US20130087388A1

US20130087388A1 - Wellbore influx detection with drill string distributed measurements

Info

Publication number: US20130087388A1
Application number: US13/648,231
Authority: US
Inventors: Daniel Marco Veeningen
Original assignee: Intelliserv LLC
Current assignee: Intelliserv LLC
Priority date: 2011-10-09
Filing date: 2012-10-09
Publication date: 2013-04-11
Also published as: EP2764207A1; EP2764207A4; WO2013055706A1

Abstract

A method for detecting a wellbore influx with drill string distributed measurements includes 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.

Description

CROSS-REFERENCE TO RELATED APPLICATIONS

This application claims the benefit of U.S. provisional patent application Ser. No. 61/545,188 filed Oct. 9, 2011 and entitled “Wellbore Influx Detection with Drill String Distributed Measurements.”

STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT

Not applicable.

BACKGROUND

Drilling personnel need as much information as possible about borehole and formation characteristics while drilling a well for safety and other reasons. 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. In some wells, a wellbore or formation fluid influx, also called a “kick”, can cause an unstable and unsafe condition at the surface or rig. Currently, wellsite personnel must rely on measurements taken at the surface in order to estimate the conditions downhole and determine whether a kick has occurred. After a kick is detected, the blowout preventer (BOP) may be closed and steps taken to “kill” the well, and regain control. However, 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.
Additionally, as is described above, it often becomes necessary to kill the well in the event of a kick. In these circumstances it is often advantageous to have accurate measurements of the conditions downhole, which are independent from surface data, in order to quickly identify the wellbore influx, analyze downhole conditions as the event unfolds, and to track the progress of well kill operations and to ensure their success. Thus, a need remains for improved techniques to identify and address drilling conditions during drilling operations.

SUMMARY

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.
Also disclosed are systems for detecting wellbore influx with a drill string distributed electromagnetic network with a computer system, including any one or more of the features and aspects described above and elsewhere herein.

BRIEF DESCRIPTION OF THE DRAWINGS

For a detailed description of exemplary embodiments of the disclosure, reference will now be made to the accompanying drawings in which:

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; and

FIG. 11 is still another method for detecting wellbore influx and migration above the BOP in accordance with the principles disclosed herein.

