Patent Application
20230127022
This disclosure relates generally to detection and mitigation of kicks, blow-outs, and other well-control events in relation to subterranean wells.
Hydrocarbons, such as oil or natural gas, can be retrieved from subsurface reservoirs by drilling wells. In some instances, a kick, blowout, or other well control event can occur in a well. A well control event is an undesirable subsurface fluid or gas flow influx from the subsurface reservoirs into a wellbore. Well control events can happen during drilling, tripping, completion, or other well operations. The influx can be caused by pressure imbalances between formation fluids and wellbore fluids, such as drilling mud or cement. The likelihood of a well control event increases as the well gets deeper due to increased pressures in deep wells. Well control events can have severe environmental and financial ramifications. Various equipment, systems, and method have been developed for detecting and mitigating well control events.
Certain aspects of the subject matter herein can be implemented as a computer-implemented method. The method includes initiating, by a computer system, a shear ram closure in a central bore of a blow-out preventer stack in response to a determination by the computer system of a loss of well control event and a determination by the computer system, based on a measurement received by the computer system from a joint locator sensor, that a tubing joint is not present within the central bore of the blow-out preventer stack. A pipe ram closure is initiated in response to a determination by the computer system that the shear ram has not fully closed after a predetermined time period since the initiation of the shear closure sequence.
An aspect combinable with any of the other aspects can include the following features. The initiating of the shear ram closure can be a first instance of an emergency closure sequence. A second instance of the emergency closure sequence can include the computer system initiating the pipe ram closure in response to the determination by the computer system of the loss of well control event and a determination by the computer system, based on a measurement received by the computer system from a joint locator sensor, that a tubing joint is present within blow-out preventer stack.
An aspect combinable with any of the other aspects can include the following features. The initiating of the pipe ram closure in response to the determination by the computer system that the shear ram has not fully closed after the predetermined time period can be a first instance of a shear ram closure sequence. A second instance of the shear ram closure sequence can include the computer system initiating a blind ram closure in response to a determination by the computer system that the shear ram has fully closed after the predetermined time period.
An aspect combinable with any of the other aspects can include the following features. The computer system can determine that the blind ram has fully closed.
An aspect combinable with any of the other aspects can include the following features. The predetermined time period since the initiation of the shear closure sequence can be a first predetermined time period and the determining that the blind ram has fully closed can be after a second predetermined time period. The second predetermined time period can begin with the initiation of the blind ram closure.
An aspect combinable with any of the other aspects can include the following features. The computer system can determine that the pipe ram has fully closed.
An aspect combinable with any of the other aspects can include the following features. The predetermined time period since the initiation of the shear closure sequence can be a first predetermined time period. The determining that the pipe ram has fully closed can be after a third predetermined time period beginning with the initiation of the pipe ram closure.
An aspect combinable with any of the other aspects can include the following features. The determining of the loss of well control event can include receiving, by the computer system measurements of fluid pressure, temperature, density, and volume of fluid flowing through a central bore of a blow-out preventer stack. At least one of the received measurements can be compared to a corresponding threshold. In response to the comparing, it can be determined that at least one of the received measurements is greater or lesser than the threshold by an amount indicating a loss of well control event.
An aspect combinable with any of the other aspects can include the following features. The measurement of the volume of fluid flowing through the central bore is based on real-time monitoring of changes in volume of a trip tank during tripping operations.
An aspect combinable with any of the other aspects can include the following features. The determining that the shear ram has not fully closed is based on a measurements received by the computer system by at least one of a shear ram location sensor or a hydraulic piston pressure sensor.
Certain aspects of the subject matter herein can be implemented as a well control system. The system includes a blow-out preventer stack that includes a central bore, a shear ram preventer, a pipe ram preventer, and a blind ram preventer. The system also includes a computer system communicatively coupled to the shear ram preventer, the pipe ram preventer, and the blind ram preventer. The computer system includes one or more processors and a non-transitory computer readable medium storing instructions executable by the one or more processors to perform computer operations. The operations include initiating a closure of the shear ram preventer in response to a determination by the computer system of a loss of well control event and a determination by the computer system, based on a measurement received by the computer system from a joint locator sensor, that a tubing joint is not present within the central bore of the blow-out preventer stack. The operations also include determining, after a predetermined time period since the initiation of the shear closure sequence, that the shear ram has not fully closed, and initiating a pipe ram closure in response to a determination by the computer system that the shear ram has not fully closed after the predetermined time period.
