DRILLING SYSTEM AND METHOD USING DYNAMICALLY DETERMINED DRILLING WINDOW

Abstract

Control of a drilling system drilling a wellbore is improved using a hydraulics model corrected for pressure losses. A surface backpressure of the outlet and a standpipe pressure of the inlet are measured with sensors in the system. An estimate of the standpipe pressure is calculated based integrating from the measured surface backpressure back to the inlet in the hydraulics model. The pressure loss increment in the hydraulics model is calculated based on a difference between the measured and estimated standpipe pressures. Meanwhile, a parameter in the drilling system is monitored during drilling so the parameter can be adjusted at least partially based on the hydraulics model corrected for the pressure loss.

Description

BACKGROUND OF THE DISCLOSURE

The flow of formation fluids into a wellbore during drilling operations, when the annular pressure (AP) is below the pore pressure (PP), is called an influx or “kick.” By contrast, when the annular pressure is above the fracture pressure (FP), a fluid loss to the formation can occur. Hydrostatic pressure is the first conventional barrier for controlling the well from influxes and fluid losses. Rig blow out preventers (BOP) are a second barrier for influxes. Losses can be managed using lost circulation material (LCM) or by performing other procedures.

Even using available methods, both influxes and fluid losses can occur during drilling operations. Either event can have detrimental effects. If a kick cannot be detected and controlled fast enough, it can escalate into uncontrolled flow of formation fluids to the surface, which is called a “blow-out,” resulting in operational delays (non-productive time) or even more severe consequences to the safety of personnel or loss of the well.

For these reasons, accurate monitoring for downhole pressure changes is useful during drilling operations to maintain proper pressure balance in the well. Flow deviation can be detected by continuously monitoring the return flow from the wellbore (i.e., flow-out) in a closed-loop circulation system and comparing the flow-out to the flow-in (i.e., outflow to the inflow). Several controlled pressure drilling techniques have been used to drill wellbores with such closed-loop drilling systems. In general, the controlled pressure drilling techniques include managed pressure drilling (MPD), underbalanced drilling (UBD), and air drilling operations.

In MPD, the drilling system uses a closed and pressurize-able mud-return system, a rotating control device (RCD), and a choke manifold to control the wellbore pressure during drilling. The various MPD techniques used in the industry allow operators to drill successfully in conditions where conventional technology simply will not work by allowing operators to manage the pressure in a controlled manner during drilling.

As the bit drills through a formation, for example, pores become exposed and opened. As a result, formation fluids (i.e., gas) from an influx or kick zone can mix with the drilling mud. The drilling system then pumps this gas, drilling mud, and the formation cuttings back to the surface. As the gas rises in the annulus of the well, the gas may expand, and the density of the mud may decrease, meaning more gas from the formation may be able to enter the wellbore. If the pressure of the mud column is less than the formation pressure, then even more influx could enter the wellbore.

Conventionally, drilling operators use pressure-while-drilling (PWD) data, when available, to monitor the drilling and to determine the bottom hole pressure (BHP). However, PWD data cannot always be used especially when pump rates are low, and the PWD data has a low resolution and a slow data transfer rate. These setbacks can hinder attempts to drill and control a well.

Control of pressures during drilling operations may be based on a hydraulics model that calculates BHP and bottomhole temperature. Efficient control of the BHP during MPD operations benefits from a precise hydraulics model, which might not always interoperate downhole conditions. For example, the annular pressure profile being modeled may be different from the actual physical system. Although the hydraulics model accounts for numerous details related to the drillpipe, the drill bit, casing geometry, temperature effects of the formation, the mud characteristics, effects of cuttings, and the like, modelling the characteristics of open hole formations, fluid density, rheology, and other factors properly in the hydraulics model may be difficult to achieve.

Currently, geophysical and drilling parameters while drilling are used to estimate the pore pressure and fracture pressure. After estimation of the drilling window, the bottomhole pressure in the MPD operations are manually set to a setpoint and will be controlled there.

The typical methods to estimate pore pressure and fracture pressure use empirical correlations to quantitatively relate drilling parameters, sonic transit time, and resistivity readings for given formation types (inputs) and to evaluate formation pore pressure (output) according to Terzaghi's effect. In general, the Terzaghi's effect is defined as the relationship between overburden stress and effective stress. There are multiple correlations available in the prior art, and each correlation uses different combinations of inputs. However, all of these empirical correlations have actually been developed based on limited data obtained from a number of cases/formations/fields. Consequently, the accuracy of these estimations can be poor, even though accurate measurement-while-drilling/logging-while-drilling (MWD/LWD) data may be provided by downhole tools. The poor estimation and uncertainty in these methods arise from the coefficients defined for the correlations. More importantly, the subjectivity of pore pressure estimations performed by a user also produces the uncertainty in these methods.

In addition to a way to qualitatively validate pore pressure and fracture pressure using parameters, such as connection gas, kicks, etc., what is needed is a quantitative way to calibrate the empirical correlations and maintain bottomhole pressure automatically during drilling between the boundaries of a dynamic drilling window.

The subject matter of the present disclosure is directed to overcoming, or at least reducing the effects of, one or more of the problems set forth above.

SUMMARY OF THE DISCLOSURE

A method disclosed herein is implemented by a computerized control for a closed-loop drilling system. The closed-loop drilling system has: a bottom hole assembly for drilling a wellbore in a formation, at least one pump for pumping drilling fluid at an inlet, and at least one choke for choking the drilling fluid at an outlet. The method comprises: (i) calculating normal compaction trendlines for intervals of the wellbore to be drilled in the formation (“normal” referring to direction); (ii) drilling the wellbore in a drilling operation using the closed-loop drilling system while monitoring inflow at the inlet, monitoring outflow at the outlet, and measuring surface backpressure at the outlet; and (iii) while drilling in the drilling operation, repeatedly: (a) defining a dynamic drilling window for the interval of the wellbore being drilled in the formation by using the normal compaction trendline; (b) estimating a lower boundary (e.g., pore pressure gradient) for the interval of the dynamic drilling window by reducing the surface backpressure while simultaneously monitoring the inflow and the outflow until a signature influx is measured; (c) estimating an upper boundary (e.g., formation pressure gradient) for the interval of the dynamic drilling window by increasing the surface backpressure while simultaneously monitoring the inflow and the outflow until a signature loss is measured; (d) updating the normal compaction trendline for the interval in the formation ahead of the bottom hole assembly based on the estimated upper and lower boundaries; and (e) adjusting a parameter in the drilling operation to drill at a target bottom hole pressure within the dynamic drilling window.

A programmable storage device disclosed herein can have program instructions stored thereon for causing a programmable control device to perform a method as disclosed above of drilling a wellbore with drilling fluid using a drilling system.

A system disclosed herein is used for drilling a wellbore with drilling fluid. The system comprises at least one pump, at least one choke, storage, a first sensor, and a programmable control device. The at least one pump is disposed at an inlet of the system and is operable to pump the drilling fluid into the wellbore when drilling the wellbore with the drilling system. The at least one choke is disposed at an outlet of the system and is operable to adjust flow of the drilling fluid from the wellbore when drilling the wellbore with the drilling system.

The memory storage stores a hydraulics model of the drilling system drilling the wellbore, and the first sensor is configured to measure a value of surface backpressure upstream of the at least one choke. The programmable control device is communicatively coupled to the storage and the first sensor. The programmable control device being configured to perform a method as disclosed above.

The foregoing summary is not intended to summarize each and every aspect of the present disclosure.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 illustrates a controlled pressure drilling system having a control system according to the present disclosure.

FIG. 2 schematically illustrates the control system of the present disclosure.

FIG. 3 illustrates a flow chart of a process according to the present disclosure.

FIG. 4 illustrates a graph of a dynamically determined drilling window according to the present disclosure.

FIG. 5A illustrates additional steps for the disclosed process.

FIG. 5B illustrates a representation of a model of the drilling system for the present disclosure.

FIG. 6 graphs a conceptual pressure profile for pore pressure tests at different depths within a closed-loop managed pressure drilling (MPD) system.

FIG. 7A illustrates details of a dynamic pore pressure test (DPPT) in MPD.

FIG. 7B illustrates a stepwise increase in surface backpressure (SBP) during DPPT.

FIG. 8A illustrates details of a dynamic fracture pressure test (DLOT) in MPD.

FIG. 8B illustrates a stepwise increase in SBP during DFIT/DLOT test.

FIGS. 9A-9B show a flowchart of an example process according to the present disclosure.

DETAILED DESCRIPTION OF THE DISCLOSURE

FIG. 1 shows a closed-loop drilling system 10 according to the present disclosure for controlled pressure drilling. As shown and discussed herein, this drilling system 10 can be a managed pressure drilling (MPD) system and, more particularly, a Constant Bottom-hole Pressure (CBHP) form of MPD system. Although discussed in this context, the teachings of the present disclosure can apply equally to other types of controlled pressure drilling systems, such as other MPD systems (Pressurized Mud-Cap Drilling, Returns-Flow-Control Drilling, Dual Gradient Drilling, etc.) as well as to UBD systems, as will be appreciated by one skilled in the art having the benefit of the present disclosure.

The drilling system 10 may be a land-based system or an offshore system. As shown here, the drilling system 10 includes a mobile offshore drilling unit 100, such as a semi-submersible, having a drilling rig 110 and components for fluid handling.

The drilling rig 110 includes a derrick 112 having a traveling block supporting a top drive 116, which couples to a flow sub 118. A top of the drillstring 14 connects to the flow sub 118, such as by a threaded connection, or by a gripper (not shown), such as a torque head or spear. The top drive 116 is operable to rotate the drillstring 14 extending from the derrick 112 and includes an inlet 114 (e.g., top drive inlet) coupled to a Kelly hose to provide fluid communication between the Kelly hose and the flow sub 118 and drillstring 14 extending therefrom.

The drillstring 14 extending from the drilling rig 110 includes a bottom hole assembly (BHA) 16 at the end of the connected joints of drillpipe. The BHA 16 can typically include a drill bit 18, drill collars, a drilling motor (not shown), a measurement while drilling, a logging while drilling sub, and the like for drilling a wellbore 12.

The drilling system 10 further includes a riser package 30 (i.e., an upper marine riser package (UMRP)), a riser 22, auxiliary lines (boost, choke, etc.) 24, and other components. As is customary, the riser 22 extends from the drilling rig 110 to a wellhead 20 located on the sea floor. The riser 22 typically connects to the wellhead 20 with a wellhead adapter, and the wellhead 20 typically has blow-out preventers (BOPs) and connects to the riser lines 24, such as booster line, choke line, kill line, and the like.

