Classifications

• • E—FIXED CONSTRUCTIONS
  • E21—EARTH OR ROCK DRILLING; MINING
  • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
  • E21B21/00—Methods or apparatus for flushing boreholes, e.g. by use of exhaust air from motor
  • E21B21/08—Controlling or monitoring pressure or flow of drilling fluid, e.g. automatic filling of boreholes, automatic control of bottom pressure
• • E—FIXED CONSTRUCTIONS
  • E21—EARTH OR ROCK DRILLING; MINING
  • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
  • E21B44/00—Automatic control systems specially adapted for drilling operations, i.e. self-operating systems which function to carry out or modify a drilling operation without intervention of a human operator, e.g. computer-controlled drilling systems; Systems specially adapted for monitoring a plurality of drilling variables or conditions
• • E—FIXED CONSTRUCTIONS
  • E21—EARTH OR ROCK DRILLING; MINING
  • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
  • E21B47/00—Survey of boreholes or wells
  • E21B47/06—Measuring temperature or pressure
• • E—FIXED CONSTRUCTIONS
  • E21—EARTH OR ROCK DRILLING; MINING
  • E21B—EARTH OR ROCK DRILLING; OBTAINING OIL, GAS, WATER, SOLUBLE OR MELTABLE MATERIALS OR A SLURRY OF MINERALS FROM WELLS
  • E21B2200/00—Special features related to earth drilling for obtaining oil, gas or water
  • E21B2200/20—Computer models or simulations, e.g. for reservoirs under production, drill bits

Definitions

• drilling fluid In conventional drilling operations, drilling fluid, sometimes referred to as mud, is circulated through the drillstring and well for the purposes of cooling and lubricating the drill bit, removing cuttings from the well, and maintaining wellbore stability.
• the drilling fluid is critical to maintaining primary well control through the application of hydrostatic pressure.
• the drilling rig must regularly stop circulation of the drilling fluid, set the drillstring into slips, break the connection between the top drive and the uppermost joint of pipe in a stand and then add another stand of drill pipe to the drillstring in a process commonly known as making a connection. After the connection is made, the lengthened drillstring may be used to achieve a greater wellbore depth.
• the wellbore In conventional drilling operations, the wellbore is open to the atmosphere at the surface such that the pressure at the top of the fluid column is atmospheric. Under static conditions, such as when a drill pipe connection is made, the pressure at the bottom of the wellbore is substantially determined by the weight of the fluid column in the well. Thus, under static conditions, the hydrostatic pressure at the bottom of the well is a function of the density of the drilling fluid and the depth of the well.
• the drilling rig must circulate drilling fluid through the well to cool and lubricate the drill bit, remove cuttings from the well, and maintain wellbore stability. As the circulation or flow rate increases, frictional pressures are created as fluid particles interact with the wellbore, drillstring, and other fluid particles.
• bottomhole pressure to increase as a function of drilling fluid flow rate through the well. While the amount of friction acting at any depth may vary through optimization of the fluid composition, fluid flow rate, and tubular design, there is no way to completely eliminate friction from the well.
• the hydrostatic pressure at the bottom of the well is a function of the density of the drilling fluid, the depth of the well, and friction influenced by the composition of the drilling fluid, fluid flow rate, and tubular design.
• the drilling rig typically sees bottomhole pressure that is substantially equivalent to the hydrostatic pressure when the mud pumps are off and higher than the hydrostatic pressure when the mud pumps are on, due to friction.
• a conventional hydraulic model is a software implemented tool that is used to estimate downhole process parameters, including wellbore pressure, based on one or more static data and, if available, dynamic data from live feeds.
• the hydraulic model is typically incorporated as part of a control system for a choke and rig automation and executes on the same computing system but may be a standalone application or system.
• conventional hydraulic models use static assumptions of dynamic process parameters (e.g., offline modeling) to estimate downhole pressure and other model parameters.
• conventional hydraulic models use real-time updates of dynamic process parameters (e.g., online modeling) to estimate downhole pressure and other model parameters. While offline modeling is typically used in planning operations prior to drilling, online modeling is typically used while drilling operations are underway, to assist in real-time decision-making.
• offline modeling is typically used in planning operations prior to drilling
• online modeling is typically used while drilling operations are underway, to assist in real-time decision-making.
• outputs of the conventional hydraulic model may be based solely on surface-based input data that is provided to the hydraulic model.
• rounding errors and resolution limitations of the surface-based equipment may result in the calculation of model parameters that tend to drift away and deviate from actual values.
• measurements from one or more downhole tools may be used to apply a correction factor to the hydraulic model.
• the purpose of a conventional hydraulic model is to provide the user with a realistic idea of what is happening downhole, in as close to real-time as is possible.
• the outputs of conventional hydraulic models are based entirely on surface-known or surface-acquired information, and the outputs are not influenced by changing downhole conditions until the changing downhole conditions are observed using the surface-based equipment.
• a method of calibrating a hydraulic model of a wellbore includes inputting, into the hydraulic model, one or more static values for one or more process parameters of the wellbore, receiving, at a control system, one or more dynamic values for one or more process parameters of the wellbore, measuring, via one or more downhole sensors, one or more measured values for one or more downhole process parameters at one or more locations at one or more depths within the wellbore, transmitting, via wired drillpipe telemetry, one or more measured values to the control system in real-time, validating, via the control system, whether one or more measured values are within an expected range, calculating, via the hydraulic model, one or more expected values for one or more process parameters, calculating, via the control system, for an expected value of a process parameter of interest, a quotient of the expected value and its corresponding measured value, calculating, via the control system, a correction factor for the expected value of the process parameter of interest when the quotient
• a method of detecting an unexpected downhole event in a wellbore includes measuring, via one or more downhole sensors, one or more measured values of downhole process parameters at one or more locations at one or more depths within the wellbore, transmitting, via wired drill pipe telemetry, one or more measured values to a surface- based control system in real-time, validating, via the control system, whether one or more measured values are within an expected range, calculating, via the hydraulic model, one or more expected values for one or more downhole process parameters at one or more locations at one or more depths within the wellbore, comparing, via the control system, one or more expected values with the corresponding one or more measured values, and providing an alert, via the control system, if the comparison of one or more expected values with the corresponding one or more measured values exceeds a predetermined range.
• a method of visualizing unexpected downhole events in a wellbore includes measuring, via one or more downhole sensors, one or more measured values of downhole process parameters at one or more locations at one or more depths within the wellbore, transmitting, via wired drill pipe telemetry, one or more measured values to a surfacebased control system in real-time, validating, via the control system, whether one or more measured values are within an expected range, calculating, via the hydraulic model, one or more expected values for one or more downhole process parameters at one or more locations at one or more depths within the wellbore, comparing, via the control system, one or more expected values with the corresponding one or more measured values, and outputting, to a display of the control system, a result of the comparison between the one or more measured values and the one or more expected values.
• a method of automatically removing debris from a wellbore includes inputting, via a control system, a target equivalent circulating density or a target pressure for a target depth within the wellbore, measuring, via one or more downhole sensors, one or more measured values of one or more downhole process parameters at one or more locations at one or more depths within the well, transmitting, via wired drillpipe telemetry, one or more measured values to a surface-based control system, validating, via the control system, whether one or more measured values are within an expected range, calculating, via the hydraulic model, one or more estimated values corresponding to the one or more measured values, comparing, via the control system, the one or more expected values with the one or more measured values, and rotating and reciprocating a drill string to a predetermined or random schedule to agitate and disperse cutting beds or other built-up debris in the wellbore until the one or more measured values is approximately equal to the one or more expected values or a predetermined
• FIG. 1 shows a conventional MPD drilling system.
• FIG. 2 shows a conventional MPD control system that uses a conventional hydraulic model and downhole pressure measurements to manage downhole pressure and provide kick detection.