An aspect combinable with any of the other aspects can include the following features. The initiating of the shear ram closure can be a first instance of an emergency closure sequence. The operations can further include a second instance of the emergency closure sequence including initiating the pipe ram closure in response to the determination by the computer system of the well control event and a determination by the computer system, based on a measurement received by the computer system from a joint locator sensor, that a tubing joint is present within blow-out preventer stack.
An aspect combinable with any of the other aspects can include the following features. The initiating of the pipe ram closure can be in response to the determination by the computer system that the shear ram has not fully closed after the predetermined time period is a first instance of a shear ram closure sequence. The operations can also include a second instance of the shear ram closure sequence that includes initiating, by the computer system, a blind ram closure in response to a determination by the computer system that the shear ram has fully closed after the predetermined time period.
An aspect combinable with any of the other aspects can include the following features. The operations can further include determining that the blind ram has fully closed.
An aspect combinable with any of the other aspects can include the following features. The predetermined time period since the initiation of the shear closure sequence can be a first predetermined time period and the determining that the blind ram has fully closed can be after a second predetermined time period. The second predetermined time period can begin with the initiation of the blind ram closure.
An aspect combinable with any of the other aspects can include the following features. The operations can further include determining that the pipe ram has fully closed.
An aspect combinable with any of the other aspects can include the following features. The predetermined time period since the initiation of the shear closure sequence can be a first predetermined time period and the determining that the pipe ram has fully closed is after a third predetermined time period. The third predetermined time period can begin with the initiation of the pipe ram closure.
An aspect combinable with any of the other aspects can include the following features. The determining of the loss of well control event include the computer system receiving measurements of fluid pressure, temperature, density, and volume of fluid flowing through a central bore of a blow-out preventer stack. The determining of the well control event can also include comparing at least one of the received measurements to a corresponding threshold determining, in response to the comparing, that the at least one of the received measurements is greater or lesser than the threshold by an amount indicating a loss of well control event.
An aspect combinable with any of the other aspects can include the following features. The measurement of the volume of fluid flowing through the central bore can be based on real-time monitoring of changes in volume of a trip tank during tipping operations.
An aspect combinable with any of the other aspects can include the following features. The determining that the shear ram has not fully closed can be based on measurements received by the computer system by at least one of a shear ram location sensor or a hydraulic piston pressure sensor.
The details of one or more embodiments are set forth in the accompanying drawings and the description below. Other features, objects, and advantages will be apparent from the description and drawings, and from the claims.
The present disclosure describes systems and techniques that can be used for the operation of blow-out preventer system associated with a well for producing hydrocarbons or for other subsurface operations. The disclosure describes an intelligent system for detecting and responding to kicks, blowouts, and/or other well control events.
The subject matter described in this specification can be implemented in particular implementations, so as to realize one or more of the following advantages. Human error associated with detecting well control events and closing preventer valves and other flow control equipment and sensors can be reduced or eliminated. Full and complete closure of emergency valves can be more accurately and efficiently confirmed and appropriate alternative actions taken in the event of failure of such valves to completely close.
The intelligent well control system can include a blowout preventer (BOP) control system which can utilize hydraulic, electric, and/or acoustic components integrated with a well control programmable logic controller with various input modules capable of enhancing remote monitoring of well kill operations, BOP performance, well control detection, and intervention in case of loss of well control.
Support the drilling operation in identifying early kick indicator or eliminates errors in detection through the automated real time trip tank volume monitoring. This provides the opportunity for early identification of swab kick during tripping operations thus reducing kick size and pressure. It can also be used as a flow check tool on mobile offshore rigs.
Other benefits include incorporating an innovative emergency shut-in/shear system which can be activated with or without loss of signal and will isolate the wellbore in the event of a loss of well control thus isolating personnel, equipment and environment from hazardous conditions.