The riser package 30 includes a diverter 70, a flex joint 72, a telescopic joint 74, a tensioner 76, a tensioner ring 78, and a rotating control device (RCD) 60. For example, the telescopic joint 74 includes an outer barrel connected to an upper end of the RCD 60 and includes an inner barrel connected to the flex joint 72. The outer barrel may also be connected to the tensioner 76 by the tensioner ring 78.

The RCD 60 can include any suitable pressure containment device that keeps the wellbore 12 in a closed loop while the wellbore 12 is being drilled. (As will be appreciated, the wellbore 12 includes the borehole in the formation F and includes the riser 22 which constitutes an extension of the borehole). In this way, the RCD 60 can contain and divert annular drilling returns via a return line 62 to complete the circulating system to create the closed loop of incompressible drilling fluid.

The RCD 60 can include any typical construction. For example, the RCD 60 may include a housing, a piston, a latch, and a rider. The housing may be tubular and have one or more sections connected together, such as by flanged connections. The rider may include a bearing assembly, a housing seal assembly, one or more strippers, and a catch sleeve. The rider may be selectively longitudinally and torsionally connected to the housing by engagement of the latch with the catch sleeve. The housing may have hydraulic ports in fluid communication with the piston and an interface of the RCD 60. The bearing assembly may support the strippers from the sleeve such that the strippers may rotate relative to the housing (and the sleeve). The bearing assembly may include one or more radial bearings, one or more thrust bearings, and a self-contained lubricant system. The bearing assembly may be disposed between the strippers and be housed in and connected to the catch sleeve, such as by a threaded connection and/or fasteners.

Each stripper in the RCD 60 may include a gland or retainer and a seal. Each stripper seal may be directional and oriented to seal against the drillstring 14 in response to higher pressure in the riser 22 than the riser package 30. Each stripper seal may have a conical shape for fluid pressure to act against a respective tapered surface thereof, thereby generating sealing pressure against the drillstring 14. Each stripper seal may have an inner diameter slightly less than a pipe diameter of the drillstring 14 to form an interference fit therebetween. Each stripper seal may be flexible enough to accommodate and seal against threaded couplings of the drillstring 14 having a larger tool joint diameter. The drillstring 14 may be received through a bore of the rider so that the stripper seals may engage the drillstring 14. The stripper seals may provide a desired barrier in the riser 22 either when the drillstring 14 is stationary or rotating.

The RCD 60 may be submerged adjacent to the waterline. The RCD interface may be in fluid communication with an auxiliary hydraulic power unit (HPU) (not shown) of a control system 200 via control lines 202. (As discussed herein, the control system 200 can provide computerized control of the systems and method disclosed.) An active seal RCD may be used. Alternatively, the RCD 60 may be located above the waterline and/or along the riser package 30 at any other location besides a lower end thereof. Alternatively, the RCD 60 may be assembled as part of the riser 22 at any location therealong.

The RCD 60 may be connected to other flow control devices, such as an annular seal device 50, a flow spool 40 having controllable valves, and the like, as used in MPD. The annular seal device 50 can be used to sealingly engage (i.e., seal against) the drillstring 14 or to fully close off the riser 22 when the drillstring 14 is removed so fluid flow up through the riser 22 can be prevented. Typically, the annular seal device 50 can use a sealing element that is closed radially inward by hydraulically actuated pistons. The control lines 202 from hydraulic components on the drilling rig 110 can be used to deliver controls to the annular seal device 50.

The flow spool 40 can include controllable valves (not shown) that connect to flow connections 42 to communicate the internal passage of the riser 22 with rig components on the drilling rig 110. Return lines 32 from the riser package 30 may be used to communicate flow, and the control lines 202 on the riser 22 may also be used to deliver controls to open and close the controllable valves.

In addition to the riser package 30, the drilling system 10 also includes a choke manifold 120, a mud gas separator 130, a shaker 140, mud tanks 142, mud pumps 150. In addition to these, the drilling system 10 includes flow equipment 160 to deliver flow to the drillstring 14 through the Kelly hose connected to a supply line 165a or through a clamp 174 connected to a bypass line 165b and couplable to the flow sub 118. The clamp 174 and flow sub 118 are part of a continuous flow system that allows flow to be maintained while pipe connections are being made.

One or more return lines 32 connects from the riser package 30 to the choke manifold 120. A return pressure sensor 240, return choke 122, and return flowmeter 124 communicate with the flow from the return line 32. After the choke manifold 120, the flow eventually communicates with the mud gas separator 130 and the shaker 140.

A transfer line 144 connects an outlet of the mud tanks 142 to the mud pumps 150. A standpipe 152 connects from the mud pumps 150 to the drilling rig 110 to conduct drilling fluid from the mud pumps 150 to the Kelly hose and other flow connections. The standpipe 152 can include a pressure sensor 250c near the mud pumps 150 or elsewhere in the flow after the mud pumps 150.

Here, the standpipe 152 also includes flow equipment 160 connected between the mud pumps 150 and the drilling rig 110 for directing drilling flow into the drillstring 14 via the Kelly hose or via the clamp 174. The flow equipment 160 includes a supply line 165a connected from the mud pumps 150 to the top drive inlet 114. A supply pressure sensor 250a, a supply flowmeter 166a, and a supply shutoff valve 164a may be assembled as part of the supply line 165a.

Additionally, the flow equipment 160 includes a bypass line 165b connecting the standpipe 152 from the mud pump 150 to the clamp 174. An HPU 170 connects by hydraulic lines and manifold 172 to the clamp 174 to control its operation. For example, when the top drive 116 runs the drillstring 14 into the wellbore 12, the clamp 174 can engage the flow sub 118, and the pumped flow of the drilling fluid can be bypassed to the bypass line 165b. In this way, continuous flow into the drillstring 14 can be maintained while making up new stands 14a of pipe to the drillstring 14. A bypass pressure sensor 250b, bypass flowmeter 166b, and bypass shutoff valve 164a can be assembled as part of the bypass line 165b.

Finally, the flow equipment 160 can further include a drain line 161 connecting the transfer line 144 to the supply and bypass lines 165a-b. Drain prongs of the drain line 161 can have drain valves, pressure chokes 162a-b, and the like connected to an outlet of the mud pump 150.

The pressure sensor 240, 250a-c can use any suitable sensor for measuring pressure, such as a pressure transducer, a pressure gauge, a diaphragm-based pressure transducer, a strain gauge-based pressure transducer, an analog device, an electronic device, or the like.

Each return choke 122, 162, etc. may include a hydraulic actuator operated by the control system 200 via an auxiliary HPU (not shown). The return choke 122 receiving flow returns diverted from riser package 30 is operated by the control system 200 to adjust backpressure in the riser 22 and the wellbore 12 for well control.

The flow choke 162a may be operated by the control system 200 to prevent a flow rate supplied to the flow sub 118 and the clamp 174 in bypass mode from exceeding a maximum allowable flow rate of the flow sub 118 and/or clamp 174. The pressure choke 162b may be operated by the control system 200 to protect against overpressure of the clamp 174 by the mud pumps 150. Each shutoff valve 164a-b and others may be automated and have a hydraulic actuator (not shown) operable by the control system 200 via the auxiliary HPU.

For purposes of understanding, the drilling system 10 generally includes an inlet (11i) and an outlet (110) for the flow of drilling fluid in a drilling operation. The inlet (11i) in general includes one or more features, such as the choke manifold 120, flow lines, flow spool 40, RCD 60, and the like that receive or divert flow returns as inflow to the components of the rig 110. The outlet (110) in general includes one or more features, such as standpipe 152, the top drive inlet 114, top drive 116, flow sub 118, flow lines 165a-b, and the like that direct flow as outflow from the components of the rig 110.

The control system 200 of the drilling system 10 integrates hardware, software, and applications across the drilling system 10 and is used for monitoring, measuring, and controlling parameters in the drilling system 10. In this contained environment of the closed-loop drilling system 10, for example, minute wellbore influxes or losses are detectable at the surface, and the control system 200 can further analyze pressure and flow data to detect kicks, losses, and other events. In turn, at least some operations of the drilling system 10 can be automatically handled by the control system 200.

To monitor operations and provide computerized control, the control system 200 uses data from a number of the sensors and devices in the drilling system 10. In particular, the control system 200 uses the one or more pressure sensors 240 uphole of the choke manifold 120 to measure pressure in the flow returns from the riser 22 and the wellbore 12. As the return choke 122 in the manifold 120 is adjusted, the one or more pressure sensors 240 measure the surface backpressure SBP applied to the riser 22 and the wellbore 12.

In addition, the control system 200 can use the one or more sensors 250a-c downstream of the mud pumps 150 to measure pressure in the standpipe 152 (i.e., the standpipe pressure SPP). One or more other sensors (i.e., stroke counters) can measure the speed of the mud pumps 150 for deriving the flow rate of drilling fluid into the drillstring 14. In this way, flow into the drillstring 14 may be determined from strokes-per-minute and/or standpipe pressure SPP. The flowmeters 166a-b after the mud pumps 150 can also be used to measure flow-in (e.g., inflow) to the wellbore 12.

One or more sensors (not shown) can measure the volume of fluid in the mud tanks 142 and can measure the rate of flow into and out of mud tanks 142. In turn, because a change in mud tank level can indicate a change in drilling fluid volume, flow-out (e.g., outflow) of the wellbore 12 may be determined from the volume entering the mud tanks 142.

Rather than relying on conventional pit level measurements, paddle movements, and the like, the drilling system 10 can use mud logging equipment and flowmeters to improve the accuracy of detection. For example, the drilling system 10 preferably uses the flowmeter 124, such as a Coriolis mass flowmeter, on the choke manifold 120 to capture fluid data-including mass and volume flow, mud weight (i.e., density), and temperature-from the returning annular fluids in real-time, at a sample rate of several times per second. Because the return flowmeter 124, such as a Coriolis flowmeter, can give a direct mass rate measurement, the return flowmeter 124 can measure gas, liquid, or slurry. Other sensors can be used, such as ultrasonic Doppler flowmeters, SONAR flowmeters, magnetic flowmeter, rolling flowmeter, paddle meters, etc.

Each pressure sensor 240, 250a-c may be in data communication with the control system 200. The return pressure sensor 240 measures surface backpressure (SBP) exerted by the returns choke 122. The pressure sensor 250c and/or the supply pressure sensor 250a measures standpipe pressure (SPPM) to the Kelly hose, whereas the pressure sensor 250c and/or the bypass pressure sensor 250b measures the standpipe pressure SPP to the clamp 174 during connection of a standpipe.