• FIG. 3 shows a flow of information from the perspective of rig crew during an unexpected downhole event when using a conventional MPD control system and hydraulic model.
• FIG. 4 shows a drilling control system using WDP to improve management of downhole pressure and provide early detection of unexpected downhole events in accordance with one or more embodiments of the present invention.
• FIG. 5 shows a drilling control system using WDP to improve management of downhole process parameters and provide early detection of unexpected downhole events in accordance with one or more embodiments of the present invention.
• FIG. 6 shows a flow of information from the perspective of rig crew during an unexpected downhole event when using a drilling control system using WDP in accordance with one or more embodiments of the present invention.
• FIG. 7 shows an example of a system for calibrating a hydraulic model in accordance with one or more embodiments of the present invention.
• FIG. 8 shows an example of a system for a drilling control system using WDP in accordance with one or more embodiments of the present invention.
• FIG. 9 shows an example of a system using WDP in accordance with one or more embodiments of the present invention.
• FIG. 10 shows a computing system in accordance with one or more embodiments of the present invention.
• upper or top refer to portions of apparatus that are physically located above so-called lower or bottom portions of apparatus or are closer to the surface than lower or bottom portions of apparatus.
• lower or bottom refer to portions of apparatus that are physically located below so-called upper or top portions of apparatus or are closer to the bottom of the hole than upper or top portions of apparatus.
• static data means one or more values for one or more process parameters that, once known, are not subject to change including, for example, casing shoe depth and casing inner diameter.
• Dynamic data means one or more values for one or more process parameters acquired from surface-based instrumentation or equipment including, for example, pump speed, pump strokes, volumetric inflow rate, block height of traveling block, pressure in the standpipe, applied surface backpressure at the MPD manifold, and temperature.
• Downhole data means one or more values for one or more downhole process parameters transmitted from downhole to the surface using downhole telemetry including, for example, downhole pressure and temperature.
• FIG. 1 shows a conventional MPD drilling system 100.
• a floating platform or rig (not shown) is typically disposed over a body of water (not shown) to facilitate deepwater drilling and other operations.
• a subsea blowout preventer (“BOP”) 105 is disposed above and in fluid communication with the wellhead (not shown) of wellbore 110.
• a marine riser 115 is disposed above and in fluid communication with subsea BOP 105.
• a flow diverter 120 is disposed above and in fluid communication with marine riser 115, an annular closing system 125 is disposed above and in fluid communication with flow diverter 120, and an annular sealing system 130 is disposed above and in fluid communication with annular closing system 125.
• a slip joint 135, telescopic joint 140, ball joint 145, and rig diverter 150 are disposed above and in fluid communication with annular sealing system 130.
• a top drive system (not shown) controllably provides rotation from above to drillstring 155 that is disposed through a central lumen that extends from rig diverter 150 through to drill bit 157 disposed in wellbore 110.
• Annular sealing system 130 controllably seals the annulus surrounding drillstring 155 such that the annulus is encapsulated and is not exposed to the atmosphere.
• Annular closing system 125 provides an additional controllable seal capable of encapsulating the well and sealing the annulus surrounding drillstring 155 when rotation has stopped or annular sealing system 130, or components thereof, are being installed, serviced, maintained, removed, or otherwise disengaged.
• Flow diverter 120 diverts returning fluids from below the annular seal formed by annular sealing system 130 (or annular closing system 125) to distribution manifold 160 and MPD manifold 165 disposed on the drilling rig (not shown).
• MPD manifold 165 directs returning fluids to fluids processing systems disposed on the rig, such as, for example, mud-gas-separator 170 and shale shakers 175 that process returning fluids for reuse downhole by one or more mud pumps 185 by way of active mud system 180.
• fluids processing systems disposed on the rig such as, for example, mud-gas-separator 170 and shale shakers 175 that process returning fluids for reuse downhole by one or more mud pumps 185 by way of active mud system 180.
• a control system 1000 may control the flow rate of mud pumps 185, thereby controlling the injection rate of fluids downhole.
• control system 1000 may command one or more choke valves of MPD manifold 165 to a desired choke aperture setting, or position, thereby controlling the flow out.
• the pressure tight seal on the annulus provided by annular sealing system 130 allows for the control of wellbore pressure by manipulation of the choke aperture of the one or more choke valves of MPD manifold 165 and the corresponding application of surface backpressure.
• the choke aperture of MPD manifold 165 corresponds to an amount, commonly represented as a percentage, that MPD manifold 165 is open and capable of flowing.
• each choke valve of MPD manifold 165 may be fully opened, fully closed, or somewhere in between with a plurality of intermediate settings that refer to some degree of openness.
• MPD manifold 165 may include a plurality of choke valves, for the sake of clarity, it should be noted that the plurality of chokes are often referred to as a singular choke for the sake of simplicity when referring to the choke aperture or position of MPD manifold 165.
• the choke aperture of MPD manifold 165 may be reduced to further restrict fluid flow and apply additional surface backpressure.
• the choke aperture of MPD manifold 165 may be increased to increase fluid flow and reduce the amount of applied surface backpressure.
• new footage may be drilled as long the pressure of the fluid in the wellbore is greater than the pore pressure and less than the fracture pressure of all the open hole, or uncased, formations.
• An overbalanced condition occurs when the pressure in the wellbore is greater than the formation pressure.
• An underbalanced condition occurs when the pressure in the wellbore is less than the formation pressure.
• Most drilling occurs under a slight to moderate overbalanced condition.
• the drilling rig risks taking an influx of fluid known as a kick if the static downhole pressure in the wellbore is less than the pore pressure of the adjacent rock.
• the drilling rig risks causing a wellbore collapse if the static downhole pressure in the wellbore is less than the collapse pressure of the adjacent rock.
• the drilling rig risks fracturing the rock.
• Each of these scenarios may give rise to significant complications including a blowout or underground blowout. Therefore, the drilling crew must carefully maintain the drilling fluid composition such that the static downhole pressure in the wellbore is greater than the pore pressure of the adjacent rock and such that the dynamic downhole pressure in the wellbore is less than the fracture pressure of the adjacent rock for every open hole formation simultaneously.
• the drilling rig must stop drilling and set a casing to protect vulnerable formations.
• Other complications similar to those noted above, may arise when tripping pipe in and out of the well.
• an annular sealing system such as a rotating control device (“RCD”) or non-rotating active control device (“ACD”), is used to enclose the well above the BOP. Drilling returns are diverted from the annulus to the surface through the dedicated MPD manifold.
• the MPD manifold typically includes at least an array of sensors for measuring the pressure, temperature, and flow rate of the fluid, a plurality of choke valves, and a control system that uses input data from sensors and targets set by computer or rig personnel to control the choke.
• Contemporary MPD systems use a conventional hydraulic model to estimate downhole conditions based on static and/or dynamic data to determine an optimal surface pressure at the MPD manifold to maintain a constant downhole pressure.
• the choke While the drilling rig is circulating drilling fluid through the drillstring, the choke is partly or mostly open to maintain a lower surface pressure. However, when circulation is stopped, the choke is moved to a more closed position to achieve a higher fluid pressure at the surface. Pressure applied to the wellbore at the surface, by way of the MPD manifold, increases the bottomhole pressure by a substantially equal amount. While there is no way to entirely eliminate friction from the well, the use of ASBP MPD techniques allow the rig crew, or the control system if automated, to trade applied surface backpressure for downhole circulating friction pressure as the flow rate through the well varies, stabilizing downhole pressures and maintaining a constant downhole pressure at a defined depth.
• a functioning annular sealing system is critical for efficient ASBP MPD operations.
• the annular sealing system typically an ACD or RCD, substantially blocks the flow of drilling fluids allowing for the controlled application of surface pressure.