DETAILED DESCRIPTION

In the drawings and description that follow, like parts are typically marked throughout the specification and drawings with the same reference numerals. The drawing figures are not necessarily to scale. Certain features of the disclosure may be shown exaggerated in scale or in somewhat schematic form and some details of conventional elements may not be shown in the interest of clarity and conciseness. The present disclosure is susceptible to embodiments of different forms. Specific embodiments are described in detail and are shown in the drawings, with the understanding that the present disclosure is to be considered an exemplification of the principles of the disclosure, and is not intended to limit the disclosure to that illustrated and described herein. It is to be fully recognized that the different teachings of the embodiments discussed below may be employed separately or in any suitable combination to produce desired results.
In the following discussion and in the claims, the terms “including” and “comprising” are used in an open-ended fashion, and thus should be interpreted to mean “including, but not limited to . . . ”. Unless otherwise specified, 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. In addition, the term “t=0” denotes certain conditions at an initial time, while “t=1”, “t=2” and t=n+1 denote conditions at later moments in time. The symbol “≈” indicates minimal or no change in an associated value. Furthermore, as used herein, the term 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. In addition, in the discussion and claims that follow, it may be sometimes stated that 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. The various characteristics mentioned above, as well as other features and characteristics described in more detail below, will be readily apparent to those skilled in the art upon reading the following detailed description of the embodiments, and by referring to the accompanying drawings.
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.
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. In some embodiments, 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. Thus, 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. 1, 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. However, it should be noted that 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). For purposes of this disclosure, 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. Preferably 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.
Various types of 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. In some embodiments, the sensors 40 are annular pressure sensors. In other embodiments, 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.
As previously described, nodes 30 may include booster assemblies. In some embodiments, 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. Additionally, sensors 40 disposed on or within network nodes 30, allow measurements to be taken along the length of the drill string 12. Thus, 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. Besides the absolute value of pressure, temperature, strain, or flow rate at each node 30, 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. These absolute values and gradient values may then be tracked as time advances. Observed changes in absolute measurements and the associated gradients over time may then be compared either by preprogrammed software or wellsite personnel, such that the specific conditions occurring in the downhole environment may be monitored. As a result of this analysis, wellsite personnel may be able to make more informed decisions as more fully explained below.
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. Although only a few 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.
Due to safety concerns arising from the uncontrolled influx of a large volume of combustible hydrocarbons into the wellbore that are developing a flow path from the subsurface to the surface, it is important to detect the influx as soon as possible. In some circumstances, BOP 29 may be actuated such that the well is closed above the wellbore influx. However, in some cases, for example in deepwater wells, a leading portion of the wellbore influx may have already migrated above the BOP 29 at the time the rams or seals are closed. In the embodiments herein, downhole distributed measurements and high speed broadband telemetry systems (e.g., system 46) 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. In other embodiments herein, downhole distributed measurements on a high speed broadband telemetry system (e.g., system 46) allow wellsite personnel to monitor and manage well kill operations. In some embodiments, the measurements used are independent from surface measurements.
Referring still to FIG. 1, when an influx occurs in the borehole 36, fluid (e.g., hydrocarbons) 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. Because the formation fluids entering the borehole 36 (e.g., gas, oil, water, etc.) will typically be of a lower density and a higher temperature than the drilling fluid (e.g., drilling mud) or completion fluid, the hydrostatic pressure in the annulus 22 will drop while the temperature will initially rise. Additionally, after 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. Further, 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. Additionally, because the formation fluids are typically at a lower density than the drilling or completion fluids, the influx causes the buoyancy in the interval covered by the influx to be reduced. As a result, the strain experienced by the drill string will increase as the effective weight of the drill string increases. As the influx volume increases and expands to cover a larger section of the drill string, 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.
Referring now to FIG. 2, wherein an enlarged view of portion II-II in FIG. 1 is shown. 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.
In addition to diverter 60, 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. By forcing the annulus fluid over baffles 54, the gas is separated from the drilling fluid and rises to the top of vessel thereby exiting through outlet 55, while the remaining annulus fluid sinks to the bottom and exits via outlet 57. Each 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. In some embodiments of mud-gas separator 50, 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. Additionally, in some embodiments, 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. In particular, the mud-gas separator 50 will typically have a maximum flow rate capacity. Thus, if the wellbore influx is large enough such that the amount of gas or hydrocarbon contained within the drilling fluid is above the operational limits of separator 50, 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.
Furthermore, it is difficult to determine beforehand if 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. This is illustrated by the fact that the volume of a fluid at the BOP (e.g., BOP 29) will greatly expand as it progresses up the annulus 22 toward the sea surface 27. For example, 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. In this scenario, 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.
Referring now to FIG. 4, 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. In addition, 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). However, it should be understood that other embodiments may not include sensor 145 while still complying with the principles disclosed herein. Also, it would further be understood by one skilled in the art that sensors disposed on a drill string (e.g., sensors 142, 144, 146, 148) may simultaneously measure multiple variables, such as for example, pressure and temperature, while still complying with the principles disclosed herein. For the purposes of clarity, the embodiments disclosed herein will each concentrate on a single variable. In the embodiment shown, 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). Furthermore, according to the nomenclature contained within FIG. 4, 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. Also, 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.