As noted above, the return flowmeter 124 may be a mass flow meter, such as a Coriolis flowmeter, and is in data communication with the control system 200. The return flowmeter 124 connected in the return line 62 downstream of the returns choke 122 measures a flow rate of the returns. Each of the supply and bypass flowmeters 166a-b may be a volumetric flowmeter, such as a Venturi flowmeter. The supply flowmeter 166a measures a flow rate of drilling fluid supplied by the mud pump 150 to the drillstring 14 via the top drive 116. The bypass flowmeter 164b measures a flow rate of drilling fluid supplied by the mud pump 150 to the clamp 174. The control system 200 can receive a density measurement of the drilling fluid from a mud blender (not shown) or other source to determine a mass flow rate of the drilling fluid. Alternatively, the bypass and supply flowmeters 166a-b may each be mass flowmeters.

Additional sensors can measure mud gas, flow line temperature, mud density, and other parameters. For example, a flow sensor can measure a change in drilling fluid volume in the well. Also, a gas trap, such as an agitation gas trap, of the mud gas separator 130 can monitor hydrocarbons in the drilling mud at surface. To determine the gas content of drilling mud, for example, the gas trap of the mud gas separator 130 mechanically agitates mud flowing in a tank. The agitation releases entrained gases from the mud, and the released gases are drawn-off for analysis. The spent mud is simply returned to the tanks 142 to be reused in the drilling system 10.

A gas evaluation device can be used for evaluating fluids in the drilling mud, such as evaluating hydrocarbons (e.g., C1 to C10 or higher), non-hydrocarbon gases, carbon dioxide, nitrogen, aromatic hydrocarbons (e.g., benzene, toluene, ethyl benzene and xylene), or other gases or fluids of interest in drilling fluid. Accordingly, the device 126 can include a gas extraction device that uses a semi-permeable membrane to extract gas from the drilling mud for analysis.

A multi-phase flowmeter can be installed in the flow line to assist in determining the make-up of the fluid. As will be appreciated, the multi-phase flow meter can help model the flow in the drilling mud and provide quantitative results to refine the calculation of the gas concentration in the drilling mud.

With the overview of the drilling system 10 provided above, discussion turns to operation of the drilling system 10 in drilling a wellbore 12. During drilling operations, the mud pumps 150 pump drilling fluid from the transfer line 144 (or fluid tank connected thereto), through the standpipe 152 and the Kelly hose to the top drive 116. The drilling fluid may include a base liquid, such as oil, water, brine, or a water/oil emulsion. The base oil may be diesel, kerosene, naphtha, mineral oil, or synthetic oil. The drilling fluid may further include solids dissolved or suspended in the base liquid, such as organophilic clay, lignite, and/or asphalt, thereby forming a mud.

The drilling fluid at the inlet 114 flows into the drillstring 14 via the top drive 116 and flow sub 118. The drilling fluid flows down through the drillstring 14 and exits the drill bit 18 of the BHA 16, where the fluid circulates the cuttings away from the drill bit 18 and returns the cuttings up an annulus formed between the casing or wellbore 12 and the drillstring 14. The returns (drilling fluid plus cuttings) that flow through the annulus to the wellhead 20 then continue into the annulus of the riser 22 up to the RCD 60.

At the RCD 60, the drilling system 10 uses the RCD 60 to keep the well closed to atmospheric conditions. The returns are diverted into the return line 32 and continue through the returns choke 122 and the return flowmeter 124. Therefore, fluid leaving the wellbore 12 flows through the automated choke manifold 120, which measures return flow (e.g., flow-out) and density using the return flowmeter 124 installed in line with the return chokes 122. The returns then flow into the shale shaker 140, which removes the cuttings. As the drilling fluid and returns circulate, the drillstring 14 may be rotated by the top drive 116 and lowered by the traveling block, thereby extending the wellbore 12 into the lower formation F.

Throughout the drilling operation, the fluid data and other measurements noted herein are transmitted to the control system 200, which in turn operates drilling functions. In particular, the control system 200 operates the automated choke manifold 120 to manage pressure and flow during drilling. This can be achieved using an automated choke response in the closed and pressurized circulating system 10 made possible by the RCD 60.

To do this, the control system 200 controls the return chokes 122 with an automated response by monitoring the flow-in and the flow-out of the well, and software algorithms in the control system 200 seek to maintain a mass flow balance. If a deviation from mass flow balance is identified, the control system 200 initiates an automated choke response that changes the well's annular pressure profile and thereby changes the wellbore's equivalent mud weight. This automated capability of the control system 200 allows the control system 200 to perform dynamic well control or CBHP techniques.

Software components of the control system 200 then compare the flow rate in and flow rate out of the wellbore 12, the injection or standpipe pressure SPP (measured by the one or more sensors 250a-c), the surface backpressure SBP (measured by the one or more pressure sensors 240 upstream from the drilling system's return chokes 122), the position of the return chokes 122, and the mud density, among other possible variables. Comparing these variables, the control system 200 then identifies minute downhole influxes and losses on a real-time basis to manage the annular pressure (AP) during drilling by apply adjustments to the surface backpressure (SBP) with the choke manifold 120.

By identifying the downhole influxes and losses during drilling, for example, the control system 200 monitors circulation to maintain balanced flow for CBHP under operating conditions and to detect kicks and lost circulation events that jeopardize that balance. The drilling fluid is continuously circulated through the drilling system 10, choke manifold 120, and the return flowmeter 124. As will be appreciated, the flow values may fluctuate during normal operations due to noise, sensor errors, etc. so that the control system 200 can be calibrated to accommodate such fluctuations. In any event, the control system 200 measures the flow-in and flow-out of the well and detects variations. In general, if the flow-out is higher than the flow-in, then fluid is being gained in the drilling system 10, indicating a kick. By contrast, if the flow-out is lower than the flow-in, then drilling fluid is being lost to the formation, indicating lost circulation.

To then control pressure, the control system 200 introduces pressure and flow changes to the incompressible circuit of fluid at the surface to change the annular pressure profile in the wellbore 12. In particular, using the choke manifold 120 to apply surface backpressure SBP within the closed loop, the control system 200 can produce a reciprocal change in BHP. In this way, the control system 200 uses real-time flow and pressure data and manipulates the annular backpressure to manage wellbore influxes and losses.

To do this, the control system 200 uses internal algorithms to identify what event is occurring downhole and can react automatically. For example, the control system 200 monitors for any deviations in values during drilling operations, and alerts the operators of any problems that might be caused by a fluid influx into the wellbore 12 from the formation F or a loss of drilling mud into the formation F. In addition, the control system 200 can automatically detect, control, and circulate out such influxes and losses by operating the return chokes 122 on the choke manifold 120 and performing other automated operations.

A change between the flow-in and the flow-out can involve various types of differences, relationships, decreases, increases, etc. between the flow-in and the flow-out. For example, flow-out may increase/decrease while flow-in is maintained; flow-in may increase/decrease while flow-out is maintained, or both flow-in and flow-out may increase/decrease.

In general, a possible fluid influx or “kick” can be noted when the “flow-out” value (measured from the return flowmeter 124) deviates from the “flow-in” value (measured from the flowmeter 166a-b or the stroke counters of the mud pumps 150). As is known, a “kick” is the entry of formation fluid into the wellbore 12 during drilling operations. The kick occurs because the pressure exerted by the column of drilling fluid is not great enough to overcome the pressure exerted by the fluids in the formation being drilled.

On the other hand, a possible fluid loss can be noted when the “flow-in” value (measured from the stroke counters of the mud pumps 150 or inlet flowmeter 166a-b) is greater than the “flow-out” value (measured by the return flowmeter 124). As is known, fluid loss is the loss of whole drilling fluid, slurry, or treatment fluid containing solid particles into the formation matrix. The resulting buildup of solid material or filter cake may be undesirable, as may be any penetration of filtrate through the formation, in addition to the sudden loss of hydrostatic pressure due to rapid loss of fluid.

Similar steps as those given above, but suited for fluid loss, can then be implemented by the control system 200 to manage the pressure and flow during drilling in this situation. In general, higher density mud loss control materials (LCM), and the like may be pumped into the wellbore 12, and other remedial measures can be taken. For example, the operator can initiate pumping new mud with the recommended or selected kill mud weight. As the kill mud starts to go down the wellbore 12, the return chokes 122 are opened up gradually approaching a snap position as the kill mud circulates back up to the surface. Once the kill mud turns the drill bit 18, the control system 200 again switches back to the standpipe pressure (SPP) control until the kill mud circulates back up to the surface.

During drilling operations, the control system 200 operates the return choke 122 so that a target bottom hole pressure (BHP) can be maintained in the annulus during the drilling operation. The target BHP may be selected within a drilling window. A lower boundary of the drilling window is defined as greater than or equal to a minimum threshold pressure, such as pore pressure (PP), of the lower formation F. An upper boundary of the drilling window is defined as less than or equal to a maximum threshold pressure, such as fracture pressure (FP), of the lower formation F. For example, a target BHP may be selected as an average of the pore and fracture pressures of the lower formation F being drilled with an advancing borehole.

As an alternative, the minimum threshold for the lower boundary may be stability pressure and/or the maximum threshold for the upper boundary may be a leak-off pressure. As another alternative, threshold pressure gradients may be used instead of pressures, and the pressure gradients may be at other depths along the lower formation F besides bottomhole, such as the depth of the maximum pore gradient and the depth of the minimum fracture gradient. In alternatives disclosed herein, the control system 200 may be free to vary the BHP within the drilling window during the drilling operation. A static density of the drilling fluid (typically assumed equal to returns; effect of cuttings typically assumed to be negligible) may correspond to a threshold pressure gradient of the lower formation F, such as being greater than or equal to a pore pressure gradient.

During the drilling operation, the control system 200 can execute a real-time simulation of the drilling operation to predict the actual BHP from measured data, such as from the standpipe pressure SPP measured from the sensor 250a-c, mud pump flowrate measured from the supply flowmeter 166a, wellhead pressure from any of the sensors, and return fluid flowrate measured from the return flowmeter 124. The control system 200 then compares the predicted BHP to the target BHP and adjusts the return choke 122 accordingly. The control system 200 can also use PWD data to estimate the BHP during the drilling operation so control system 200 can compare the estimated BHP to the target BHP and can adjust the return choke 122 accordingly.

During the drilling operation, the control system 200 also performs a mass balance to monitor for instability of the lower formation F, such as a kick event or lost circulation event. As the drilling fluid is being pumped into the wellbore 12 by the mud pump 150 and the returns are being received from the return line 32, the control system 200 may compare the mass flow rates (i.e., drilling fluid flow rate minus returns flow rate) using the respective flowmeters 124, 166a-b. The control system 200 may use the mass balance to monitor for formation fluid (not shown) entering the annulus and contaminating the returns or returns entering the formation F.