• FIG. 2 shows a conventional MPD control system 200 that uses a conventional hydraulic model 210 and downhole pressure measurements 230 to manage downhole pressure and provide kick detection.
• Conventional MPD control system 200 may input one or more of rheology, flow in, flow out, well geometry, standpipe pressure, ASBP, rate of penetration (“ROP”), rotations per minute, or other wellsite information transfer specification (“WITS”) data to hydraulic model 210 and kick detection system 240.
• a downhole pressure sensor provides measurements of downhole pressure, sometimes referred to as pressure while drilling (“PWD”) information for calibration 220, that is ultimately input into hydraulic mode 210.
• Hydraulic model 210 uses this information to select a choke position for the MPD manifold that achieves the target choke pressure 260 as measured on the surface at the MPD manifold, to achieve a desired downhole pressure.
• a significant issue with conventional hydraulic model 210 is that the outputs of the model 210 are based entirely on surface-known or surface-acquired information and an initial calibration, and the outputs cannot change due to changing downhole conditions until the changing downhole conditions are observed using surface-based instrumentation (and may have already changed since being observed), such that they cannot provide early detection of unexpected downhole events.
• kick detection is challenging, and the occurrence of a kick is not always obvious to the driller.
• the ROP or drilling speed it is common for the ROP or drilling speed to increase in an event known as a drilling break.
• a drilling break occurs in part because the pressure differential between the formation and the wellbore acts to push the rock into the wellbore.
• a drilling break is not a positive confirmation of an influx event because an increase in the ROP may be caused, for example, by drilling through a harder formation and into a softer formation.
• an influx of fluid occurs, it may displace fluid already in the well, resulting in higher-than-expected levels of drilling fluids stored in surface tanks of the active mud system.
• a tank mud level which is higher than the expected tank mud level is typically considered positive confirmation of an influx.
• a kick of hydrocarbon gas may go into solution with the drilling fluid without substantially affecting the volume of the drilling fluid. In such a case, the volume of drilling fluid at the surface may not change noticeably until the solution gas is circulated closer to the surface where the decreased hydrostatic pressure allows the gas to come out of solution.
• kick detection systems 240 use surface-based instrumentation to detect signs of a kick and alert the crew. In a conventional drilling operation, this typically includes a signal from a return flow line sensor to indicate relative high flow and a signal from pit volume totalizing system to indicate accumulation of drilling fluid at the surface. While better than a manual attempt to detect influxes, early kick detection systems 240 of conventional drilling operations depends on extremely high flow rates or the accumulation of mass at the surface before the alarm is triggered, such that the scale of the event is already large before the rig crew even becomes aware of it.
• kick detection system 240 has a major drawback in that all the instrumentation to detect an influx is based at the surface and conventional kick detection system 240 has no knowledge of what is happening downhole.
• kick detection system 240 is a separate and standalone system separate and apart from MPD control system 200. While kick detection is just one example, there are a number of unexpected downhole events for which there is no definitive early detection mechanism, posing substantial risk to the safety of the operation, rig crew, and environment.
• Mud pulse telemetry is the most commonly used type of downhole telemetry and uses the mud in the wellbore as the transmission medium. In essence, mud pulse telemetry uses pressure pulses to encode and transmit data to the surface.
• Mud pulse telemetry systems include a downhole turbine that rotates when the drilling fluid is circulating. The rotation of the downhole turbine is used to generate a current that is used to controllably oscillate a poppet or dump valve in the drillstring, that increases or decreases pressure in the drillstring. In this way, the downhole turbine and valve transmit data encoded in high or low pressure pulses.
• mud pulse telemetry requires a significant amount of power to transmit a detectable signal to the surface and consequently, the ability of a mud pulse telemetry system to transmit a downhole signal to the surface is reduced as circulation decreases.
• the pressure fluctuations are decoded to extract the data from the high-pressure and low-pressure pulses transmitted.
• the surface receiver views high and low pressure pulses as a sequence of ones and zeros to be decoded while other systems use elapsed time between high and low pressure pulses as the information to be decoded.
• the commonality with these types of transmission methods is that the mud in the drill pipe is the transmission medium.
• drilling fluid as the transmission medium is not optimal for a number of reasons. Under normal operation, small pressure fronts within the drill pipe tend to attenuate over short distances. Drillstring dynamics may also interfere with the pressure fronts travelling within the pipe. Other irregularities in the circulating system such as pump noise can also interfere with the signal.
• the onsite rig crew will decrease the transmission rate or increase the amplitude of the pressure pulses to improve system reliability. However, increasing the pressure pulse amplitude may require a reconfiguration of the downhole tool while slowing the transmission rate reduces the amount of information capable of being transmitted in a unit of time.
• Modern mud pulse telemetry tools are coupled with a variety of downhole sensor packages, typically disposed at or near the bottom hole assembly (“BHA”).
• BHA will typically include at least one or more directional survey tools, pressure sensors, temperature sensors, or acceleration sensors.
• Natural gamma ray tools are also commonly used to identify formations with high organic content.
• More advanced BHA sensor packages include resistivity and density logs among others to describe the oil-bearing potential, near wellbore porosity, and near wellbore permeability.
• WDP is a relatively new type of downhole telemetry that uses wired connections to substantially improve the speed, throughput, reliability, and availability of data transmission in comparison to conventional mud pulse and other conventional means of downhole telemetry.
• a WDP system may be coupled with various downhole sensor packages. While WDP telemetry is similar to mud pulse telemetry in that it transmits data from downhole to the surface, WDP telemetry relies upon coaxial cable, rather than drilling fluid, as the transmission medium.
• the coaxial cable is capable of electrically transmitting signals substantially faster than encoded pressure pulses and is capable of transmitting substantially more data per second than encoded pressure pulses. Further, coaxial cable isolates the signal from drillstring and fluid dynamics, increasing the reliability of the signal and network availability. As such, WDP telemetry eliminates the problems associated with using pressure pulses transmitted via mud to transmit data.
• WDP telemetry While mud pulse telemetry systems are, for mechanical reasons, only disposed near the BHA and consequently only include sensors disposed as part of the BHA, WDP telemetry uniquely enables the use of a plurality of different types or kinds of sensor packages, that may be disposed at one or more locations, at one or depths, anywhere along the length of the drillstring, because the coaxial cable of the WDP system extends along the length of the drillstring. While mud pulse telemetry systems require drilling fluid to flow at a high rate to even transmit data and cannot transmit data when circulation has stopped, WDP telemetry has no such limitation and is capable of transmitting data whether the drilling fluid is circulating or not.
• mud pulse telemetry stops transmitting data during the transient connection ramping periods when making connections, effectively causing a blackout period where the surface does not receive data from downhole.
• WDP telemetry is capable of effectively transmitting data regardless of the state of circulation and even through transient connection ramping periods.
• WDP telemetry has a narrower window of blackout when a pipe connection is broken to add or take away a stand of drill pipe.
• WDP telemetry improves the speed, throughput, reliability, and availability of the data and can achieve transmission rates of 57,600 bits per second or even more.
• a hydraulic model is a software implemented tool that is used to estimate downhole process parameters under various conditions.
• the wellbore and drillstring may be defined and partitioned into segments based on similar geometry. Each segment may have an associated hydrostatic pressure and an associated applied pressure on one end of the segment.
• the hydraulic model may then calculate the flow area and velocity and, given fluid rheology, calculate the pressure drop across the segment for the given flow rate.
• the hydraulic model may also account for density changes due to the pressure applied to the drilling fluid. In some cases, the hydraulic model may even combine these to provide an estimate of downhole pressure under specified conditions of fluid rheology and flow.
• the hydraulic model may account for heat transfer between the drilling fluid and the surrounding formation or body of water.
• the hydraulic model may account for pipe motion such as tripping in and out of the hole or drillstring rotation.