A smart well control system that is able to assess the presence of tool joint across the BOP stack prior to closing or shearing the string with the BOP pipe/shear rams. This will reduce the shut-in sequence and time, and reduce shut in time and the volume of kick taken as the space out to ensure tool joint not across the rams will have already been addressed.
In some embodiments, the well control system is able to provide confirmation of successful implementation of the BOP function initiated at the central control unit or BOP panel or mini panel or offsite from a well control programmable logic controller (PLC) device. For example, after the controller issue instructions to close a pipe ram pipe ram, the PLC can examine and check the input signals to confirm closure.
The details of one or more implementations of the subject matter of this specification are set forth in this detailed description, the accompanying drawings, and the claims. Other features, aspects, and advantages of the subject matter will become apparent from this detailed description, the claims, and the accompanying drawings.
The illustrated wellbore 108 extends substantially vertically (that is, vertical as designed) away from the earth’s surface 106. In alternative operating environments, all or portions of the wellbore 108 may be vertical, deviated at any suitable angle, horizontal, curved or both. The wellbore 108 may be a new wellbore, an existing wellbore, a straight wellbore, an extended reach wellbore, sidetracked wellbore, a multi-lateral wellbore, and other types of wellbores for drilling and completing one or more production zones. Conductor casing 110 and surface casing 112 ensure integrity of the borehole and isolate formations adjacent to wellbore 108. Cement 111 fills the annulus between conductor casing 110 and surface casing 112. Wellbore 108 may be used for producing wells and/or injection wells, and may be completely cased (with a conductor casing 110, surface casing 112, and inner casings and/or liners), partially cased (for example, with only the conductor casing 110 and surface casing 112), or open hole (for example, uncased) or variations thereof.
A drill string 116 or other wellbore tubular (such as a workover string or production string) can be lowered into the subterranean formation for a variety of purposes (for example, drilling, intervening, injecting or producing fluids from the wellbore, workover or treatment procedures, or otherwise) throughout the life of the wellbore 108. In this illustrated example, the workover or drilling rig 102 may comprise a derrick with the rig floor 104 through which the drill string 116 extends downward from the drilling rig 102 into the wellbore 108. Drill string 116 can comprise tubular pipe segments 118 connected with tool joints 120, and can include a drill bit 122 at its downhole end. The workover or drilling rig 102 may comprise a motor driven winch and other associated equipment for extending the drill string 116 into the wellbore 108 to position the drill string at a selected depth. While the operating environment depicted in
As illustrated, drill string 116 extends through blowout preventer (BOP) stack 126, which can stop or reduce a flow of fluids from wellbore 108 in the event of a pressure kick, blowout, or other well control event or emergency. In the illustrated example, BOP stack 126 has a central bore 127 in which an upper portion of drill string 116 is disposed. BOP stack 126 includes three preventers: a pipe ram preventer 128, a shear ram preventer 130, and a blind ram preventer 132, each of which can fully or partially close central bore 127. Pipe ram preventer 128 includes a pair of horizontally opposed metal rams, each with a half-circle hole on the edge to mate with the other so as to form a hole, with the hole sized such that, when closed, the rams can fit around pipe segments 118, thereby closing BOP stack 126 and preventing further flow of fluids around drill string 116. Shear ram preventer 130 includes a pair of rams with hardened tool steel blades designed to cut through a drill pipe segment 118. Blind ram preventer 132 includes a pair of metal rams which can close to seal off the BOP stack when there is no drill string segment or other object within the stack (for example, if drill string 116 has been severed by shear ram preventer 130). BOP stack 126 can also include an annular preventer 134 which can include a rubber packing element which can close around drill string 116. The particular configuration of the BOP stack 126 preventers may be optimized to provide maximum pressure integrity, safety and flexibility in the event of a well control incident. BOP stack 126 can also include various other preventers, spools, adapters, valves, and piping outlets (not shown) to permit, prevent, or regulate the circulation of wellbore fluids under pressure during normal operations and/or in the event of a well control incident or other situation or emergency.