Upon detection of instability (e.g., kick), the control system 200 takes remedial action, such as diverting the flow of returns from an outlet of the return flowmeter 124 to the mud gas separator 130. A gas detector of the mud gas separator 130 can use a probe having a membrane for sampling gas from the returns, a gas chromatograph, and a carrier system for delivering the gas sample to the chromatograph. The control system 200 may also adjust the returns choke 122 accordingly, such as tightening the choke in response to a kick and loosening the choke in response to loss of the returns.

Alternatively, the control system 200 may include other factors in the mass balance, such as displacement of the drillstring and/or cuttings removal. The control system 200 may calculate a rate of penetration (ROP) of the drill bit 18 by being in communication with the drawworks and/or from a pipe tally. A mass flowmeter may be added to the cuttings chute of the shaker 140, and the control system 200 may directly measure the cuttings mass rate.

Having an understanding of the drilling system 10, discussion now turns to some additional details of the components of the control system 200. FIG. 2 schematically illustrates some details of the control system 200 of the present disclosure. The control system 200 includes a processing unit 210, which can be part of a computer system, a server, a programmable control device, a programmable logic controller, etc. Using input/output interfaces 230, the processing unit 210 can communicate with choke manifold 120 and other system components to obtain and send operational data 232 (e.g., communication, sensor, actuator, and control signals) for the various system components as the case may be. In terms of the current controls discussed, the control signals of the operational data 232 can include, but are not limited to, the choke position signals, pressure signals, flow signals, temperature signals, fluid density signals, etc.

In addition to the chokes 122a-b, the return flowmeter 124, and pressure sensors 240, the choke manifold 120 can include a local controller (not shown) to control operation of the manifold 120, and manifold 120 can include a hydraulic power unit (HPU) and/or electric motor to actuate the return chokes 122. The control system 200 is communicatively coupled to the manifold 120 and has a control panel with a user interface and processing capabilities to monitor and control the manifold 120.

The processing unit 210 also communicatively couples to a database or storage 220 having set points 222, a hydraulics model 224, and other stored information. The hydraulics model 224 characterizes the well pressure system. This information for the hydraulics model 224 can be stored in any suitable form, such as lookup tables, curves, functions, equations, data sets, etc. Additionally, multiple hydraulics models 224 or the like can be stored and can characterize the system in terms of different system arrangement, different drilling fluids, different operating conditions, and other scenarios.

As will be appreciated, the hydraulics model 224 of the control system 200 can be built based on the various components, elements, and the like in drilling system 10. The hydraulics model 224 can be built with any complexity desired to model the drilling system 10, which as noted above with reference to FIG. 1 can have a great deal of complexity and information associated with it and which can change over time depending on drilling parameters. The processing unit 210 operates a pressure control 212 according to the present disclosure, which uses a dynamically determined drilling window 400. (Details of how the pressure control 212 uses the dynamically determined drilling window 400 will be discussed below.)

Finally, the processing unit 210 uses the current pressure profile from the pressure control 212 to operate a choke control 214 according to the present disclosure for monitoring and controlling the choke(s) 122a-b. For example, the processing unit 210 can transmit signals to one or more of the chokes 122a-b of the drilling system 10 using any suitable communication. In general, the signals are indicative of a choke position or position adjustment to be applied to the chokes 122a-b. Typically, the chokes 122a-b are controlled by hydraulic power so that the signals 105 transmitted by the processing unit 210 may be electronic signals that operate solenoids, valves, or the like of an HPU for operating the chokes 122a-b.

As shown here in FIG. 2, two chokes 122a-b may be used. The same choke control 214 can apply adjustments to both chokes 122a-b, or separate choke controls 214 can be used for each choke 122a-b. In fact, the two chokes 122a-b may have differences that can be accounted for in the two choke controls 214 used.

As discussed herein, the control system 200 uses the choke control 214 tuned in real-time to manage surface backpressure SBP, and the control system 200 uses pressure measurements from the pressure sensors 240 associated with the choke(s) 122a-b to determine the surface backpressure SBP of the system.

Having an understanding of the drilling system 10 and the control system 200, discussion now turns to a process 300 in FIG. 3 for dynamically determining a drilling window (400) used in a drilling operation according to the present disclosure. For discussion, reference is made to the drilling system 10 and control system 200 of FIGS. 1-2. FIG. 4 illustrates a graph of an example for a dynamically determined drilling window 400 according to the present disclosure.

The process 300 begins with obtaining data for input into the hydraulics model 224 of the drilling operation at hand (Block 310). Using the input data, the hydraulics model 224 is built as a well pressure model from the components, arrangement, properties, and other details of the drilling system 10 used during the MPD operation (Block 320).

As some examples, the hydraulics model 224 is built using input data of the well trajectory. The input data for the well trajectory include values for measured depth (MD), inclination, and azimuth. The hydraulics model 224 is also built using geometric parameters for the drilling system 10, including the geometry (diameter and depths) for the annulus (riser, casing, open hole) and the geometry for the drillstring segments.

The hydraulics model 224 is built using fluid properties of the drilling fluid used in the drilling operation, formation properties of the formation being drilled, and system properties of the drilling system 10 being used. The drilling fluid properties can include the drilling fluid's density (base type and fraction, pressure-volume-temperature (PVT) coefficients, composition fractions, salinity) and the fluid's rheology. The hydraulics model 224 is also built using thermal properties (specific heat, conductivity) for the drilling fluid, formation, and metal elements of the drilling system 10, and the hydraulics model 224 is built using the formation temperature. The hydraulics model 224 is further built using empirical formulas for the local pressure losses from particular tool(s) used for the drilling operations. These particular tools are typically customized tools for the drilling operation, such as the BHA 16, rotary steerable systems, the RCD 60, wellhead components, etc. Finally, the hydraulics model 224 is built using at least some of the operational data 232 obtained during drilling. The operational data 232 can include: surface backpressure (SBP), flow rate, rotation rate (RPM), bit depth, fluid input temperature, standpipe pressure (SPP), and the like.

The complexity of the hydraulics model 224 can be defined as desired, given all of the information available. Certain assumptions can be used in the hydraulics model 224. For example, the solution functions of the hydraulics model 224 can be assumed to depend on the measured depth (x) of the wellbore 12. Any radial dependence of the hydraulics model 224 may be assumed to be averaged. For convenience, the drillstring segments may be assumed to have a constant diameter. These and other assumptions can be used.

With the hydraulics model 224 built, the MPD operation can begin by using the constructed hydraulics model 224 (Block 330) to manage pressure, detect flow imbalance, determine influxes and losses, adjust the surface backpressure SBP with the chokes 122a-b, and perform other relevant operational steps.

In the process 300 while drilling the wellbore in the MPD drilling operation using the closed-loop drilling system 10, for example, the control system 200 monitors inflow at the inlet (Block 340), monitors outflow at the outlet (Block 342), and measures surface backpressure at the outlet (Block 344). In general, measuring the inflow of the drilling fluid into the wellbore can involve measuring the inflow with a flowmeter in communication with the inflow (Block 340). Similarly, measuring the outflow of the drilling fluid from the wellbore can involve measuring the outflow with a flowmeter in communication with the outflow (Block 342). Other techniques disclosed herein can be used.

To measure the surface backpressure at the outlet (Block 344), a value of the surface backpressure can be measured with a sensor disposed upstream of the at least one choke 122a-b. As noted, one or more sensors upstream of the choke manifold 120 can provide readings of the surface backpressure SBP. The sensor can be a pressure transducer, a pressure gauge, a diaphragm-based pressure transducer, and a strain gauge-based pressure transducer, an analog device, and an electronic device.

In the MPD operations, the bottomhole pressure (BHP) is adjusted at a setpoint to control pressure. The adjustments are ultimately performed in various steps or Blocks (380) of the process 300. The technique disclosed herein allows the drilling system 10 to automatically measure lower and upper boundaries 410, 420 for the dynamically determined drilling window 400 as shown in the example of FIG. 4 so a target bottom hole pressure (BHP) can be maintained in the annulus when performing the adjustment steps or Blocks (380) during the MPD operation.

As already noted above, the target BHP may be selected within a drilling window 400 having a lower boundary defined as greater than or equal to a minimum threshold pressure for the lower boundary 410, such as pore pressure (PP), of the lower formation F and having an upper boundary defined as less than or equal to a maximum threshold pressure for the upper boundary 420, such as fracture pressure (FP), of the lower formation, such as an average of the pore and fracture BHPs. Thus, the lower boundary 410 of the drilling window 400 can be the pore pressure, and the upper boundary of the drilling window 400 can be the fracture pressure. As also noted above, other values for the boundaries could be used.

Accordingly, the dynamic drilling window 400 is repeatedly determined and updated (Blocks 350 to 370) while drilling in the MPD operation. An estimated lower boundary of the drilling window 400 for a target BHP is estimated by reducing the surface backpressure (Block 350) while simultaneously monitoring the inflow and the outflow until a signature influx is measured (Block 352). Reducing the surface backpressure (Block 350) can involve stepwise or incrementally reducing the surface backpressure. When estimating the lower boundary 410, a pressure value determined from the signature influx can be indicative of the current BHP approaching (being equal to or slightly less than) a pore pressure of the downhole formation at current depth. When estimating the lower boundary, monitored surface parameters (including gas-at-surface, flowline pressure, and difference in the inflow and the outflow) can be correlated to evaluate the pore pressure at the current depth.

As seen, the estimated lower boundary 410 (e.g., the pore pressure) for the drilling window 400 can be measured using a form of Dynamic Pore Pressure Test (DPPT) while drilling with the drilling system 10. The drilling system 10 on the rig can perform the DPPT operation without any downtime or additional cost. The DPPT operation is done by stepwise reducing the surface backpressure (SBP) while simultaneously monitoring the return flow, until a signature micro influx is observed. (The well must be statically underbalanced for an influx to be observed). This signature influx point indicates a value at which the BHP reaches (e.g., becomes equal to or slightly less than) the pore pressure. Advantageously, the DPPT operation is conducted at full circulation rate, enabling a Pressure While Drilling (PWD) tool on the bottom hole assembly to continue reading the actual BHP during the test, reducing uncertainties about the BHP.

As discussed in more detail below, the value of the pore pressure, obtained by the estimation in Blocks 350-352, can be used to quantitatively calibrate the coefficients for the empirical correlations being used. The calculated coefficients for a normal compaction trendline (NCT) are substituted back into the available methods, and a real pore pressure point is estimated. This method provides more accurate estimations for predicting ahead of the drill bit on the bottom hole assembly because the method evaluates how the rock at a further depth is compacted using real data from the previous depth.