During a drilling operation, at time t=0, an influx 147 of formation fluid enters the wellbore, but the influx 147 or kick is unnoticed as the influx 147 is below the deepest or lowermost sensor 142. At t=1 (a later moment in time from t=0), 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. In addition, 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. 4 with a downward facing block arrow next to the pressure gradient, VP, between the sensors 142, 144. As the hydrostatic pressure in the annulus decreases due to the influx 147, the pressure in the inner bore of the drill string 112 is also reduced. This is expressed by a decrease in the standpipe pressure (a surface measurement), as well as a decrease in the absolute pressure measured in the inner bore of the drill string 112 by sensor 145. At t=2, the second deepest annular pressure sensor 144 measures an annular pressure decrease, thereby also triggering a decrease in the gradient between sensors 144 and 146. At t=3, the wellbore influx 147 has migrated to above the BOP 129. 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. At t=4, the BOP 129 is closed. As a result, 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. Thus, 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. These positive absolute annular pressure readings below BOP 129 verify that BOP 129 has successfully closed and that the annulus (e.g., annulus 22) is now sealed. Additionally, the continued annular pressure gradient decrease above the now actuated BOP 129 verifies that the influx 147 has migrated above the BOP 129 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).
Referring now to 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.
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. If “no” then 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.
In other embodiments of method 100, only one or some of the decision boxes 152, 154, 155 may be present while still complying with the principles disclosed herein. For example, 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.
It should also be noted that if an influx is occurring, the pressure sensors above the leading of edge of the influx do not register an absolute pressure increase. This phenomenon allows for the location of the leading edge of the influx to be detected at 151. By contrast, if losses were occurring within the wellbore, all of the pressure sensors distributed along the drill string would register a pressure decrease. Additionally, the pressure decrease would also reach a maximum value at or near the point where the losses are occurring.
Once the determination is made that an influx has occurred in the wellbore, 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.
In either case, whether the influx is determined to be above the BOP at 158 or below the BOP at 157, it will often become necessary to actuate the BOP to stop any further influx below the BOP from expanding into the riser. As a result, 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.
Finally, once it is determined that the influx is above the BOP at 158, it is determined whether the pressure and/or pressure gradient decline rate measured in the intervals disposed in the riser is high at 160. If “yes”, then the operator may divert the flow off the rig or overboard at 162 as a remedial measure for the wellbore influx. If “no”, then the operator may line up and engage a mud-gas separator at 164.
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. Also, in some embodiments, the determination at 158 that the wellbore or gas influx is above the BOP is made based on information such as at t=4 in FIG. 4, wherein the annular pressure measurements and gradients below the closed BOP 129 are increasing while the annular pressure measurements and gradients above the BOP 129 are rapidly decreasing.
In further embodiments, the determinations at 152, 154, 156, 160 further comprise additional sensor intervals above the BOP and analysis thereof. These 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. For example, the additional sensor and sensor intervals allow a more refined analysis of the pressure and gradient decline rates above the BOP.
Additionally, it should be noted that 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. Specifically, the number of intervals available for measurement and analysis will depend upon the number of sensors placed along the drill string 112. For example, and with reference to FIG. 4, an annular pressure sensor may be disposed every 1,000 feet in the drill pipe section. For a drill string section that is 4,000 feet in length, for example, 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. Furthermore, five measurement sensors will yield 10 corresponding intervals.
Referring now to 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.
Referring briefly again to FIGS. 1 and 2, after a wellbore influx is detected a decision may be made to kill the well to regain control. In general, a well kill operation involves pumping heavy “kill mud” into the wellbore. There are various ways to place kill mud in the well to regain control. First, 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. Second, a conventional well kill initially requires activation of the BOP 29. Thereafter, 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. Third, 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. During some bullheading well kill processes, 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. During a well kill process, it is beneficial to monitor the pressures exerted by the kill mud and the pumping action on the formation in order to (1) prevent additional formation fluids from entering the wellbore; (2) avoid overcoming the formation pressure in the case of a conventional or dynamic well kill; and (3) ensure that the pressure rating of the equipment in use is not exceeded.
In the context of a dynamic or conventional well kill, 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. As a result, the fracture pressure of the formation at the bottom of the casing (e.g., casing 18), otherwise known as 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). Traditionally, during well kill operations, 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.
Referring again to FIG. 6, 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.
Next, 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. As a result, 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. Thus, after the determination is made at 253 to engage in a bullheading well kill process, 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.
If, on the hand, no bullheading well kill process is being used at 252, 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. Alternatively, if a dynamic well kill process is being used, kill mud is pumped down the drill string and returns are taken from the annulus at 254.
Next, the measurement sensors above and below the casing shoe are identified and the associated pressure readings from those sensors are collected at 256. Once the various pressure readings from the identified pressure sensors have been 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.
Once the annular pressure at the casing shoe has been interpolated at 258, a determination is made at 260 as to whether the annular pressure at the casing shoe is below a pre-determined threshold. If “no” then a determination is made at 264 to reduce the displacement rate or the pumping of the kill mud. As a result, the pumping parameters of the kill mud are adjusted, thereby reinitiating the analysis at 254. It should be noted that in other embodiments of method 200, the determination at 264 may include other known steps for reducing the pressure exerted by the kill mud such as but not limited to actuating the choke. Additionally, 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.
If, on the other hand, 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. For example, such 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. However, other factors may be considered while still complying with the principles disclosed herein.
As a result, through use of method 200 above, it is possible to more accurately determine the pressures experienced during the well killing operations, thereby resulting in better and more efficient management of well kill operations with resulting lower maximum pressures.
Referring now to FIG. 7, 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. In addition, 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). However, it should be understood that other embodiments may not include sensor 345 while still complying with the principles disclosed herein. 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). Furthermore, according to the nomenclature contained within FIG. 7, the symbol #T≈ indicates that there is no or a minimal change in the absolute temperature for a particular sensor and 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. Also, 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.
During a drilling operation, at time t=0, an influx 347 of formation fluid enters the wellbore, but the influx 347 or kick is unnoticed as the influx 347 is below the deepest or lowermost sensor 342. At t=1, (a moment later in time from t=0) the deepest or lowermost positioned annular temperature sensor 342 is the first sensor to measure a temperature increase because the formation fluids entering the wellbore are almost always at a higher temperature than the drilling or completion fluids being used. This increase is temperature is noted in FIG. 7 with an upward facing line arrow next to the absolute temperature, #T, for the associated sensor 342. In addition, 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.