As illustrated, pipe ram preventer 128, shear ram preventer 130, and blind ram preventer 132 can be individually actuated by, for example, hydraulic fluid that is circulated through control lines 138 from a hydraulic power unit (HPU) 136. The HPU 136 is operable to circulate a controlled-pressure hydraulic fluid to one or more of the preventers 128, 130, and/or 132 to actuate them to shut-in the wellbore 108.
Shown in more detail in
System 100 can include various sensors (shown generally as 180) within, connected, or in proximity of BOP stack 126. Such sensors can include, for example, pressure, temperature, and fluid weight/density sensors to measure the pressure, temperature, and density of drilling fluid 160 and/or other fluids flowing through drill string 116 and the surrounding annulus, and otherwise within, or into or out of, BOP stack 126. Other sensors can include actuator line flow sensors, accumulator charge & pressure sensors, sensors to measure flow to and from, and/or pressure within, BOP hydraulic components, and other suitable sensors.
System 100 can also include location detection sensors 182 in each of preventers 128, 130, and 132 to detect the location of the rams and associated hydraulic pistons and other components within preventers 128, 130, and 132, annular preventer 134, and/or other components of BOP stack 126. Such location detection sensors can include solid state magnetic field sensors, Hall Effect sensors, strain gauge, hydraulic piston pressure, or other suitable sensors. System 100 can further include pressure and/or other suitable sensors associated with the hydraulic pistons which drive the preventer rams.
While the shear rams of shear ram preventer 130 can be effective in cutting through a pipe segments 118 of drill string 116 or other tubular components, they may be ineffective at cutting through thicker, stronger, and/or more robust components such as tool joints 120. Therefore, and as described in more detail below, the location of tool joints 120 with respect to BOP stack 126 as the drill string 116 is tripped into or out of the wellbore can be important for proper functioning of BOP stack 126 in the event of a well control event or other situation requiring sealing of the wellbore via BOP stack 126. Therefore, system 100 can further include a tool joint locator sensor 184 which can indicate whether a tool joint 120 is present within BOP stack 126 proximate to shear ram preventer 130. Tool joint locator sensor 184 can be a magnetic or other suitable sensor type.
Well system 100 also includes a programmable logic controller (PLC) module 150, which is described in more detail in reference to
PLC module 150 can include various forms of digital computers, such as printed circuit boards (PCB), processors, digital circuitry, or otherwise. Additionally, the system can include portable storage media, such as, Universal Serial Bus (USB) flash drives. For example, the USB flash drives may store operating systems and other applications. The USB flash drives can include input/output components, such as a wireless transmitter or USB connector that may be inserted into a USB port of another computing device.
The processor can be configured to process instructions for execution within the PLC and can be designed using any of a number of architectures such as a complex instruction set computers processor, a reduced instruction set computer processor, or a minimal instruction set computer processor. The processor can either be a single-threaded processor or a multi-threaded processor and can be capable of processing instructions stored in the memory or on the storage device to display graphical information for a user interface on the input/output device.
The memory can store information within the controller and can be a computer readable medium, a volatile memory unit or a non-volatile memory unit. The storage device can provide mass storage for the controller. The processor and the memory can also be supplemented by, or incorporated in, ASICs (application-specific integrated circuits). Similarly, the storage unit can be a computer-readable medium, a floppy disk device, a hard disk device, an optical disk device, a tape device, flash memory, a solid state device (SSD), or a combination.
The input/output device provides input/output operations for the controller and can include a keyboard and/or pointing device, or a display unit for displaying graphical user interfaces. The features described can be implemented in digital electronic circuitry, or in computer hardware, firmware, software, or in combinations of them.
The apparatus can be implemented in a computer program product tangibly embodied in an information carrier, for example, in a machine-readable storage device for execution by a programmable processor; and method steps can be performed by a programmable processor executing a program of instructions to perform functions of the described implementations by operating on input data and generating output. The described features can be implemented advantageously in one or more computer programs that are executable on a programmable system including at least one programmable processor coupled to receive data and instructions from, and to transmit data and instructions to, a data storage system, at least one input device, and at least one output device. A computer program is a set of instructions that can be used, directly or indirectly in a computer to perform a certain activity or bring about a certain result. A computer program can be written in any form of programming language, including compiled or interpreted languages.