Continuing with the process 300 in FIG. 3, an estimated upper boundary 420 of the drilling window 400 for the target BHP is estimated by increasing the surface backpressure (Block 360) while simultaneously monitoring the inflow and the outflow until a signature loss is measured (Block 362). Increasing the surface backpressure (Block 360) can include stepwise or incrementally increasing the surface backpressure. When estimating the upper boundary 420, a pressure value determined from the signature loss can be indicative of the BHP approaching (i.e., being equal to or slightly greater than) a fracture pressure of the downhole formation at current depth.

As seen, the estimated upper boundary 420 (e.g., the fracture pressure) for the drilling window 400 can be determined using a form of Diagnostic Fracture Injection Test (DFIT) or Diagnostic Leakoff Test (DLOT) by stepwise increasing the SBP while simultaneously monitoring the return flow until a loss is observed. This point of signature loss indicates a value at which the BHP reaches (e.g., becomes equal to or slightly greater than) the fracture pressure.

Either one or both of the upper and lower boundaries 410, 420 can be estimated in Blocks 350-352/360-362 at each iteration during an interval 408 of the wellbore being drilled, and they can be estimated in either order. For example, the boundaries 410, 420 of the drilling window 400 can be dynamically determined every few hundred feet during drilling or other interval 408. Any current drilling window 400 stored in the control system 200 is updated with the new estimation (Block 370), and the MPD operation continues while using the updated drilling window 400 (Block 372). (An arbitrary example for an interval 408 is shown in FIG. 4 simply for the purposes of illustration. The actual intervals 408 in the wellbore can vary based on a number of factors, such as rate of penetration, characteristics of the formation, and the like).

This procedure (Blocks 350 to 370) can be repeated at its own processing increment at any time as necessary and desired during drilling. Preferably, the processing unit 210 includes instructions in firmware to improve the processing increment. For example, the processing unit 210 may operate to provide updates to the drilling window 400 at various time or processing increments. Additionally or alternatively, the procedure (Blocks 350 to 370) can be governed by an overall processing, depth, or time or processing increment (Block 302) of the drilling operation.

Continuing in the process 300 of FIG. 3, the drilling system 10 continues by adjusting a parameter in the MPD operation as needed based on the drilling window 400 and based on any other measured parameters (Block 380). In managing pressures, the dynamically determined drilling window 400 is used in the pressure control 212 of the MPD operation (Block 380). In the MPD operation (Blocks 380), for instance, the control system 200 measures a parameter of the drilling operation (Block 382), determines an adjustment to the parameter (Block 384), and performs the adjustment (Block 386). To adjust the parameter in the drilling operation at Block 384, various operations can be performed, including adjusting at least one of: mud weight of the drilling fluid, a flow rate of the drilling fluid out of the wellbore using the at least one choke, a pressure of flow of the drilling fluid out of the wellbore using the at least one choke, a current value of the surface backpressure in the wellbore, a mass flow rate of the drilling fluid out of the wellbore, a pressure during make-up of a drillpipe connection while drilling with the drilling system 10, a pressure during a loss detected while drilling with the drilling system 10, or a flow rate during a kick detected while drilling with the drilling system 10.

As an example, the surface backpressure SBP may need to be adjusted because there is a determined imbalance between the flow-in versus the flow-out indicative of a kick or an influx. Therefore, a new choke position is determined to produce the needed surface backpressure SBP to control the kick so the BHP can stay within a target BHP of the drilling window 400. The control system 200 actuates the chokes 122a-b to produce the needed surface backpressure SBP. Comparable adjustments can be made for losses and other well-control operations with the control system 200.

As expected, these steps are repeated while drilling in the MPD drilling operation and can be governed by a processing increment, depth interval 408, time increment, and the like (Block 302). For example, the tests from Blocks 350 to 362 can be performed at predetermined depth intervals (e.g., every few hundred meters) as the wellbore is drilled so the drilling window 400 can be dynamically determined ahead of the bottom hole assembly in an ongoing process.

As shown in the graph of FIG. 4, static pressure 404 increases with depth due to the increasing hydrostatic pressure 402 in the wellbore. Hydrostatic pressure 402 can be estimated by known techniques. During drilling operations, the dynamic pressure 406 above the static pressure 404 is controlled between the dynamically determined boundaries 410, 420 (e.g., pore pressure and fracture pressure) of the drilling window 400.

Thus, using the disclosed process 300 of FIG. 3, the drilling system 10 dynamically determines the lower and upper boundaries of the drilling window 400 and navigates the target BHP between the two boundaries 410, 420 in the drilling window 400 by automatically adjusting the surface backpressure (SBP). The MPD operation aims to produce an Equivalent Circulating Density (ECD) 430 that maintains the bottomhole pressure within the boundaries 410, 420 of the dynamic drilling window 400. As is known, the ECD is a function of the surface backpressure (SBP), mud weight (MW), and friction pressure (Pfriction). (The friction pressure can be determined by techniques known in the art.) Accordingly, the adjustments to the surface backpressure can change the equivalent circulating density (ECD) during the MPD operation to stay in the drilling window 400. In the end, being able to manage pressures in this manner allows the drilling operation to more effectively reach target depths, stay within the drilling window 400, handle imbalances, and perform other operations noted herein.

During conventional operation, pore pressure estimations can be performed (i) before drilling (using geophysical data), (ii) while drilling (using MWD/LWD data), and (iii) after drilling (using wireline data). Being able to obtain real pore pressure measurements is still a challenge. There are conventional tools, such as Repeat Formation Tester (RFT), Drill Stem Test (DST), and the like, which can measure pore pressure. However, these conventional tools have limitations because their use can produce delays in the drilling operation and the tools may be limited to measuring in only certain formations. According to the disclosed process 300, however, the drilling system 10 uses tests during drilling to obtain pore pressure measurements frequently at different depth intervals (408). The measurements with the drilling system 10 can also be performed on any type of formation. This reduces the non-productive time inherent when using conventional tools (e.g., RFT and DST) without compromising operational safety.

Advantageously, data from the pressure sensors (240, 250a-c) can be readily available in real-time at high speed. In the meantime, PWD data may not always be available and is often delayed data. For example, PWD data may only be available at flow rates above 250-gpm so there may not even be data available for calibration during drillpipe connections or during low Slow Circulation Rate (SCR). For these reasons, the data used in dynamically determining the drilling window 400 according to the process 300 provides a useful source for knowing what is going on downhole. Nevertheless, the teachings of the present disclosure can further benefit by using PWD data.

The process 300 as outlined in FIG. 3 can include a number of additional steps when dynamically determining the drilling window 400 and when updating the hydraulics model 224. FIG. 5A shows a few of these steps that can be performed in the process 300 of FIG. 3. In general, the process 300 can perform one or more steps of calculating for friction pressure loss in the system (Block 390), measuring standpipe pressure (Block 392), using an estimate or measurement of bottom hole pressure (BHP) (Block 394), measuring BHP with a Pressure-While-Drilling (PWD) sensor (Block 396), calibrating the hydraulics model (Block 398), and the like.

In particular, FIG. 5B illustrates a simplified representation of a hydraulics model 224 of the drilling system 10 for the present disclosure. The mud pump(s) 150 at the inlet of the drilling system 10 pump drilling fluid through the standpipe 152 into the drillstring 14, which is made up of known pipe details. The standpipe 152 includes the one or more pressure sensors 250 for measuring the standpipe pressure SPP.

The drilling fluid in the bore 15 of the drillstring 14 is subject to friction, hydrostatic pressures, different geometries of the drill pipes making up the drillstring 14, the characteristics of the drilling fluid, etc., which are defined in the hydraulics model 224. Exiting from the BHA 16, the drilling fluid then passes up the annulus 13 of the wellbore 12. The flow of the drilling fluid up the annulus 13 is subject to friction from the wellbore 12 and the drillstring 14, hydrostatic pressures, the geometry of the annulus 13, the characteristics of the drilling fluid, temperature of the formation, heat transfer variables, etc., which are defined in the hydraulics model 224. (As will be appreciated, when a riser 22 is used, the wellbore 12 for the hydraulics model would include both the wellbore 12 in the formation and the riser 22. Additionally, modeling of the wellhead may also be done as being part of the wellbore 12.)

The drilling fluid exits the annulus 13 at the outlet of the wellbore 12 and passes to the choke manifold 120. One or more pressure sensors 240 at the choke's inlet can measure the surface backpressure SBP. As an addition, the bottom hole assembly 16 can include a pressure-while-drilling (PWD) sensor 260 that can be used in determining a value of a current BHP of the drilling system 10. Further details of this will be provided later.

If a PWD sensor 260 is used, a pressure-while-drilling value can be measured (Block 396) that is indicative of a measured BHP at the bottom hole assembly 16 of the drillstring 14. Adjusting the parameter in the drilling operation can therefore involve adjusting the surface backpressure in the drilling operation to bring the measured bottom hole pressure toward a target bottom hole pressure in the drilling window (400). When measuring the pressure-while-drilling value, the PWD sensor 260 on the bottom hole assembly 16 can read pressure values conducted at full circulation rate.

In an alternative when a PWD sensor 260 is absent or readings are not available, the control system 200 can estimate a BHP value (Block 394) at the bottom hole assembly 16 of the drillstring 14 and can adjust the surface backpressure in the drilling operation to bring the estimated BHP toward the target BHP within the drilling window (400). To estimate the BHP, a pressure profile can be integrated from the measured surface backpressure value down an annulus of the wellbore to the bottom hole assembly 16 disposed in the wellbore. If a standpipe pressure is measured at the inlet (Block 392), then an estimated bottom hole pressure can be determined by integrating a pressure profile from the bottom hole assembly 16 up the drillstring 14 to the measured standpipe pressure. As noted, measuring a value of the standpipe pressure can use a pressure sensor 250 disposed in communication with the inflow of the drilling fluid into the wellbore downstream of the at least one mud pump 150. The pressure sensor 250 can be a pressure transducer, a pressure gauge, a diaphragm-based pressure transducer, a strain gauge-based pressure transducer, an analog device, and an electronic device.

During operations, the friction pressure loss can be calculated to calibrate the hydraulics model (Block 398). To do this, the standpipe pressure is measured (Block 392), along with the surface backpressure and other measurements. If PWD data is available from a PWD sensor 260, the estimated BHP (Block 394) can be compared to a BHP determined from the PWD data. The integration of the pressure profile of the hydraulics model 224 for the drilling system 10 can then determine errors for calibrating the pressure losses in the hydraulics model 224. For instance, integration can start from the surface backpressure SBP measured at the choke's pressure sensor (240) and can integrate down the annulus (13). This integration leg can be used to estimate a value of a bottom hole pressure (BHP). A measured value of the bottom hole pressure BHPM as determined from PWD data measured with the PWD sensor 260 on the BHA 16 (Block) can then be compared to the estimated bottom hole pressure BHPE (Block). This first difference between estimated bottom hole pressure BHPE and measured bottom hole pressure BHPM can provide an intermediate error indicative of the pressure losses missing from the hydraulics model 224 in this annular leg.