As time advances, the influx 347 migrates to shallower depths, which may, in some cases, be above the BOP 329. As a result, 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. Thus, at t=2, the second deepest annular temperature sensor 344 measures an annular temperature decrease, thereby triggering a decrease in the gradient between sensors 344 and 346. At t=3, when the wellbore influx 347 has migrated above the BOP 329, sensor 346 also measures a decreasing temperature, and the gradient between the measurement sensors 346, 348 is also decreasing.
At t=4, 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. The measured increase in temperature below the closed BOP 329 serves as positive confirmation that the BOP 329 has successfully actuated and has therefore sealed the annulus. Additionally, the deceasing temperature gradients shown at t=4 indicate that the wellbore influx 347 has migrated above the BOP 329 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).
Referring now to 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. If “yes” then a determination is made at 351 that there is an influx in the wellbore and it has advanced or migrated to the sections or intervals where the temperature increases in 352, and 354 have been observed. In other embodiments of method 300, only one of the decision boxes 352, 354 may be included while still complying with the principles disclosed herein.
After the influx has been detected at 351, 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. If “yes”, then 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. In other embodiments of method 300, only one of the decision boxes 356, 358 may be included while still complying with the principles disclosed herein.
Once it has been determined, at 355, that the gas dissolved in the fluid flowing up the annulus has begun to separate from or break out of the solution and rapidly expand toward the surface, 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.
In either case, whether the influx is determined to be above the BOP at 359 or below the BOP at 357, it will often become necessary to actuate the BOP to stop any further influx below the BOP from expanding into the riser. As a result, 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.
In some embodiments of method 300, 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.
In the current embodiment, if it is determined that the influx is above the BOP at 359, a determination is made as to whether the temperature and/or temperature gradient decline rate measured in the intervals disposed above the riser is high at 364. If “yes” then wellsite personnel may divert the flow off the rig or overboard at 365 as a remedial measure for the wellbore influx. If “no” then the operator may line up and engage a mud-gas separator at 367.
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.
In other embodiments, the determinations at 351, 352, 354, 356, 358, 360, and 364 further comprise additional sensor intervals above the BOP and analysis thereof. These 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.
Referring now to FIG. 9, 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. In addition, 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). However, it should be understood that other embodiments may not include sensor 445 while still complying with the principles disclosed herein. Annular flow rate sensors 442, 444, 446, 448 allow wellsite personnel to measure both the flow rate at each sensor (shown in FIG. 9 as #F) 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. 9 as ∇F). Furthermore, according to the nomenclature contained within FIG. 9, the symbol #F≈ indicates that there is no or a minimal change in the absolute flow rate for a particular sensor and the symbol ∇F≈ indicates that there is no or a minimal flow rate gradient for a given set of sensors (e.g., sensors 442, 444, 446, 448) at that given point in time. Also, 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.
During a drilling operation, at time t=0, an influx 447 of formation fluid enters the wellbore, but the influx 447 or kick is unnoticed as the influx 447 is below the deepest or lowermost sensor 442. At t=1 (a later moment in time from t=0), 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. In addition, 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. 9 with an upward facing block arrow next to the flow rate gradient, ∇F, between the sensors 442, 444. At t=2, the second deepest annular flow rate sensor 444 measures an annular flow rate increase, thereby also triggering an increase in the gradient between sensors 444 and 446. At t=3, the wellbore influx 447 has migrated above the BOP 429. Sensor 446 measures a further increase in the absolute flow rate, the gradients between measurement sensors or stations 446, 448. At t=4, the BOP 429 is closed. As a result, 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. Thus, 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. Additionally, 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).
Referring now to 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. If “yes” then a determination is made at 451 that there is an influx in the wellbore and it has advanced or migrated to the sections or intervals where the flow rate increases in 452, and 454 have been observed. In other embodiments of method 400, only one of the above described decision boxes 452, 454 may be included while still complying with the principles disclosed herein.
Once the determination has been made that an influx has occurred in the wellbore at 451, 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.
In either case, whether the influx is determined to be above the BOP at 455 or below the BOP at 453, it will often become necessary to actuate the BOP to stop any further influx below the BOP from expanding into the riser. As a result, 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.
Additionally, if it is determined that the influx is above the BOP at 455, a determination is made as to whether the flow rate and/or the flow rate gradient increase measured in the intervals disposed in the riser is high at 460. If “yes” then the wellsite personnel may divert the flow off the rig or overboard at 461 as a remedial measure for the wellbore influx. If “yes” then the wellsite personnel may line up and engage a mud-gas separator at 463.
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.
In other embodiments, the determinations at 451, 452, 454, 456, and 460 further comprise additional sensor intervals above the BOP and analysis thereof. These 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.
Referring now to 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. Additionally, as the influx expands toward the surface, each of the sensors disposed above the leading edge of the influx experience an increase in strain whereas each of the sensors disposed below the leading edge of the influx will experience a greatly reduced increase in strain relative to the sensors disposed above the influx. As a result, the interval along the drill string in which the leading edge of the influx is occupying at any given time will show a decreasing gradient. Thus, 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. If “no” then 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.
Once the wellbore influx has been detected at 553, a determination is made to actuate the BOP at 555. Once the BOP is closed, fluid is no longer allowed to flow into the riser from the wellbore. As a result, the pressure of the annular fluid below the BOP will begin to increase. This increase in pressure applies an upward force on the drill string below the BOP and reduces the strain experienced by the drill string at that point. Thus, 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.
The embodiments set forth herein are merely illustrative and do not limit the scope of the disclosure or the details therein. It will be appreciated that many other modifications and improvements to the disclosure herein may be made without departing from the scope of the disclosure or the inventive concepts herein disclosed. Because many varying and different embodiments may be made within the scope of the inventive concept herein taught, including equivalent structures or materials hereafter thought of, and because many modifications may be made in the embodiments herein detailed in accordance with the descriptive requirements of the law, it is to be understood that the details herein are to be interpreted as illustrative and not in a limiting sense.