• the hydraulic model may assume that the drillstring or well behaves as a rigid body or accounts for the flexibility of the drillstring and wellbore compressibility effects. While the above-noted examples are merely exemplary, advanced hydraulic models may account for as many of the physical realities acting on the well as is possible with a particular drilling system.
• hydraulic models have primarily been used in offline applications, specifically, well planning prior to undertaking drilling operations.
• the drilling engineer may use a hydraulic model to verify that a particular well can be safely drilled under a particular set of assumptions.
• the drilling engineer may analyze different scenarios including, for example, sensitivity analysis of differing flow rates, identifying maximum tripping speed, or managing an influx of a particular size.
• the result of these activities is a well plan that is used during drilling operations.
• the onsite rig crew of the drilling operation are tasked with maintaining the operability of the rig and maintaining drilling parameters to the specification set by the offsite engineering team. While the onsite decision making is critical to the safe and efficient operation of the rig, the information provided by the hydraulic model is typically consumed by the offsite engineering team rather than the onsite rig crew, thereby preventing integration of the hydraulic models into live drilling control systems.
• hydraulic models may be used to estimate downhole parameters based on surface-acquired data during drilling operations.
• the objective of an online hydraulic model is to provide the rig crew with a realistic idea of what is actually happening downhole based on the data available on the surface.
• the hydraulic model output is based entirely on surface-known or surface- acquired data.
• the outputs of the hydraulic model are not influenced by changing downhole conditions until the changing downhole conditions are observed on the drilling rig via surface-based instrumentation or equipment. This means the hydraulic model outputs have no timely dependencies on downhole information because downhole conditions may change faster than they are transmitted and received on the surface.
• MPD is an application where the use of an online hydraulic model plays a critical role in the operation.
• MPD is being adopted as a means to extend the envelope of drillable wells, proactively maintain the primary well control barrier, and reduce drilling risks.
• the most common form of MPD today is ASBP MPD which uses one or more chokes of an MPD manifold and closed-loop drilling techniques to maintain a constant downhole pressure by varying the application of surface backpressure.
• ASBP MPD which uses one or more chokes of an MPD manifold and closed-loop drilling techniques to maintain a constant downhole pressure by varying the application of surface backpressure.
• the high-rate fluid circulation causes friction pressures to act on the well.
• the friction pressures go to zero as the downhole circulation rate goes to zero.
• MPD proactively controls the annular pressure profile in the annulus of the well.
• one or more chokes of the MPD manifold are controllably adjusted to apply surface backpressure to offset the downhole dynamic pressure change. Notwithstanding, friction is not proportional to flow rate; a small circulating rate increase when the circulating rate is low may have very little effect on the downhole friction while a small circulating rate increase when the circulating rate is high may have a large effect on the downhole friction.
• This information was generated offline, then used by the onsite rig crew to manually adjust the applied surface backpressure of the one or more chokes of the MPD manifold as a function of flow rates. While this approach greatly improved upon the lack of an active annular pressure management approach, the lack of an online hydraulic model forced a manual control mode that required a human in the loop, the use of standalone control screens, and radio communications between rig crew representing different teams onboard the drilling rig.
• the hydraulic model sees the pump moving at a slower speed and recalculates the expected value of downhole pressure.
• the hydraulic model provides a value for target pressure as measured on the surface that is calculated to achieve the expected value of the downhole pressure.
• This target pressure is fed to the choke controller which automatically adjusts the one or more chokes of the MPD manifold to maintain the downhole pressure at the anchor point constant.
• FIG. 3 shows a flow of information 300 from the perspective of rig crew 310, during an unexpected downhole event when using a conventional MPD control system (e.g., 200 of FIG. 2) and hydraulic model (e.g., 210 of FIG. 2).
• a significant problem of conventional MPD control systems is that the rig crew 310 receive a multitude of inputs from a variety of disparate sources and has to marshal that information to manage the choke position of the MPD manifold (e.g, 165 of FIG. 1) via choke controller 250.
• rig crew 310 may receive downhole measured data 230, calculated data from hydraulic model 210, surface-measured or surface-acquired data 205, and kick detection information 240.
• kick detection 240 provides output based solely on surface- acquired data and downhole measured data 230 is only used to calibrate calculated outputs of the hydraulic model (e.g., 210 of FIG. 2).
• MPD systems represent a substantial improvement over conventional drilling practice and even early implementations of MPD, some shortcomings remain.
• MPD systems treat choke control and kick detection as separate and independent features, with no data exchanged between them.
• Static configurations and data are used to control one or more chokes of the MPD manifold and live data acquired from surface instrumentation is fed into the hydraulic model. Imperfect resolution or rounding errors in the input data may be compounded when combined with other aspects of the hydraulic model, so the onboard rig crew typically calibrate the hydraulic model on an intermittent basis using the PWD system.
• the PWD system is not available when the mud pumps are ramped down to zero during connections, so the hydraulic model fills in the gaps by providing expected values of downhole pressure to the choke controller in real-time during, for example, PWD blackout periods.
• kick detection and other unexpected downhole event systems are operated separately and independently from the choke controller.
• contemporary kick detection methodologies use only surface-acquired data and operate without knowledge of actual downhole conditions.
• contemporary kick detection methods are typically separated from the choke control methods to prevent the MPD system from exceeding the authority granted;
• MPD systems are typically operated as a part of the primary well control barrier and may only be used in secondary well control situations under specific authorization.
• the human operator may have relinquished primary control of the choke, the well control dynamic leads to situations where the human operator must quickly take in varied information, from multiple systems, to rapidly figure out what is happening, and then act to prevent further escalation of the unexpected downhole event. This process often results in several minutes of observation and functional inaction, which takes place as an unexpected downhole event is unfolding, and that typically gets more serious with the passage of time.
• MPD using WDP uses data from downhole sensors to improve management of wellbore pressure, calibrate a hydraulic model, provide early detection of unexpected downhole events, augment surface-based automation, provide visualization of dynamic wellbore conditions, and automate removal of debris from the wellbore.
• the control system and rig crew are provided with actionable real-time information that enables drilling to proceed in an optimal manner.
• data from downhole sensors may be provided to a standalone kick detection system to provide substantially earlier detection of kicks and other unexpected downhole events.
• Coupling online hydraulic modeling with real-time WDP telemetry presents significant advantages including early unexpected downhole event detection in operations with MPD and WDP or in WDP standalone operations.
• One of the major drawbacks of conventional event detection technology is that the data flowing into an event detection system is surface-acquired or single-point time delayed low-frequency data. Any alarms or automated functions are triggered with very limited direct knowledge of downhole conditions. While estimated hydraulic model data closely match measured downhole data under normal conditions, actual downhole conditions may not match the model during contingencies.
• FIG. 4 shows a drilling control system 400 using WDP 430 to improve management of downhole pressure and provide early detection of unexpected downhole events in accordance with one or more embodiments of the present invention.
• control system 400 uses downhole measurements of process parameters that are used to both calibrate and update hydraulic model 410 and improve kick detection 440 to enable true early detection of unexpected downhole events.
• conventional MPD control systems e.g., 200 of FIG. 2 leverages mud pulse telemetry, when it is available, it provided limited bandwidth, limited transmission speeds, poor reliability, and long periods of unavailability during critical operations, such that, changes downhole were not identified on the surface until the surface-based instrumentation received it.
• WDP 430 provides almost instantaneous data transmission via coaxial cable, with substantially increased bandwidth, transmission speed, reliability, and availability (in contrast to mud pulse telemetry that only works when the mud pumps are sufficiently circulating).
• WDP 430 enables the deployment of a plurality of sensors (not independently illustrated) at various locations and depths along the drillstring, not just at the BHA.