The computer program can be deployed in any form, including as a stand-alone program or as a module, component, subroutine, or other unit suitable for use in a computing environment. For instance to accommodate interface with the user, the features can be implemented on a computer having a display device such as a CRT (cathode ray tube), LCD (liquid crystal display), or LED (light-emitting diode) monitor for displaying information to the user and a keyboard and a pointing device such as a mouse or a trackball by which the user can provide input to the computer.
Additionally, such activities can be implemented via touchscreen flat-panel displays and other appropriate mechanisms. The features can be implemented in a control system that includes a back-end component, such as a data server, or that includes a middleware component, such as an application server or an Internet server, or that includes a front-end component, such as a client computer having a graphical user interface or an Internet browser, or any combination of them. The components of the system can be connected by any form or medium of digital data communication such as a communication network. Examples of communication networks include a local area network (“LAN”), a wide area network (“WAN”), peer-to-peer networks (having ad-hoc or static members), grid computing infrastructures, and the Internet.
Referring to
Inputs at step 302 can further include data from emergency shut in/shear system inputs 318 and tool joint position information 320 (from, for example, tool joint locator 184 of
Inputs at step 302 can further include data from the preventer ram position and ram hydraulic piston sensors and annular preventer sensors (for example, sensors 182 of
The above input data can be monitored and/or processed in real time by the PLC. In some embodiments, all of inputs 310 - 336 are monitored; in some embodiments, only some of the inputs 310-336 are monitored. In some embodiments, all of the inputs 310 are monitored and analyzed continuously and in real-time; in some embodiments, only some of the inputs are monitored continuously and in real-time and others are monitored periodically or intermittently.
Proceeding to step 350, the PLC module determines if one or more of the input signals 310-336. If at step 350 a determination is made that the signal has not been lost, the method proceeds to step 352 wherein a determination is made of whether there is an indication of a well control event. The determination steps 350 and 352 can in some embodiments be made periodically or can be made continuously (for example, while other steps of method 300 are occurring).
The determination of a loss of well control event (such as a blowout) at step 352 can be based on one or more of several factors or measurements. For example, a loss of well control event determination can be made based on an increase of wellhead pressure and/or temperature in drill string 116 and/or in the surrounding annulus exceeding a predetermined threshold (and/or a rate of change above a predetermined threshold). In addition or alternatively, the determination can be made based on a change in specific gravity (SG) of the fluids in drill string 116 and/or in the surrounding annulus or wellbore (for example, when there is no drill string in the hole) as compared to a predetermined threshold or rapid change in the return flow, active pit level or trip tank as compared to a predetermined threshold depending on the drilling or other activity at the time of the incident. Similarly, a rapid loss in weight-on-bit (WOB) or negative WOB can indicate a loss of well control event. These parameters (pressure, temperature, specific gravity, volume, changes in WOB, and others) can be considered together or separately by the PLC in determining a well control event and/or to reduce the risk of loss of well control to as low as reasonably practicable (ALARP).
During tripping operations, in addition to some or all of the above parameters, a loss of well control event at step 352 can be determined based on evaluation of trip tank volume. In some embodiments, the PLC module at step 352 can monitor trip tank volumes and flow rates in real time and compare current flow check data to past flow check “fingerprints” to determine a possible anomaly. Due to the active real-time monitoring of the volume of the trip tank with a calibrated trip level indicator, the PLC module at step 352 can detect changes in trip tank volume which may indicate a “kick” or other well control event. The PLC module can monitor trip tank volume in real time providing a positive indication of, for example, swabbed in kick where the volume of steel displacement is less than what is calculated while pulling out of hole or where the volume displacement is more than the steel displacement whilst tripping in hole. To enable such calculations, an exact bottom hole assembly (BHA) configuration can be entered by the user into the PLC module to be used in the calculations, thus improving trip monitoring accuracy.