Claims

What is claimed is:

1. A method for detecting a wellbore influx with drill string distributed measurements comprising:

obtaining a first annular measurement from a first sensor disposed on a drill string;

obtaining a second annular measurement from a second sensor disposed on the drill string;

computing a gradient of a first interval defined by the first and second sensors; and

detecting a wellbore influx based on the gradient and the first and second annular measurements.

2. The method of claim 1 further comprising:

obtaining a third annular measurement from a third sensor disposed on the drill string;

wherein a plurality of intervals are defined between the first, second, and third sensors;

further computing at least one gradient over the plurality of intervals; and

detecting the wellbore influx based on the at least one gradient and the first, second, and third annular measurements.

3. The method of claim 1 wherein the first and second annular measurements include pressure, and further comprising measuring a drill string bore pressure from a bore sensor disposed on the drill string.

4. The method of claim 3 further comprising:

observing a decrease in the first or second annular pressure measurements;

observing a decrease in the pressure gradient of the first interval; and

detecting the wellbore influx based on the decreases.

5. The method of claim 4 further comprising locating the wellbore influx where the decreases are observed.

6. The method of claim 5 further comprising observing the decreases above a BOP and determining that the wellbore influx is above the BOP.

7. The method of claim 6 further comprising observing a pressure or gradient decline rate within a riser.

8. The method of claim 7 further comprising diverting a wellbore fluid if the decline rate is at or above a pre-determined rate.

9. The method of claim 7 further comprising lining up a mud-gas separator if the decline rate is below a pre-determined rate.

10. The method of claim 5 further comprising observing the decreases below a BOP and determining that the wellbore influx is below the BOP.

11. The method of claim 10 further comprising observing a pressure below the BOP, and:

if the below-BOP pressure is increasing, determining that the BOP has actuated and has sealed an annulus, or

if the below-BOP pressure is not increasing, actuating the BOP or determining an inadequate dealing of the annulus.

12. The method of claim 3 wherein the detecting the wellbore influx further comprises measuring an increasing annular pressure below a BOP in a closed position and measuring a decreasing annular pressure and a decreasing annular pressure gradient above the closed BOP.