• hydraulic model 410 provides kick detection system 440 with one or more expected values for one or more downhole process parameters, such that kick detection 440 now has expected values and measured values for one or more downhole process parameters, received in real-time, such that kick detection 440 can detect an unexpected downhole event the moment the measured value of a process parameter starts to deviate from the expected value of the process parameter, in this case, when the Measured Value of process parameter DHT1 starts to deviate from the Expected Value of DHT1.
• the same event may be detected by other sensors for the same or other process parameters (e.g., DHT2, DHT3, DHT4, and DHT5) deployed at other locations, each of which may confirm the early detection identified with respect to process parameter DHT1.
• DHT2, DHT3, DHT4, and DHT5 deployed at other locations, each of which may confirm the early detection identified with respect to process parameter DHT1.
• detecting the kick at the deviation of the Measured Value from the Expected Value of process parameter DHT1 and the near instantaneous transmission of that information to the surface via WDP telemetry, provides substantially earlier detection of an unexpected downhole event than conventional kick detection systems are capable of providing.
• a method of detecting an unexpected downhole event in a wellbore may include measuring, via one or more downhole sensors, one or more measured values of one or more downhole process parameters, at one or more locations at one or more depths within the wellbore.
• the method may include transmitting, via wired drill pipe telemetry, one or more measured values to a surface-based control system in real-time.
• real-time means without significant delay occasioned by the transmission means or medium, such that a downhole measured value of a process parameter is transmitted and received on the surface before the process parameter has had time to significantly change downhole.
• the method may further include validating, via the control system, whether one or more measured values are within an expected range as a sanity check, calculating, via the hydraulic model, one or more expected values for one or more downhole process parameters at one or more locations at one or more depths within the wellbore, comparing, via the control system, one or more of the expected values with the corresponding one or more of the measured values, and providing an alert, via the control system, if the comparison of one or more expected values with the corresponding one or more measured values exceeds a predetermined range.
• the comparison may include calculating a difference between the one or more expected values and the corresponding one or more measured values. In other embodiments, the comparison may include calculating a difference between the one or more measured values and the corresponding one or more expected values. In still other embodiments, the comparison may include calculating a quotient of the one or more expected values and the corresponding one or more measured values, where a deviation from unity is indicative of a difference. In still other embodiments, the comparison may include calculating a quotient of the one or more measured values and the corresponding one or more expected values, where a deviation from unity is indicative of a difference.
• the comparison may use any other type or kind of metric to describe the divergence or deviation between the one or more measured values and the corresponding one or more expected values in accordance with one or more embodiments of the present invention.
• the hydraulic model does not need to be precisely calibrated for early detection of an unexpected downhole event; it needs only to provide an explanation to the kick detection system for major changes in the measured values, to prevent false alarms.
• a further improvement in detectability and robustness may be achieved by analyzing measured and expected values at multiple points (e.g., DHT1, DHT2, DHT3, DHT4, and DHT5 of FIG. 4) along the drillstring. Analysis may be based on a weighted sum of the data from all or a subset of measurement locations, where the weights may be a combination of positive and negative numbers. Such approaches may reduce the model error and hence the probability of false positives.
• Plotting data from rig instrumentation is a common practice within the drilling industry. Time-series plotted data allows the user to see the history of one or more variables, such as a process parameter of interest, quickly displaying magnitude change and rate of change in a variable over time.
• multicolor plots on an x/y coordinate plane may be used to show the downhole pressure or equivalent circulating density (“ECD”) as a function of time and depth, providing the user with a real-time depiction of what is happening downhole.
• ECD equivalent circulating density
• plotting data from a raw measured value provides the user with historical context, it does not provide the user with situational context. For the user to make correct decisions, the user must first develop a thesis for what is happening downhole, which may not be consistent with what instrumentation is measuring and displaying.
• a method of visualizing unexpected downhole events in a wellbore may include measuring, via one or more downhole sensors, one or more measured values of one or more downhole process parameters at one or more locations at one or more depths within the wellbore, transmitting, via wired drill pipe telemetry, one or more of the measured values to a surface-based control system in real-time, validating, via the control system, whether one or more measured values are within an expected range as a sanity check, calculating, via the hydraulic model, one or more expected values for one or more downhole process parameters at one or more locations at one or more depths within the wellbore, comparing, via the control system, one or more expected values with the corresponding one or more measured values, and outputting, to a display of the control system, a result of the comparison between the one or more measured values and the one or more expected values.
• the comparison may include calculating a difference between the one or more expected values and the corresponding one or more measured values. In other embodiments, the comparison may include calculating a difference between the one or more measured values and the corresponding one or more expected values. In still other embodiments, the comparison may include calculating a quotient of the one or more expected values and the corresponding one or more measured values, where a deviation from unity is indicative of a difference. In still other embodiments, the comparison may include calculating a quotient of the one or more measured values and the corresponding one or more expected values, where a deviation from unity is indicative of a difference.
• the comparison may use any other type or kind of metric to describe the divergence or deviation between the one or more measured values and the corresponding one or more expected values in accordance with one or more embodiments of the present invention.
• outputting may include plotting one or more of the one or more expected values, the one or more measured values, and the comparison of the one or more expected values and the one or more measured values, or combinations thereof.
• outputting may include plotting one or more of the one or more expected values, the one or more measured values, and the comparison of the one or more expected values and the one or more measured values, or combinations thereof, as a color-coded heat map.
• the outputting may use any other type or kind of output display to show the divergence or deviation between the one or more measured values and the corresponding one or more expected values in accordance with one or more embodiments of the present invention.
• a drilling control system 400 using WDP 430 may facilitate real-time communication of downhole data between WDP 430 and choke controller 230 to improve the management of wellbore pressure.
• Conventional MPD control systems e.g., 200 of FIG. 2 are not able to transmit data in a timely manner due to the inherent unreliability of mud pulse telemetry, the limited ability to transmit data only while fluids are circulating at a sufficiently high rate, and the transmission blackout period that occurs whenever the mud pumps start ramping down, such that there is no communication during connections, a time during which visibility is most needed.
• Drilling control system 400 using WDP 430 addresses many of these shortcomings by providing hydraulic model 410, and in turn choke controller 250, with timely and actionable information based on actual downhole conditions in real-time.
• High-speed sampling of the downhole sensor and measurement packages enables transmission of downhole pressure from WDP 430 to feed choke controller 250 directly.
• WDP 430 provides a reliable signal through transient pump ramp down periods as well as during periods when there is no fluid circulating.
• hydraulic model 410 may provide choke controller 250 with a realtime measured value for downhole pressure that enables choke controller 250 to rapidly adjust the application of surface backpressure to achieve a targeted downhole pressure.
• hydraulic model 410 may provide choke controller 250 with an expected value for downhole pressure that enables choke controller 250 to adjust the application of surface backpressure to achieve the targeted downhole pressure.
• choke controller 250 can regulate based on realtime measurements of downhole pressure, or expected values thereof in the event WDP 430 telemetry is unavailable.
• downhole pressure between sampling points may be interpolated or extrapolated to fill in gaps between the downhole pressure measurement sample points. This enables choke controller 250 to control directly from a downhole sensor at or near the zone of concern rather than controlling from a sensor that may be located far away from the zone of concern.
• a method of managing wellbore pressure using WDP includes measuring, via one or more downhole sensors, one or more measured values of downhole pressure at one or more locations at one or more depths within the wellbore, transmitting, via WDP telemetry, one or more measured values of downhole pressure to a surface-based control system in real-time, validating, via control system, whether one or more measured values of downhole pressure are within an expected range, calculating, via hydraulic model, one or more expected values for the downhole pressure, controlling, via the control system, one or more choke valves of an MPD choke manifold to achieve a downhole pressure for a desired depth, where the downhole pressure may be based on one or more measured values if there are one or more sensors at the desired depth, or where the downhole pressure may be based on an extrapolation from one or more measured values at a depth nearby the desired depth and validated by the corresponding expected value.