In all, the active, real-time trip tank volume and flow monitoring combined with the real-time pressure, temperature, density, and other parameter monitoring of the system of the present disclosure enable more efficient and accurate well control event detection, and can take into account (and thereby reduce detection difficulties caused by) mud transfer activities, spills and leaks in surface equipment, drain back, mud weight adjustment, etc.. For example, the PLCmodule can be programmed to take into account surface leaks in the assessment of pit volume gain. Similarly, the system can account for mud transfer to and from the active or change in the active pit as a result of mud weight adjustment in the analysis of pit gain.
If, at step 352, the PLC module determines that there is no indication of a well control event (or at least no indication of an event of such a magnitude requiring (or making desirable) an emergency response to shut-in the wellbore), the method proceeds to step 354 wherein monitoring of inputs 310-336 continues. If, at step 352 the PLC module determines that there is an indication of a well control event (or an indication of a well control event of such magnitude requiring (or making desirable) an emergency response to shut-in the wellbore), the method proceeds to step 356, wherein the PLC module determines, based on tool joint sensors, whether a tool joint is across the BOP stack. As noted previously, a tool joint can prevent full shear by a shear ram preventer. If at step 356 the PLC module determines that no tool joint is present in the BOP stack, the method proceed to step 358 wherein the emergency shear system is activated. Proceeding to step 360, as part of the emergency shear system, the PLC module sends commands to the shear ram preventer to close the shear rams (step 362).
After step 362, the method proceeds to step 364 wherein the PLC module waits a pre-determined period of time before, at step 366, determining whether the shear rams have closed. With respect to the delay period at step 364 and the confirmation of shear closure at step 366, the logic assesses the shear criteria programmed in the PLC module and the PLC module monitors the shearing pressure and fluid volume required to shear the string in question and compares with the calculated shear pressure for the string. The sequence for the blind ram (step 368 - see below) will only be automatically activated after the preset period determined by the operator and programmed in the PLC module. The method proceeds from step 362 to 368 only if the delay period has occurred and the location sensor on the shear rams (and/or other data as discussed below) confirms (at 366) full stroke of the shear ram piston (i.e. full tubular shear). The time delay includes the period between activation of the shear function, shearing of the string and feedback to the PLC module to confirm shear with some margin. In some embodiments, the time period can be equivalent to minimum twice the response time expected for the shear rams to complete closure, or another suitable time period. The purpose of the delay period is to allow time for full closure of the shear rams and to confirm said closure prior to proceeding to the next step (for example, activation of the blind rams). This programmed delay period approach differs from other approaches which may rely on hydraulic timing circuits based on hydraulic pressure and flow rates which can be inconsistent and may result in the tubular caught in the path of the sealing rams when they are activated thereby resulting in partial or incomplete sealing of the wellbore, resulting in exposure of the surface and environment to the blow out condition.
With respect to confirmation of shear ram closure (and/or confirmation of other ram closure as described below), the PLC module can, in addition to using ram piston location sensor data, compare data from hydraulic fluid or accumulator pressure or volume sensors in the piston components and compare this data to expected volume changes and fluctuations (and/or previously determined or calculated volume or pressure data “fingerprints”) associated with full ram closure, and use any deviations from such expected data to confirm ram closure or determine incomplete ram closure or other ram closure failure.
In some embodiments, if the PLC module confirms shear ram closure using position location and/or pressure or volume data, then the PLC module can send a signal to the output module which can in turn transmit to the operator a positive indication (such as an indicator icon or light on a display screen) of such confirmation of shear ram closure. Such positive confirmation indication to the operator can be in addition to the display screen indication to the operator of the initiation or activation of the shear ram closure sequence. In this way, the operator obtains both an indication of the initiation of the shear ram closure sequence (i.e., that the hydraulic signals have been sent to the closure mechanism to initiate the closure) and also a confirmation that the shear ram closure sequence has successfully completed.
