 9 notes the changes in both the absolute values as well as the gradients of flow rate measured by the sensors 442 , 444 , 446 , 448 .
  • An increase is noted by an upward facing arrow while a decrease is noted by a downward facing arrow, and the relative magnitude of the increase/decrease is shown by the size of the associated arrow.
  • the deepest or lowermost positioned annular flow rate sensor 442 is the first sensor to measure a flow rate increase, which is indicated in FIG. 9 with an upward facing line arrow.
  • the gradient between sensors 442 and 444 is also increasing due to the fact that the sensor 442 is measuring a flow rate increase while the sensor 444 is not. This increase in the flow rate gradient between sensors 442 and 444 is indicated in FIG.
  • the portion of the influx 447 disposed below the now closed BOP 429 is being compressed within the sealed annulus, and the portion of the influx 447 disposed above the BOP 429 is continuing to expand upward toward the sea surface 27 .
  • the annular flow rate measurements and gradients above the BOP 429 are increasing, and the annular flow rate measurements and gradients below the BOP 429 are zero or near zero.
  • the near-zero or zero-value flow rate measurements below the BOP 429 verify that BOP 429 has successfully closed and that the annulus (e.g., annulus 22 ) is now sealed.
  • the continued annular pressure gradient increase above the now actuated BOP 429 verifies that the influx 447 has migrated above the BOP 429 and has entered the riser (e.g., riser 13 ), such that it now becomes necessary for the wellsite personnel to determine what remedial actions are appropriate (e.g., diverter 60 or mud-gas separator 50 ).
  • FIG. 10 wherein a method 400 for detecting wellbore influx and migration above the BOP 429 , and determining the appropriate remedial action is shown. Though depicted sequentially as a matter of convenience, at least some of the actions shown can be performed in a different order and/or performed in parallel. Additionally, some embodiments may perform only some of the actions shown. Finally, in some embodiments some or all of the steps disclosed below may be performed manually by a person or persons, or may be performed, at least partially, by a computer.
  • the method 400 begins by collecting the flow rate readings from the various sensors (e.g., sensors 442 , 444 , 446 , and 448 ) throughout the drill string and computing a gradient for an interval between two of the various sensors at 450 .
  • the method 300 next includes a first decision box 452 determining whether an annular flow rate increase is observed at the sensors. If “no” then flow rate measurements are recollected and analyzed at 450 . If “yes” then another decision box 454 determines whether an annular flow rate gradient increase is being observed in the interval. If “no” then flow rate measurements are recollected and analyzed at 450 .
  • the method 400 next includes a decision box 456 which inquires as to whether the sensors disposed above the BOP (e.g., sensors 456 , 458 ) are observing flow rate increases as described above in 452 and 454 . If “yes”, then a determination is made that the wellbore influx is above the BOP and is inside the riser (e.g., riser 13 ) at 455 . If, on the other hand, the sensors disposed above the BOP are not observing flow rate as described above in 452 and 454 , then a determination is made that the influx is still below the BOP at 453 .
  • the sensors disposed above the BOP e.g., sensors 456 , 458
  • method 400 includes a decision box 458 wherein it is determined whether a zero or near zero absolute flow rate is being observed below the BOP. If “no” then a determination is made at 457 to either actuate the BOP or, if the BOP has already been actuated, that the BOP has not adequately sealed the annulus. If “yes” then a determination is made at 459 that the BOP has successfully actuated and has sealed the annulus.
  • the determination at 460 as to whether the flow rate and/or flow rate gradient increase rate is high or low comprises comparing the observed values to a pre-determined threshold limit.
  • This threshold limit may be determined based on various factors such as but not limited to the operational capacity of the mud-gas separator (e.g., separator 50 ), the environmental conditions present at the well, and the properties of the drilling fluid or formation.
  • the determinations at 451 , 452 , 454 , 456 , and 460 further comprise additional sensor intervals above the BOP and analysis thereof.
  • additional above-BOP sensors and flow rate gradient intervals can be measured and analyzed to enhance the measurement of the absolute flow rate increase at 452 , the annular flow rate increase at 454 and 456 , and the flow rate and/or gradient increase at 460 .
  • the enhanced measurement may then be used to refine the determination of a wellbore influx above the BOP at 455 and the remedial measures taken at 461 and 463 .
  • FIG. 11 wherein a method 500 for detecting wellbore influx and migration above the BOP is shown. Though depicted sequentially as a matter of convenience, at least some of the actions shown can be performed in a different order and/or performed in parallel. Additionally, some embodiments may perform only some of the actions shown. Finally, in some embodiments some or all of the steps disclosed below may be performed manually by a person or persons, or may be performed, at least partially, by a computer.
  • the method 500 begins by collecting strain measurements from various sensors distributed along the drill string and computing a gradient for an interval between two of the various sensors at 550 . If a wellbore influx occurs, the fluid flowing in from the formation will begin to fill the wellbore. Because the formation fluids are typically of a lower density than the drilling/completion fluids in the wellbore, the buoyancy forces acting on the drill string will be reduced as the formation fluid enters the wellbore. This reduction in the buoyancy causes an increase in the strain (tension) experienced by the drill string.
  • the method includes a first decision box 552 , inquiring into whether a strain increase has been observed by the sensors. If “no”, then strain measurements are recollected at 550 . If “yes” then a second decision box 554 inquires as to whether a strain gradient decrease is being observed in the interval.
  • strain measurement are recollected at 550 . If “yes” then a determination is made at 553 that there is an influx in the wellbore and its leading edge has advanced or migrated to the section or interval where the strain increases and decrease in 552 , and 554 , respectively, have been observed.
  • the method 500 includes a decision box 556 that makes a determination as to whether sensors below the now closed BOP are observing strain decreases. If “yes”, then a determination is made at 558 that the BOP has successfully actuated and has sealed the annulus. If “no” then a determination is made at 560 that the BOP has either not actuated or is not adequately sealing the annulus.

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US20130111985A1 (en) * 2011-11-07 2013-05-09 Intelliserv, Llc Method for efficient pressure and inflow testing of a fluid containment system through real time leak detection with quantification of pvt effects
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US10718206B2 (en) * 2014-02-18 2020-07-21 Schlumberger Technology Corporation Method for interpretation of distributed temperature sensors during wellbore operations
US20170067335A1 (en) * 2014-02-18 2017-03-09 Schlumberger Technology Corporation Method for interpretation of distributed temperature sensors during wellbore operations
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US20170139074A1 (en) * 2015-11-12 2017-05-18 Schlumberger Technology Corporation Control of electrically operated radiation generators
US10845501B2 (en) * 2015-11-12 2020-11-24 Schlumberger Technology Corporation Control of electrically operated radiation generators
US11578587B2 (en) * 2020-05-05 2023-02-14 Chevron U.S.A. Inc. Analysis of well operations using wellhead data
US11448061B1 (en) * 2021-03-04 2022-09-20 Saudi Arabian Oil Company Monitoring downhole leaks

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