• controlling the one or more choke valves of the MPD choke manifold may be based on one or more measured values at least partly acquired from WDP telemetry during transient flow during ramping of one or more mud pumps during connections. In other embodiments, controlling the one or more choke valves of the MPD choke manifold may be based on the one or more expected values when the one or more corresponding measured values are not available or are otherwise deemed to not correctly reflect downhole conditions.
• a drilling control system 400 using WDP 430 may use downhole telemetry data to calibrate hydraulic model 410 based on real-time measurements of downhole process parameters, enabling hydraulic model 410 to provide more accurate estimates of downhole process parameters.
• downhole WDP 430 measurements represent actual downhole conditions
• corresponding expected values from hydraulic model 410 represent estimates of downhole conditions based on information observed on the surface.
• Static configurations may be inputted into hydraulic model 410 and live data obtained from surface instrumentation may be fed into hydraulic model 410.
• imperfect resolution and rounding errors in the input data may compound when combined in hydraulic model 410.
• the use of WDP 430 data to calibrate 420 hydraulic model 410 allows control system 400 to capture and transmit data at a substantially higher rate, and at times when conventional telemetry systems are blacked out.
• a method of calibrating a hydraulic model of a wellbore includes inputting, into the hydraulic model, one or more static values for one or more process parameters of the wellbore, receiving, at a control system, one or more dynamic values for one or more process parameters of the wellbore, measuring, via one or more downhole sensors, one or more measured values for one or more downhole process parameters at one or more locations at one or more depths within the wellbore, transmitting, via wired drillpipe telemetry, one or more measured values to the control system in real-time, validating, via the control system, whether one or more measured values are within an expected range, calculating, via the hydraulic model, one or more expected values for one or more process parameters, calculating, via the control system, for an expected value of a process parameter of interest, a quotient of the expected value and its corresponding measured value, calculating, via the control system, a correction factor for the expected value of the process parameter of interest when the quotient deviates from
• the calibrated hydraulic model may be calibrated in parallel with an offline hydraulic model that is not calibrated in real-time. In other embodiments, the calibrated hydraulic model may be compared with the offline hydraulic model to verify that the calibrated model is within a predetermined expected range of the offline hydraulic model.
• Calibration of online hydraulic model 410 provides explanations for changes in measured downhole values of one or more downhole process parameters, thereby improving the precision of unexpected event detection (e.g., 440).
• measured downhole data trends are typically constant.
• measured downhole data trends are expected to vary; setting a simple threshold alarm on the measured downhole data provides too wide of a tolerance to deliver actionable information in a timely manner.
• the raw downhole data trends must be corrected. Rather than setting a threshold alarm on the raw measured downhole data, drilling control system 400 includes a threshold alarm on the difference between the measured and expected values.
• a small difference between the measured and expected values for a given process parameter indicates that downhole conditions substantially match what the rig observes at the surface.
• a large difference between the measured and expected values indicates that something has happened downhole which the rig system is currently unable to detect with surface equipment. When this occurs, an alarm may be triggered to alert the crew of the mismatch. This allows the rig crew to act substantially sooner than a conventional MPD control system would allow.
• the measured downhole data from WDP 430 should closely match that of the calculated downhole data provided by hydraulic model 410.
• measured downhole data may not match what is observed at the surface. For example, if an influx occurs and gas from the formation enters solution, the gas volume may not substantially displace drilling fluid from the well, however solution of gas into the drilling fluid will typically cause the temperature of the drilling fluid to increase. The solution of gas into the mud may continue undetected for several minutes.
• a conventional MPD control system dependent on surface-acquired data, the influx may only be detected when the flow out exceeds the flow into the well; in the case of solution gas, this may occur only once the annular pressure drops to the bubble point. This implies that a substantial portion of the well may contain unknown gas in solution in mud prior to detection by a conventional MPD control system.
• a wellbore stability event may be caused by insufficient wellbore pressure. If the wellbore pressure remains low, compressive failure of the wellbore may occur and material from the wall of the bore hole may collapse into the well and be circulated out with the cuttings.
• the collapsed material has the same effect on average fluid density as cuttings have on average fluid density, however the control system accounts for drilled cuttings as a function of the ROP; no such correction is applied for collapsed material.
• the control system accounts for drilled cuttings as a function of the ROP; no such correction is applied for collapsed material.
• At the surface no change is immediately seen following a partial collapse. In part, because the volume of the collapsed material matches the void left by the collapsed material, limiting the effectiveness of a volumetric accounting tool to account for the occurrence.
• the collapsed material is located downhole, far from a return flow Coriolis meter, delaying detection by a mass balance accounting tool. Since downhole tools sense the total pressure at a given point, the downhole tool sees the density changing effects of the drilled cuttings and collapsed material whereas the hydraulic model accounts only for the density changing effects of the drilled cuttings.
• the cause of a wellbore stability problem may be low wellbore pressure while the effect of a wellbore stability problem may be the mixing of collapsed material with cuttings, increasing the average fluid density and potentially mitigating the cause of the wellbore stability problem. If the collapsed material is circulated out of the well undetected, the condition leading to the wellbore stability problem returns, and the cycle repeats undetected while wellbore quality deteriorates. In such instances, surface acquired data may not reflect a change in the downhole conditions. This results in a mismatch between the measured downhole and the corresponding estimates of expected values from the hydraulic model.
• a difference between a measured and an expected downhole process parameter greater than a predetermined threshold may trigger an alarm, alerting the rig crew that downhole conditions have deteriorated compared to what is presently observable at the surface.
• drilling control system 400 using WDP 430 may use raw measured and expected data to contextualize information for the rig crew to speed unexpected downhole event detection and characterization of the unexpected event. In turn, this allows the rig crew to form an appropriate response earlier, mitigating an event before it grows in magnitude and scope.
• drilling control system 400 using WDP 430 may be used to automatically circulate cuttings beds from the wellbore and monitor hole cleaning with feedback using measured and expected downhole data.
• WDP 430 may include downhole measurement tool packages, including, for example, pressure or temperature measurement tools, disposed at one or more locations at one or more depths along the drillstring.
• Drilling control system 400 may control the rotary velocity of the drillstring, the axial displacement of the drillstring, and the circulation rate of the fluid through the well.
• the engineering team may determine in advance a target pressure or target ECD at a target depth.
• Measured downhole data may be transmitted to the surface in real-time WDP 430 and filtered to determine which values facially reflect downhole conditions.
• Hydraulic model 410 may estimate expected values of downhole process parameters for one or more locations at one or more depths within the wellbore. Drilling control system 400 may compare the measured values with the expected values before moving the drillstring. Hydraulic model 410 may estimate an expected pressure drop between a first pressure sensor and a second pressure sensor along the drillstring at a predetermined circulating rate.
• the rig may then begin circulating at the predetermined circulating rate and compare the measured pressure drop between the first pressure senor and the second pressure sensor with the expected pressure drop between the first pressure senor and the second pressure sensor. While inconclusive, a higher-than-expected pressure drop may indicate a reduced flow area caused by the buildup of a cuttings bed while a lower-than-expected pressure drop may indicate an increased flow area caused by a wellbore stability issue. Though differences between measured and expected pressure drop between a first sensor and a second sensor may not be conclusive, the approach provides some data to the drilling crew which may be interpreted to correct an unjustified assumption.
• the drillstring may be rotated and reciprocated according to a predetermined or random schedule in a manner to agitate the system in order to disperse cuttings beds or other built-up debris in the wellbore.
• the improved drilling control system may then compare measured and expected downhole process data during or after moving the drillstring. A difference between the measured and expected downhole process data during or after agitation may indicate movement of cuttings or other debris in the well or a difference between the downhole process data measurements before and after agitation may indicate movement of cuttings or other debris in the well.