Meanwhile, the integration from the BHA (16) up the drillstring (14) can be used to estimate a value of standpipe pressure SPP. As before, the estimated standpipe pressure value SPPE can be compared to the measured value of the standpipe pressure SPPM from standpipe sensor 250a-c after the mud pumps 150. This second difference between estimated standpipe pressure SPPE and measured standpipe pressure SPPM can provide another error indicative of the pressure losses missing from the hydraulics model 224 in this drillstring leg. These two differences can be used for the correction of the friction pressure loss. Accordingly, a calibration step (Block) in the process can be used to calibrate pressure loss based on these two differences. Further details of this technique are disclosed in co-pending application Ser. No. 16/433,837 filed Jun. 6, 2019, which is incorporated herein by reference.

As noted above in the steps of the process, a form of Dynamic Pore Pressure Test (DPPT) is used during MPD operations to determine a lower boundary (e.g., pore pressure) for the drilling window used during drilling. FIG. 6 graphs a conceptual pressure profile 600 for pore pressure tests at different depths within a closed-loop managed pressure drilling (MPD) system.

Initially, geomechanical analysis seeks to estimate the pore pressure (PP) during well planning. For example, characteristics, such as gamma ray (GR), of the formation in column 601 are used along with data from offset wells in column 602 to characterize the formation to be drilled. This analysis is performed prior to drilling and can estimate pore pressures, fracture pressures, and the like based on formation velocity, magnetics, electrical data, etc. utilizing geophysical methods.

Based on those characteristics, normal compaction trendlines 606 are estimated for the formation, which will be used in developing the drilling window. Data in the MPD operation is then monitored while drilling (column 603), and pressures associated with the formation (e.g., pore pressures) are estimated from the MPD data (column 604).

Several empirical methods and formulas can be used estimate the pore pressure using seismic data, logging while drilling data, and drilling parameters. These methods can be further calibrated using data from a Repeat Formation Tester (RFT) or a Drill Stem Test (DST). According to the present techniques, the MPD operation allows precise measurement of the pore pressure using the dynamic pore pressure testing (DPPT), reducing the non-productive time inherent in RFT and DST without compromising operational safety.

Pore pressure can be estimated using a number of techniques, such as Eaton's method. In this method, stress is used in the equations:

$\begin{array}{cc}{P}_p=S-\left(S-P_{\mathrm{hyd}}\right){\left(R_{\log }/R_n\right)}^{1.2}& \left(1\right)\end{array}$ $\mathrm{and}$ $P_p=S-\left(S-P_{\mathrm{hyd}}\right){\left(\Delta T_n/\Delta T_{\log }\right)}^{3.},$

where P_p is pore pressure; S is the stress (typically, S_v); P_hyd is hydrostatic pore pressure; and the subscripts n and log refer to the normal and measured values of resistivity (R) and sonic delta-t (ΔT) at each depth. The exponents shown in Eq. 1 are typical values that are often changed for different regions so that the predictions better match pore pressures inferred from other data. Measured resistivity can be related to depth in a formation having normal pressure, and this relationship can be used to update Eaton's method to calculate the pore pressure.

The pore pressure estimation based on Eaton's method approximates the effective vertical stress with ratio of data obtained from resistivity and sonic log and normalization of the drilling parameters. The estimation of the pore pressure from the D-exponent based on Eaton's correlation is given by Eq. (2):

$\begin{array}{cc}{P}_p={\sigma }_v-\left({\sigma }_v-P_n\right){\left(\frac{d_{\mathrm{xc}}}{d_n}\right)}^{1.2}& \left(2\right)\end{array}$

where P_p is the pore pressure gradient, σ_v is the overburden gradient, P_n is the normal hydrostatic pressure gradient, d_xc is the corrected drilling exponent, d_n is the normal compaction trend of drilling exponent. The drilling exponent is based on normalization of the drilling parameters, and the d-exponent can be calculated using Eq. (3)

$\begin{array}{cc}d=\left(\frac{\log \frac{\mathrm{ROP}}{60\mathrm{RPM}}}{\log \frac{12\mathrm{WOB}}{10^6{d}_{\mathrm{bit}}}}\right)& \left(3\right)\end{array}$

where ROP is the rate of penetration (ft/hr), RPM is the revolution per minute, WOB is the weight on bit (lbf), and d_bit is the bit diameter (in). To account for changes of the mud density to the model, Eq. (4) can be used to produce a corrected D-exponent.

$\begin{array}{cc}{d}_{\mathrm{xc}}=d\left(\frac{{\mathrm{PG}}_n}{\mathrm{ECD}}\right)& \left(4\right)\end{array}$

where PG_n is the normal pressure gradient (ppg), and ECD is the equivalent circulating density.

Eq. (5) and Eq. (6) formulate empirical relationships that can predict pore pressure gradient based on sonic and resistivity logs.

$\begin{array}{cc}{P}_p={\sigma }_v-\left({\sigma }_v-P_n\right){\left(\frac{R}{R_n}\right)}^{1.2}& \left(5\right)\end{array}$ $\begin{array}{cc}{P}_p={\sigma }_v-\left({\sigma }_v-P_n\right){\left(\frac{\Delta T_n}{\Delta T}\right)}^3& \left(6\right)\end{array}$

where R is the shale resistivity obtained from well logs, R_n is the normal compaction trend of shale resistivity in Eq. (5), where in Eq. (6) ΔT_n is the shale transient time at normal pressure, and ΔT is sonic compressional transient time obtained from well logs.

These estimates are then used to update the normal compaction trendlines 606 calculated while drilling to produce updated trendlines 608 in an ongoing process ahead of the bottom hole assembly (column 603). In this example, the pore pressures are estimated in column 604, and a dynamic calibration is performed on certain parameters in a pore pressure equation to update to the updated trendlines 608 ahead of the bit.

The updated trendlines 608 shown here are directed to the normal compaction trendline (d_NCT), which are a function of pressures during the MPD operations (P_MPD), pressures from empirical calculations (P_emperical), overburden (vertical) stress (σ_v), and the drilling exponent (d_exp). Namely, the equation for the trendlines updated by the pore pressure estimates can be characterized as:

d _NCT =f(P_MPD,P_emperical,σ_v,d_exp).

As noted, managed pressure drilling (MPD) enables real time management of the annular pressure profile and accurate monitoring of the return flow through closed loop circulation system. The annular pressure profile is managed by manipulating the surface back pressure (SBP) using automated hydraulic chokes, operated by a programmable logic control. The return flow, temperature, and mud density are measured (e.g., by using a Coriolis flowmeter), and the standpipe pressure (SPP) and SBP are measured using precision digital sensors. The MPD operations using the process 300 of FIG. 3 enable repetitive dynamic formation integrity tests (DFIT) and dynamic pore pressure tests (DPPT) to be performed without the need to stop circulation. Dynamic FIT and PPT are performed to respectively confirm upper and lower boundaries 410, 420 of the downhole pressure envelope or drilling window 400 without causing down time.

In both tests, maintaining the full circulation rate enables the PWD tool to continue reading the downhole pressure, increasing the accuracy of the pore pressure and effective fracture pressure measurements. Continuous measurement of the downhole pressure using PWD minimizes the uncertainties inherent in the bottomhole pressure calculations caused by cutting loading and effect of pipe rotation.

FIG. 7A illustrates details of a form of dynamic pore pressure test (DPPT) operation used during the MPD operation to determine the lower (pore pressure) boundary of the dynamically determined drilling window. The surface backpressure is stepwise decreased by adjusting choke position to change the setpoint (middle graph 602). The flow rate of flow-in and flow-out are monitored (bottom graph 630). During the DPPT operation while drilling, the flow rate is changed, while the surface backpressure is stepwise decreased. The data eventually indicates when an imbalance occurs (i.e., a signature influx is detected). The bottomhole pressure is also monitored during the test.

As shown in (top graph 610), the BHP values (based on the PWD pressure and an estimated model pressure) are shown changing with the stepwise decrease of the surface back pressure. The pressure value 612 related to the pore pressure for the lower boundary of the dynamic drilling window is determined when the signature influx is detected by the imbalance of the flow rate. This pressure value is near the pore pressure of the formation, and the value is shown as 10800-psi in this example.

FIG. 7B illustrates details of the DPPT operation in a different graphical format. A stepwise decrease in surface backpressure (SBP) is shown in column 643 for the DPPT operation during drilling. Flow-in and flow-out are graphed (column 641) along with density-in and density-out (column 642). The stepwise decrease of the surface backpressure graphed in column 643 produces resulting changes for the standpipe pressure (column 644) and bottom hole pressures (column 645). The choke positions are also shown (column 646). The imbalance 647 between flow-in and flow out represents a signature kick at a data point 648 when the bottomhole pressure has reached (neared) the pore pressure of the formation to indicate a lower boundary of the dynamic drilling window as noted previously.

According to the process discussed previously with reference to FIGS. 3 and 4, the evaluated data point 648 in FIG. 7B is substituted back in the equations to calculate updated normal compaction trendlines for the type of data which is available. The updated normal compaction trendlines can then be used to estimate real measurements to determine the dynamic window for the current depth and depths ahead of bottom hole assembly.

The DPPT operation can be performed with or without pipe rotation pumping down the drill string, using the active system, with returns through the primary flow line of the system. As one example, the SBP in column 643 can be reduced in 30 psi decrements until a pressure level is reached in which flow out deviates from flow in by some defined difference. At the depth where the flow-out is greater than flow-in by the defined difference, bottoms up gas will be calculated. The bottom-up gas will then be used to track the time when the influx reaches the surface, subsequently the gas ratio and the SBP will be monitored. If the mentioned parameters are greater than the defined values for the corresponding formation, the pressure value is selected as a new pore pressure point for the dynamic drilling window. The DPPT operation can be implemented as an algorithm in the pressure control of the system. Correlation of the bottom-up gas after the connections, as well as monitoring of the rate of penetration and cutting analysis provide complimentary data for pore pressure interpretation.

The obtained pore pressure values via the DPPT operation are then used to back calculate the coefficients (which have been used in the addressed pore pressure estimation methods noted above) in column 604 of FIG. 6. In addition, an updated normal compaction trendline 608 as in FIG. 6 is back calculated from the real pore pressure evaluation. Therefore, using the current algorithm, the coefficient used in the available pore pressure prediction methods is calibrated, and any uncertainty in determining the accurate normal compaction trend line can be reduced.