If at step 366 the PLC module determines that the shear has fully closed, the method proceeds to step 368 wherein the PLC module initiates closure of the blind rams. In some embodiments, the PLC module is programmed at step 370 to wait another predetermined time period before (at step 372) confirming closure of the blind rams. At step 374, the PLC module can alert the operator to the well control event and of the closure status. In some embodiments, the alert of the well control event can alternatively or in addition occur at another suitable time (such as upon initial recognition of the well control event at step 352).
Returning to step 366, if at step 366 the PLC module determines that the shear rams have not fully closed, then the method proceeds to step 380 wherein the PLC module closes the annular preventer and pipe ram. In some embodiments, the PLC module is programmed at step 382 to wait another predetermined time period before (at step 384) confirming closure of the blind rams. At step 386, the PLC module can alert the operator to the well control event and of the closure status. In some embodiments, the alert of the well control event can alternatively or in addition occur at another suitable time (such as upon initial recognition of the well control event at step 352).
Returning to step 356, if at step 356 the PLC module determines that a tool joint is present across the BOP stack, then the method proceeds to 376 wherein an emergency shut in is initiated without a pipe shearing sequence. Accordingly, and next, at step 378 the PLC module initiates closure of the annular preventer and pipe rams, completing steps 380, 384, and 386 as described above (and including, in some embodiments, wait period 382).
Returning to step 350, if the PLC module determines that an input signal has been lost (such determination in some embodiments occurring at any time during method 300), then the method proceeds to step 388 wherein, like step 356 discussed previously, the PLC module determines, based on tool joint sensors, whether a tool joint is present across the BOP stack. If at step 388 it is determined that no tool joint is present at the BOP stack, then the PLC module proceeds to step 358 and completes the well closure sequence starting at step 358 as described above (including, in some embodiments, wait period 364). If at step 388 the PLC module determines that a tool joint is present, then the method proceeds to step 376 and completes the well closure sequence starting at 376 as described above (including, in some embodiments, wait period 382).
In some embodiments, the well control detection and control system can include a real time inflow test module which can be integrated with the rig system and is able to support the decision to evaluate the result of a negative test or inflow test using any of the commercially available algorithm like the Horner Time (or any other methods) to evaluate the test data to ensure it complies with the zero-leak-rate criteria. Similarly, the well control system can utilize such an approach for HPHT wells to identify and distinguish in real-time between fluid expansion (due to temperature effects) and actual formation fluid influx, and to detect wellbore ballooning effect especially when drilling with mud weights close to the fracture gradient.
In some embodiments, the well control system can be remotely monitored with possible intervention from offsite real-time operations centers (RTOC). The system can monitor various well kill scenarios with possible intervention from offsite personnel. The intervention is not limited to sounding alarm, flashing light, or speed dial to the Driller or Tool pusher or rig manager or activating shut-in sequence in case of inability of the responsible personnel on location to shut in the well. While this specification contains many specific implementation details, these should not be construed as limitations on the scope of any claims or of what may be claimed, but rather as descriptions of features specific to particular implementations. Certain features that are described in this specification in the context of separate implementations can also be implemented in combination in a single implementation. Conversely, various features that are described in the context of a single implementation can also be implemented in multiple implementations separately or in any suitable sub-combination. Moreover, although features may be described as acting in certain combinations and even initially claimed as such, one or more features from a claimed combination can in some cases be excised from the combination, and the claimed combination may be directed to a sub-combination or variation of a sub-combination.
Similarly, while operations are depicted in the drawings in a particular order, this should not be understood as requiring that such operations be performed in the particular order shown or in sequential order, or that all illustrated operations be performed, to achieve desirable results. In certain circumstances, multitasking and parallel processing may be advantageous. Moreover, the separation of various system components in the implementations described should not be understood as requiring such separation in all implementations, and it should be understood that the described program components and systems can generally be integrated together in a single software product or packaged into multiple software products.
A number of implementations have been described. Nevertheless, it will be understood that various modifications may be made without departing from the spirit and scope of the disclosure. For example, example operations, methods, or processes described herein may include more steps or fewer steps than those described. Further, the steps in such example operations, methods, or processes may be performed in different successions than that described or illustrated in the figures. Accordingly, other implementations are within the scope of the following claims.