• the programmable drilling control system 400 may automatically adjust downhole pressure or ECD to a high state by changing the drilling fluid circulation rate, drillstring rotary velocity, or drillstring axial velocity to agitate cuttings beds or debris in the well.
• the programmable drilling control system 400 may automatically adjust downhole pressure or ECD to a low state by changing the drilling fluid circulation rate, drillstring rotary velocity, or drillstring axial velocity to monitor cuttings or debris transport in the well.
• the programmable drilling control system 400 may cycle between a high ECD state and a low ECD state until a difference between the measured and expected values for one or more downhole process parameters during or after agitation or a difference between the measured values of one or more downhole process parameters before, during, or after agitation no longer indicates movement of cuttings or other debris in the well. Once this is complete, the programmable drilling control system 400 may further alert the rig crew when the process of agitating and circulating cuttings or other debris from the well is sufficiently complete.
• a method of automatically removing debris from a wellbore includes inputting, via a control system, a target equivalent circulating density or a target pressure for a target depth in the wellbore, measuring, via one or more downhole sensors, one or more measured values of one or more downhole process parameters at one or more locations at one or more depths within the wellbore, transmitting, via wired drillpipe telemetry, one or more measured values to a surface-based control system, validating, via the control system, whether one or more measured values are within an expected range, calculating, via the hydraulic model, one or more estimated values corresponding to the one or more measured values, comparing, via the control system, the one or more expected values with the one or more measured values, and rotating and reciprocating a drill string to a predetermined or random schedule to agitate and disperse cutting beds or other built-up debris in the wellbore until the one or more measured values is approximately equal to the one or more expected values or a predetermined time limit
• a difference between the one or more measured values and the one or more expected values during or after agitation indicates movement of cuttings or other debris in the wellbore. In other embodiments, a difference between the one or more measured values before and after agitation indicates movement of cuttings or other debris in the wellbore.
• the ECD is adjusted to a high state by changing a drilling fluid circulation rate or drillstring rotary velocity. In other embodiments, the ECD is adjusted to a low state by changing the drilling fluid circulation rate or drillstring rotary velocity to monitor cutting or debris transport in the well.
• control system injects drilling fluids having a high equivalent circulating density to agitate cuttings beds or other debris in the well and a low equivalent circulating density to monitor cuttings or debris transport in the well.
• control system instructs the rotating and reciprocating when a difference between the one or more measured values and the one or more expected values before and after agitation exceeds a predetermined threshold value. In other embodiments, the control system stops rotating and reciprocating when a difference between the one or more measured values and the one or more expected values before and after agitation is less than a predetermined threshold value. In certain embodiments, the control system provides a notification that the rotating and reciprocating operation is complete.
• FIG. 5 shows a drilling control system 500 using WDP 430 to improve management of downhole process parameters and provide early detection of unexpected downhole events in accordance with one or more embodiments of the present invention.
• a choke controller e.g., 250 of FIG. 4
• drilling control system 500 using WDP 430 closely resembles that of the drilling control system 400 of FIG. 4.
• the disclosure with respect to drilling control system 400 of FIG. 4 applies with equal force to drilling control system 500, with the exception of its functionality with reference to the choke controller 250 of FIG.
• drilling control system 500 may use hydraulic model 410 and WDP 430 to feed measured values for one or more downhole process parameters to an unexpected downhole event detection system (e.g., 440).
• an unexpected downhole event detection system e.g., 440
• the downhole pressure measurements represent the downhole conditions as they presently are while the corresponding estimates from hydraulic model 410 represent the downhole conditions as observed at the rig on the surface (and lagging that of their occurrence).
• Outputs from an online hydraulic model 410 may explain changes in the measured downhole values to improve the precision of unexpected downhole event detection 440. A small difference between the measured and expected values indicates that the downhole conditions match what the rig observes at the surface.
• drilling control system 500 may be used to automate the process of rotating and reciprocating drill pipe for hole cleaning without the feedback mechanism provided by WDP telemetry. While this may be considered a less capable system, it may be more readily deployed.
• FIG. 6 shows a flow of information 600 from the perspective of rig crew 310 during an unexpected downhole event when using a drilling control system (e.g., 400 of FIG. 4) using WDP (e.g., 430 of FIG. 4) in accordance with one or more embodiments of the present invention.
• a drilling control system e.g., 400 of FIG. 4
• WDP e.g., 430 of FIG. 4
• FIG. 6 shows a flow of information 600 from the perspective of rig crew 310 during an unexpected downhole event when using a drilling control system (e.g., 400 of FIG. 4) using WDP (e.g., 430 of FIG. 4) in accordance with one or more embodiments of the present invention.
• conventional drilling control systems e.g., 200 of FIG. 2
• WDP e.g., 430 of FIG. 4
• FIG. 6 shows a flow of information 600 from the perspective of rig crew 310 during an unexpected downhole event when using a drilling control system (e.
• choke controller 250 may receive measured values of downhole data provided by WDP 430 in real-time, expected values of downhole data provided by hydraulic model 410, and surface-measured or surface-acquired data 205 obtained from the surface. As discussed above, choke controller 250 may control one or more chokes of the MPD manifold (e.g., 165 of FIG. 1) to achieve a desired target pressure based on real-time measurements of downhole pressure from WDP 430, or in the absence of such measured data, based on expected values of downhole pressure from hydraulic model 210.
• the MPD manifold e.g., 165 of FIG. 1
• measured data provided by WDP 430 in real-time allows for the early detection of unexpected downhole events.
• the near instantaneous transmission of measured values from downhole sensors enables substantially earlier detection than would otherwise be possible, enabling swift remedial actions to be taken before the situation worsens.
• FIG. 7 shows an example of a system 700 for calibrating a hydraulic model 410 in accordance with one or more embodiments of the present invention.
• Fingerprinting is an essential task performed before the start of an MPD section.
• Online hydraulic model 410a is calibrated 420 against measured downhole conditions to mitigate the compounding effects of instrument resolution error and rounding error, resulting in a calibrated online hydraulic model 410b.
• the rig crew inputs configuration and live data into a hydraulic model that the rig crew manually updates the model calculated values to match the values obtained from the PWD system.
• This manual fingerprinting process typically takes hours or days to complete, such that the cost of fingerprinting the well before an MPD section is non-trivial.
• downhole measurements transmitted in real-time by WDP telemetry may be incorporated into an optimized MPD workflow, enabling the timely use of downhole measurement data to calibrate hydraulic model 410a of the well.
• Incorporating WDP data into the model calibration sequence allows the system to capture and transmit data faster, particularly during low or zero flow steps where conventional PWD telemetry systems stop transmission. This approach enables the rig 710 to spend less time in low or zero flow states to capture and transmit data to the surface.
• the online model accounts for downhole conditions, the model is based entirely at the surface and once calibrated, relies exclusively on surface- acquired data.
• FIG. 8 shows an example of a system 800 for a drilling control system 400 using WDP 430 in accordance with one or more embodiments of the present invention.
• Integrating measurements from one or more downhole sensors that are transmitted in real-time using WDP telemetry and incorporating those measurements into existing workflows enables an unexpected downhole event detection methodology that significantly improves the rig crew’s visibility into downhole conditions.
• an online hydraulic model estimates process parameters along the drillstring using surface-measured or surface-acquired data.
• WDP 430 enables the drilling control system 400 to take measurements of the actual drilling variables at different locations at different depths along the drillstring (e.g., DHT1, DHT2, DHT3, DHT4, and DHT5).
• the downhole measurements represent the downhole conditions as they are, in real-time, whereas the estimated values provided by the hydraulic model 410 represent the downhole conditions as the control system 400 observes them on the surface.