FIG. 8A illustrates details of a form of dynamic fracture pressure test (DLOT) operation used during drilling to determine the upper (fracture pressure) boundary of the dynamically determined drilling window. The surface backpressure is stepwise increased by adjusting choke position to change the setpoint (middle graph 660). The flow rate of flow-in and flow-out are monitored (bottom graph 670). During the DLOT operation while drilling, the flow rate is increased, while the surface backpressure is stepwise increased. The data eventually indicates when an imbalance 672 occurs (i.e., a signature loss). The bottomhole pressure is also monitored during the DLOT operation. As shown in (top graph 650), the BHP values (based on the PWD pressure and an estimated model pressure) are shown changing with the stepwise increase of the surface back pressure. The pressure value 652 is determined when the signature loss 672 is detected by the imbalance of the flow rate. This pressure value 652 is near the fracture pressure of the formation, and the value is shown as 13200-psi in this example.

A DFIT operation is similar to the form of DLOT operation shown. In a DFIT operation, the surface backpressure is stepwise increased until a predetermined set point is reached while the return flow is continuously monitored. If a loss is observed, the pressure is unloaded and the downhole pressure where the micro-loss occurred provides a measurement of the leak-off pressure.

FIG. 8B illustrates details of a DLOT operation 680 in a different graphical format. A stepwise increase in SBP is shown in column 653 during DFIT/DLOT operation 680 during MPD operations. Flow-in and flow-out are graphed (column 681) along with density-in and density-out (column 682). The stepwise increase of the surface backpressure in column 683 produces resulting changes for the standpipe pressure (column 684) and bottom hole pressures (column 685). The choke positions are also shown in column 686. The imbalance between flow-in and flow out represents a signature loss 687 at a data point 688 when the bottomhole pressure has reached or neared the fracture pressure of the formation to indicate an upper boundary of the dynamic drilling window as noted previously.

According to the process discussed previously with reference to FIGS. 3 and 4, the evaluated data point 688 in FIG. 8B is substituted back in the equations to calculate updated normal compaction trendlines for the type of data which is available. The updated normal compaction trendlines can then be used to estimate real measurements to determine the dynamic window for the current depth and depths ahead of bottom hole assembly.

In addition to direct measurement of the pore pressure using the DPPT operation, the monitoring and correlation of the surface parameters, such as gas ratio, flow line pressure and density, provides qualitative indication of the formation pressure. Other than direct measurement of the pore and fracture pressures through the dynamic FIT and PPT operations, monitoring and correlation of the surface parameters provide qualitative indication of the pore pressure. The correlation of the bottoms-up gas after the connections, as well as monitoring of the rate of penetration and cutting analysis provide complimentary data for pore pressure interpretation.

According to the process discussed previously with reference to FIGS. 3 and 4, the evaluated data points 648 and 688 in FIGS. 7B and 8B are substituted back in the equations to calculate updated normal compaction trendlines 608 for the type of data which is available. The updated normal compaction trendlines 608 can then be used to estimate real measurements to determine the dynamic window for the current depth and depths ahead of bottom hole assembly.

FIGS. 9A-9B show a flowchart of an example process 700 according to the present disclosure. In some implementations, one or more process blocks of FIGS. 9A-9B may be performed by a processing unit 210, such as a programmable control device.

As shown in FIG. 9A, the process 700 includes calculating normal compaction trendlines for intervals of the wellbore to be drilled in the formation (block 702). For example, the processing unit 210 may calculate normal compaction trendlines (NCT) for intervals (408) of the wellbore (12) to be drilled in the formation, as described above. As also shown in FIG. 9A, the process 700 includes drilling the wellbore in a drilling operation using the closed-loop drilling system while monitoring inflow at the inlet (Block 704), monitoring outflow at the outlet (Block 706), and measuring surface backpressure at the outlet (block 708).

As further shown in FIG. 9A, the process 700 includes a number of repeated steps while drilling is performed in the drilling operation. The process 700 includes defining a dynamic drilling window for the interval of the wellbore being drilled in the formation by using the normal compaction trendline for the interval (Block 710); estimating a lower boundary of the dynamic drilling window by reducing the surface backpressure while simultaneously monitoring the inflow and the outflow until a signature influx is measured (Block 720); estimating an upper boundary of the dynamic drilling window by increasing the surface backpressure while simultaneously monitoring the inflow and the outflow until a signature loss is measured (Block 730); updating the normal compaction trendline for the interval in the formation ahead of the bottom hole assembly based on the estimated upper and lower boundaries (Block 740); and adjusting a parameter in the drilling operation to drill at a target bottom hole pressure within the dynamic drilling window (Block 750). These repeated steps can be performed by the processing unit 210 at repeated processing increments, which can depend on the rate of penetration, wellbore interval, sensing times, and other factors.

The process 700 may include additional implementations, such as any single implementation or any combination of implementations described below and/or in connection with one or more other processes described elsewhere herein. In a first implementation, the process 700 may include measuring a pressure-while-drilling (PWD) value indicative of a measured bottom hole pressure at the bottom hole assembly (Block 760). In this instance, the parameter adjusted in the drilling operation involves adjusting the surface backpressure in the drilling operation to bring the measured bottom hole pressure toward the target bottom hole pressure in the dynamic drilling window. To measure the PWD value, the step can include reading pressure values conducted at full circulation rate by using a Pressure While Drilling (PWD) tool on the bottom hole assembly while estimating the dynamic drilling window (Block 762).

In a second implementation, alone or in combination with the first and second implementation, the process 700 may include estimating a bottom hole pressure at the bottom hole assembly as an estimated bottom hole pressure (Block 770). In this instance, the parameter adjusted in the drilling operation involves adjusting the surface backpressure in the drilling operation to bring the estimated bottom hole pressure toward the target bottom hole pressure in the dynamic drilling window.

In a third implementation, alone or in combination with one or more of the first and second implementations, the step of estimating the lower boundary (Block 720) may include estimating a pore pressure gradient by determining, from the signature influx, a pressure value as an estimated pressure value indicative of the bottom hole pressure, at a current depth of the bottom hole assembly, being equal to or less than a pore pressure (Block 722). Likewise, the step of estimating the upper boundary (Block 730) may include estimating a formation pressure gradient by determining, from the signature loss, a pressure value indicative of the bottom hole pressure being equal to or greater than a fracture pressure (Block 732).

Although FIGS. 9A-9B show example blocks of the process 700, in some implementations, the process 700 may include additional blocks, fewer blocks, different blocks, or differently arranged blocks than those depicted in FIGS. 9A-9B. Additionally, or alternatively, two or more of the blocks of the process 700 may be performed in parallel.

The foregoing description of preferred and other embodiments is not intended to limit or restrict the scope or applicability of the inventive concepts conceived of by the Applicants. It will be appreciated with the benefit of the present disclosure that features described above in accordance with any aspect of the disclosed subject matter can be utilized, either alone or in combination, with any other described feature, in any other aspect of the disclosed subject matter.

As will be appreciated, teachings of the present disclosure can be implemented in digital electronic circuitry, computer hardware, computer firmware, computer software, programmable logic controller, or any combination thereof. Teachings of the present disclosure can be implemented in a programmable storage device (computer program product tangibly embodied in a machine-readable storage device) for execution by a programmable control device or processor (e.g., control system 200, processing unit 210, etc.) so that the programmable processor executing program instructions can perform functions of the present disclosure. The teachings of the present disclosure can be implemented advantageously in one or more computer programs that are executable on a programmable system (e.g., control system 200, processing unit 210, etc.) including at least one programmable processor coupled to receive data and instructions from, and to transmit data and instructions to, a data storage system (e.g., database or storage 220), at least one input device, and at least one output device. Storage devices suitable for tangibly embodying computer program instructions and data include all forms of non-volatile memory, including by way of example semiconductor memory devices, such as solid-state devices, EPROM, EEPROM, and flash memory devices; magnetic disks such as internal hard disks and removable disks; magneto-optical disks; and CD-ROM disks. Any of the foregoing can be supplemented by, or incorporated in, ASICs (application-specific integrated circuits).

The following table of abbreviations are used herein:

Abbreviation Definition
AP           Annular Pressure
BHA          Bottom Hole Assembly
BHP          Bottom Hole Pressure
BOP          Blow out preventer
CBHP         Constant BHP
F            Formation
FP           Fracture Pressure
HPU          Hydraulic Power Unit
LCM          Lost Circulation Material
NCT          normal compaction trend
MPD          Managed Pressure Drilling
PP           Pore Pressure
DPPT         Dynamic pore pressure test
PWD          Pressure-while-Drilling
RCD          Rotating Control Device
ROP          Rate of Penetration
RPM          Rotations per Minute
SBP          surface back-pressure
SPP          Stand-Pipe pressure
TD           Total Depth
UBD          Underbalanced Drilling
σν           overburden stress
UMRP         Upper Marine Riser Package

The teachings of the present disclosure can be characterized by the following clauses:

Clause 1: A method, implemented by a computerized control, for a closed-loop drilling system (10), the closed-loop drilling system (10) having: a bottom hole assembly (16) for drilling a wellbore (12) in a formation (F), at least one pump (150) for pumping drilling fluid at an inlet (11i), and at least one choke (122a-b) for choking the drilling fluid at an outlet (110), the method comprising:

• • calculating normal compaction trendlines (NCT) for intervals of the wellbore (12) to be drilled in the formation (F);
  • drilling the wellbore (12) in a drilling operation using the closed-loop drilling system (10) while monitoring inflow at the inlet (11i), monitoring outflow at the outlet (110), and measuring surface backpressure (SBP) at the outlet (110); and
  • while drilling in the drilling operation, repeatedly: defining a dynamic drilling window (400) for the interval of the wellbore (12) being drilled in the formation (F) by using the normal compaction trendline for the interval; estimating a lower boundary (410) for the interval of the dynamic drilling window (400) as an estimated lower boundary (410) by reducing the surface backpressure (SBP) while simultaneously monitoring the inflow and the outflow until a signature influx (647, 648) is measured; estimating an upper boundary (420) for the interval of the dynamic drilling window (400) as an estimated upper boundary (420) by increasing the surface backpressure (SBP) while simultaneously monitoring the inflow and the outflow until a signature loss (687, 688) is measured; updating the normal compaction trendline (NCT) for the interval in the formation (F) ahead of the bottom hole assembly (16) based on the estimated upper and lower boundaries (410, 420); and adjusting a parameter in the drilling operation to drill at a target bottom hole pressure (BHP) within the dynamic drilling window (400).

Clause 2: The method of Clause 1, wherein reducing the surface backpressure (SBP) comprises stepwise or incrementally reducing the surface backpressure (SBP); and wherein increasing the surface backpressure (SBP) comprises stepwise or incrementally increasing the surface backpressure (SBP).