13. The method of claim 1 further comprising:

pumping a kill fluid into the drill string;

identifying measurement sensors above and below a casing shoe;

computing an annular pressure at the casing shoe by interpolating measurements from the sensors above and below the casing shoe; and

if the annular casing shoe pressure is below a pre-determined threshold, increasing the pumping of the kill fluid; or if the annular casing shoe pressure is above the pre-determined threshold, reducing the pumping of the kill fluid.

14. The method of claim 1 further comprising:

pumping a kill fluid into a kill line to force a wellbore influx and original wellbore fluid into a formation;

observing a pressure gradient increase in a sensor interval below a BOP; and

detecting progress of the kill fluid in an annulus based on the pressure gradient increase.

15. The method of claim 1 wherein the first annular measurement comprises a first annular temperature measurement and the second annular measurement comprises a second annular temperature measurement.

16. The method of claim 3 further comprising:

observing an increase in the first or second annular temperature measurements;

observing an increase in the temperature gradient of the first interval; and

detecting the wellbore influx based on the increases.

17. The method of claim 16 further comprising locating the wellbore influx where the increases are observed.

18. The method of claim 17 further comprising:

observing an annular temperature decrease;

observing an annular temperature gradient decrease; and

detecting that gas is breaking out of solution and has advanced to the locations where the decreases are observed.

19. The method of claim 18 further comprising observing the decreases above a BOP and determining that the wellbore influx is above the BOP.

20. The method of claim 19 further comprising observing a temperature or temperature gradient decline rate within a riser.

21. The method of claim 20 further comprising diverting a wellbore fluid if the decline rate is at or above a pre-determined rate.

22. The method of claim 20 further comprising lining up a mud-gas separator if the decline rate is below a pre-determined rate.

23. The method of claim 18 further comprising observing the decreases below a BOP and determining that the wellbore influx is below the BOP.

24. The method of claim 23 further comprising observing a temperature below the BOP, and:

if the below-BOP temperature is increasing, determining that the BOP has actuated and has sealed an annulus, or

if the below-BOP temperature is not increasing, actuating the BOP or determining an inadequate dealing of the annulus.

25. The method of claim 1 wherein the first annular measurement comprises a first annular flow rate measurement and the second annular measurement comprises a second annular flow rate measurement.

26. The method of claim 25 further comprising:

observing an increase in the first or second annular flow rate measurements;

observing an increase in the flow rate gradient of the first interval; and

detecting and locating the wellbore influx based on the increases.

27. A method for detecting a wellbore influx with drill string distributed measurements comprising:

obtaining a first strain measurement from a first sensor disposed on a drill string;

obtaining a second strain measurement from a second sensor disposed on the drill string;

detecting a wellbore influx based on the gradient and the first and second strain measurements.

28. The method of claim 27 further comprising:

observing an increase in the first or second drill string strain measurements;

observing a change or a decrease in the drill string gradient of the first interval; and

detecting and locating the wellbore influx based on the increase and the decrease.

29. The method of claim 28 further comprising:

actuating a BOP; and

if strain measurement decreases are observed below the BOP, determining that the BOP has actuated and has sealed an annulus, or

if strain measurement decreases are not observed below the BOP, determining that the BOP has not actuated or determining an inadequate sealing of the annulus.

30. A method for detecting a wellbore influx with drill string distributed measurements comprising:

providing a plurality of sensors distributed on a drill string with an electromagnetic network;

identifying a plurality of intervals defined between two sensors that are adjacent or have intervening sensors;

obtaining an absolute measurement at two or more of the sensors;

computing a gradient for the measurement of the plurality of intervals; and

detecting a wellbore influx based on the gradient and the absolute measurements.

31. The method of claim 30 wherein the measurement includes at least one of pressure, temperature, flow rate, or drill string strain.

32. The method of claim 4 further comprising:

observing a decrease in the bore pressure; and

detecting the wellbore influx based on the decreases in the first or second annular pressure measurements, the pressure gradient of the first interval, and the bore pressure.

33. The method of claim 1 further comprising:

pumping a kill fluid into the drill string;

identifying a measurement sensor at or immediately adjacent to a casing shoe;

computing an annular pressure at the casing shoe by based on a measurement from the sensor; and

if the annular casing shoe pressure is below a pre-determined threshold, increasing the pumping of the kill fluid; or

if the annular casing shoe pressure is above the pre-determined threshold, reducing the pumping of the kill fluid.