• the early unexpected downhole event detection system may compare various process parameters like pressure or temperature along the drillstring for early indications of a kick. Gas mixing heats or cools the drilling mud in unexpected ways.
• the unexpected downhole event detection system may compare a measured value versus an expected value for fluid density along the drillstring to determine whether a wellbore stability problem exists. Excess material falling into the well affects the average fluid density in unexpected ways.
• Along-string measurements e.g., DHT1, DHT2, DHT3, DHT4, and DHT5
• DHT1, DHT2, DHT3, DHT4, and DHT5 may detect densitychanging effects as a result of the drilled cuttings and collapsed material.
• hydraulic model 410 may account for the density-changing effects of the drilled cuttings but not the collapsed material.
• the resulting mismatch between the measured value and expected value of fluid density indicates an active wellbore stability event.
• Other applications in unexpected downhole event detection include advanced visualizations. Advanced displays of the unexpected downhole event detection system show where the measured values and expected values differ in time and along the path of the well. This allows the rig crew to quickly determine where an issue is taking effect in the well to expedite response.
• FIG. 9 shows an example of a drilling control system using WDP in accordance with one or more embodiments of the present invention.
• the WDP availability also enables new operating modes to supplement contemporary MPD workflows.
• Electronic telemetry of WDP downhole tools provides a reliable signal through the pump ramp transient period.
• MPD connections may be simplified using a highspeed sampling of WDP downhole tools with measured downhole pressure feeding the choke controller directly, adjusting for time delays and depth offsets.
• Downhole pressure may be extrapolated from a single measurement and corrected with the assistance of the hydraulic model. This feature enables the choke to be controlled directly from a sensor at or near the zone of concern rather than a sensor located up to 5 miles away.
• FIG. 10 shows a computing system 1000 in accordance with one or more embodiments of the present invention.
• Computing system 1000 may include one or more central processing units (“CPU”) 1005, one or more graphics processing units (“GPU”) 1010, and one or more specialized processing engines 1015.
• Computing system 1000 may optionally include, if not integrated into CPU 1005, a chipset 1020 that incorporates one or more functions previously provided by a legacy host bridge (not shown) or input/output (“I/O”) bridge (not shown).
• a legacy host bridge not shown
• I/O input/output
• one or more of the above-noted components may be discrete components.
• one or more of the above-noted components, or the functions that they implement may be integrated into a system-on-chip (“SOC”) 1025.
• SOC system-on-chip
• An SOC 1025 design may include a plurality of one or more of the above-noted components disposed on the same physical die (not shown) or disposed within the same mechanical package (not shown).
• One of ordinary skill in the art will recognize that the one or more CPUs 1005, the one or more GPUs 1010, the one or more specialized processing engines 1015, and chipset 1020 may be integrated, in whole or in part, to reduce the thermal design power (“TDP”), reduce power consumption, reduce chip count, reduce the mechanical footprint, and reduce the complexity of the printed circuit board (“PCB”) (not shown) that they may be disposed on.
• TDP thermal design power
• PCB printed circuit board
• Each of the one or more CPUs 1005, the one or more GPUs 1010, the one or more specialized processing engines 1015, and chipset 1020 may be a single-core processor (not independently illustrated) or a multi-core processor (not independently illustrated).
• Multi-core processors typically include a plurality of processor cores (not shown) disposed on the same physical die (not shown) or disposed within the same mechanical package (not shown) that are arranged to provide enhanced capabilities over a singlecore implementation.
• Each of the one or more CPUs 1005 may include a memory interface 1030 to system memory 1035, a graphics interface 1040 to the one or more GPUs 1010, a specialty interface 1013 to the one or more specialized processing engines 1015, and a chipset interface 1045 to chipset 1020.
• Each of the one or more GPUs 1010 may include a CPU interface 1040 to the one or more CPUs 1005, a memory interface 1050 to graphics memory 1055, and a display interface 1060 to a display device 1065.
• Chipset 1020 may include a chipset interface 1045 to the one or more CPUs 1005, a memory interface 1070 to system memory 1035, and one or more IO interfaces to one or more IO expansion devices, including, for example, a human/machine interface (“HMI”) interface 1075 to one or more HMI devices 1077, a local storage interface 1079 to one or more local storage devices 1081, a network interface 1083 to one or more network interface devices 1085, and other I/O interfaces 1087 to one or more other I/O devices 1089.
• HMI human/machine interface
• Each local storage device 1081 may be a solid-state memory device, a solid-state memory device array, a hard disk drive, a hard disk drive array, or any other non- transitory computer readable medium.
• Computing system 1000 may also include one or more network-attached storage devices 1091 that communicate with one or more network interface devices 1085 via a network interface 1085.
• the one or more network- attached storage devices 1091 may be used in addition to, or instead of, the one or more local storage devices 1081.
• the one or more network-attached storage devices 1091 may be a solid-state memory device, a solid-state memory device array, a hard disk drive, a hard disk drive array, or any other non-transitory computer readable medium.
• the one or more network-attached storage devices 1091 may or may not be collocated with computing system 1000 and may be accessible to computing system 1000 via one or more network interfaces 1083 provided by one or more network interface devices 1085.
• Each network interface device 1085 may provide one or more network interfaces including, for example, Ethernet, Fibre Channel, WiMAX, Wi-Fi, Bluetooth, or any other type or kind of network connectivity and network protocol suitable for networked communications.
• Computing system 1000 may also include one or more application specific integrated circuits (“ASICs”) that are configured to perform a certain function, such as, for example, hashing (not shown), in a more efficient manner.
• ASICs application specific integrated circuits
• the one or more ASICs may interface directly with the one or more CPUs 1005, the one or more GPUs 1010, the one or more specialized processing engines 1015, and chipset 1020.
• computing system 1000 has been described above as a general purpose computing device, one of ordinary skill in the art will recognize that computing system 1000 may be reduced to only those components necessary to perform a desired function or scaled up as needed to meet requirements. As such, any of the above-noted components, or various subsets, supersets, or combinations of functions or features thereof, may be integrated, in whole or in part, or distributed among various devices based on an application, design, or form factor in accordance with one or more embodiments of the present invention. As such, the description of computing system 1000 is merely exemplary and not intended to limit the type, kind, or configuration of components that constitute a computing system suitable for performing computing operations.
• computing system 1000 may be implemented as a specialized industrial system, a server, a workstation, a desktop computer, a laptop computer, a netbook, a tablet, a smartphone, a mobile device, and/or any other type or kind of computing system in accordance with one or more embodiments of the present invention.
• computing system 1000 may be instantiated as a virtual computer (not shown) in a virtual or cloud-based infrastructure such as those provided by, for example, Amazon AWS®, Microsoft Azure®, Google Cloud®, or other cloud computing service providers.
• the components of computing system 1000 may be distributed in a manner that is transparent, but potentially unknown, to the end user.
• control system 400 may be any type or kind of computing system 1000 or any variant thereof, including industrial systems including those based on programmable logic controllers (“PLCs”), field programmable gate arrays (“FPGAs”), and ladder logic.
• PLCs programmable logic controllers
• FPGAs field programmable gate arrays
• ladder logic programmable logic controllers
• Advantages of one or more embodiments of the present invention may include one or more of the following:
• MPD using WDP uses data from downhole sensors to provide rig crew with actionable information that enables them to advance drilling in an optimal manner.
• MPD using WDP improves the management of wellbore pressure.
• MPD using WDP provides early detection of unexpected downhole events.
• MPD using WDP augments surface-based automation.
• MPD using WDP provides visualization of dynamic wellbore conditions.
• MPD using WDP improves kick detection.
• MPD using WDP simplifies choke control.

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• 2023
  • 2023-06-29 WO PCT/US2023/026644 patent/WO2024006478A2/en not_active Ceased
  • 2023-06-29 EP EP23832366.1A patent/EP4547933A4/de active Pending

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