Clause 3: The method of Clause 1 or 2, wherein drilling the wellbore (12) in the drilling operation comprises using a hydraulics model of the closed-loop drilling system (10) drilling the wellbore (12), optionally wherein using the hydraulics model (224) of the closed-loop drilling system (10) drilling the wellbore (12) comprises using one or more of: a trajectory of the wellbore (12), a measured depth of the wellbore (12), an inclination of the wellbore (12), an azimuth of the wellbore (12), a geometric parameter of the closed-loop drilling system (10), a geometry of an annulus of the wellbore (12), a geometry of a drillstring (14), a fluid property of the drilling fluid, a density of the drilling fluid, a rheology of the drilling fluid, a thermal property for the drilling fluid, a property of the formation (F), a thermal property of the drillstring (14), a temperature of the formation (F) in the wellbore (12), an empirical formula for local pressure loss from a component of the closed-loop drilling system (10), operational data obtained during drilling, flow rate, rotation rate (RPM), bit depth, and fluid input temperature.

Clause 4: The method of any one of Clauses 1, 2 or 3, wherein measuring the surface backpressure (SBP) at the outlet (110) comprises measuring a value of the surface backpressure (SBP) with a sensor (240) disposed upstream of the at least one choke (122a-b), optionally wherein the sensor (240) is selected from the group consisting of a pressure transducer, a pressure gauge, a diaphragm-based pressure transducer, and a strain gauge-based pressure transducer, an analog device, and an electronic device.

Clause 5: The method of any one of Clauses 1 to 4, further comprising measuring a pressure-while-drilling value indicative of a measured bottom hole pressure at the bottom hole assembly (16); and wherein adjusting the parameter in the drilling operation comprising adjusting the surface backpressure (SBP) in the drilling operation to bring the measured bottom hole pressure toward the target bottom hole pressure (BHP) in the dynamic drilling window (400), optionally wherein measuring the pressure-while-drilling value comprises reading pressure values conducted at full circulation rate by using a Pressure While Drilling (PWD) tool or sensor (260) on the bottom hole assembly (16) while estimating the dynamic drilling window (400).

Clause 6: The method of any one of Clauses 1 to 5, further comprising estimating a bottom hole pressure (BHP) at the bottom hole assembly (16) as an estimated bottom hole pressure; and wherein adjusting the parameter in the drilling operation comprising adjusting the surface backpressure (SBP) in the drilling operation to bring the estimated bottom hole pressure toward the target bottom hole pressure (BHP) in the dynamic drilling window (400).

Clause 7: The method of any one of Clauses 1 to 6, wherein estimating the lower boundary (410) comprises estimating a pore pressure gradient by determining, from the signature influx (647, 648), a pressure value as an estimated pressure value indicative of a current bottom hole pressure (BHP), at a current depth of the bottom hole assembly (16), being equal to or less than a pore pressure, optionally wherein estimating the lower boundary (410) further comprises correlating monitored surface parameters including gas-at-surface, flowline pressure, and difference in the inflow and the outflow to evaluate the pore pressure at the current depth.

Clause 8: The method of Clause 7, wherein updating the normal compaction trendline (NCT) for the formation (F) ahead of the bottom hole assembly (16) comprises substituting at least the estimated pressure value indicative of the pore pressure back into a calculation of the normal compaction trendline (NCT) as a function of a measured pressure variable in the closed-loop drilling system (10), an empirical pressure variable for the closed-loop drilling system (10), an overburden stress variable, and a drilling exponent variable.

Clause 9: The method of any one of Clauses 1 to 8, wherein calculating the normal compaction trendline (NCT) comprises using a calculation of the normal compaction trendline (NCT) as a function of measured pressures in the closed-loop drilling system (10), empirical pressures, overburden stress, and drilling exponent.

Clause 10: The method of any one of Clauses 1 to 9, wherein estimating the upper boundary (420) comprises estimating a formation pressure gradient by determining, from the signature loss (687, 688), a pressure value indicative of a current bottom hole pressure (BHP) being equal to or greater than a fracture pressure.

Clause 11: The method of any one of Clauses 1 to 10, wherein to adjust the parameter in the drilling operation, the method comprises adjusting the at least one choke (122a-b) in communication with the drilling fluid from the wellbore (12); and/or wherein adjusting the parameter in the drilling operation comprises adjusting at least one of: a flow rate of the drilling fluid out of the wellbore (12) using the at least one choke (122a-b), a pressure of flow of the drilling fluid out of the wellbore (12) using the at least one choke (122a-b), a current value of the surface backpressure (SBP) in the wellbore (12), a mass flow rate of the drilling fluid out of the wellbore (12), a pressure during make-up of a drillpipe connection while drilling with the closed-loop drilling system (10), a pressure during a loss detected while drilling with the closed-loop drilling system (10), or a flow rate during a kick detected while drilling with the closed-loop drilling system (10).

Clause 12: The method of any one of Clauses 1 to 11, further comprising determining an imbalance (647, 687) between the outflow and the inflow as a determined imbalance, wherein adjusting the parameter in the drilling operation is based on the determined imbalance.

Clause 13: The method of any one of Clauses 1 to 12, wherein measuring the outflow of the drilling fluid from the wellbore (12) comprise measuring the outflow with a flowmeter (124) in communication with the outflow; and wherein measuring the inflow of the drilling fluid into the wellbore (12) comprise measuring the inflow with a flowmeter (166a-b) in communication with the inflow.

Clause 14: A programmable storage device having program instructions stored thereon for causing a programmable control device (210) to perform a method of drilling a wellbore (12) with drilling fluid using a drilling system (10) according to any one of Clauses 1 to 13.

Clause 15: A drilling system (10) for drilling a wellbore (12) in a formation with drilling fluid, the drilling system (10) comprising: at least one pump (150) disposed at an inlet (11i) of the drilling system (10) and operable to pump the drilling fluid into the wellbore (12) when drilling the wellbore (12) with the drilling system (10); at least one choke (122a-b) disposed at an outlet (110) of the drilling system (10) and operable to adjust flow of the drilling fluid from the wellbore (12) when drilling the wellbore (12) with the drilling system (10); storage (220) storing a hydraulics model (224) of the drilling system (10) drilling the wellbore (12); a first sensor (240) configured to measure a value of surface backpressure (SBP) upstream of the at least one choke (122a-b); and a programmable control device (210) communicatively coupled to the storage (220) and the first sensor (240), the programmable control device (210) being configured to perform a method according to any one of Clauses 1 to 13.

The foregoing description of preferred and other embodiments is not intended to limit or restrict the scope or applicability of the inventive concepts conceived of by the Applicants. It will be appreciated with the benefit of the present disclosure that features described above in accordance with any embodiment or aspect of the disclosed subject matter can be utilized, either alone or in combination, with any other described feature, in any other embodiment or aspect of the disclosed subject matter.

In exchange for disclosing the inventive concepts contained herein, the Applicants desire all patent rights afforded by the appended claims. Therefore, it is intended that the appended claims include all modifications and alterations to the full extent that they come within the scope of the following claims or the equivalents thereof.

Claims

1. A method, implemented by a computerized control, for a closed-loop drilling system, the closed-loop drilling system having: a bottom hole assembly for drilling a wellbore in a formation, at least one pump for pumping drilling fluid at an inlet, and at least one choke for choking the drilling fluid at an outlet, the method comprising: calculating normal compaction trendlines for intervals of the wellbore to be drilled in the formation;drilling the wellbore in a drilling operation using the closed-loop drilling system while monitoring inflow at the inlet, monitoring outflow at the outlet, and measuring surface backpressure at the outlet; andwhile drilling in the drilling operation, repeatedly: defining a dynamic drilling window for the interval of the wellbore being drilled in the formation by using the normal compaction trendline for the interval;estimating a lower boundary for the interval of the dynamic drilling window as an estimated lower boundary by reducing the surface backpressure while simultaneously monitoring the inflow and the outflow until a signature influx is measured;estimating an upper boundary for the interval of the dynamic drilling window as an estimated upper boundary by increasing the surface backpressure while simultaneously monitoring the inflow and the outflow until a signature loss is measured;updating the normal compaction trendline for the interval in the formation ahead of the bottom hole assembly based on the estimated upper and lower boundaries; andadjusting a parameter in the drilling operation to drill at a target bottom hole pressure within the dynamic drilling window.

2. The method of claim 1, wherein reducing the surface backpressure comprises stepwise or incrementally reducing the surface backpressure; and wherein increasing the surface backpressure comprises stepwise or incrementally increasing the surface backpressure.

3. The method of claim 1, wherein drilling the wellbore in the drilling operation comprises using a hydraulics model of the closed-loop drilling system drilling the wellbore.

4. The method of claim 3, wherein using the hydraulics model of the closed-loop drilling system drilling the wellbore comprises using one or more of: a trajectory of the wellbore, a measured depth of the wellbore, an inclination of the wellbore, an azimuth of the wellbore, a geometric parameter of the closed-loop drilling system, a geometry of an annulus of the wellbore, a geometry of a drillstring, a fluid property of the drilling fluid, a density of the drilling fluid, a rheology of the drilling fluid, a thermal property for the drilling fluid, a property of the formation, a thermal property of the drillstring, a temperature of the formation in the wellbore, an empirical formula for local pressure loss from a component of the closed-loop drilling system, operational data obtained during drilling, flow rate, rotation rate (RPM), bit depth, and fluid input temperature.

5. The method of claim 1, wherein measuring the surface backpressure at the outlet comprises measuring a value of the surface backpressure with a sensor disposed upstream of the at least one choke.

6. The method of claim 5, wherein the sensor is selected from the group consisting of a pressure transducer, a pressure gauge, a diaphragm-based pressure transducer, and a strain gauge-based pressure transducer, an analog device, and an electronic device.

7. The method of claim 1, further comprising measuring a pressure-while-drilling value indicative of a measured bottom hole pressure at the bottom hole assembly; and wherein adjusting the parameter in the drilling operation comprising adjusting the surface backpressure in the drilling operation to bring the measured bottom hole pressure toward the target bottom hole pressure in the dynamic drilling window.

8. The method of claim 7, wherein measuring the pressure-while-drilling value comprises reading pressure values conducted at full circulation rate by using a Pressure While Drilling (PWD) tool on the bottom hole assembly while estimating the dynamic drilling window.

9. The method of claim 1, further comprising estimating a bottom hole pressure at the bottom hole assembly as an estimated bottom hole pressure; and wherein adjusting the parameter in the drilling operation comprising adjusting the surface backpressure in the drilling operation to bring the estimated bottom hole pressure toward the target bottom hole pressure in the dynamic drilling window.

10. The method of claim 1, wherein estimating the lower boundary comprises estimating a pore pressure gradient by determining, from the signature influx, a pressure value as an estimated pressure value indicative of a current bottom hole pressure, at a current depth of the bottom hole assembly, being equal to or less than a pore pressure.

11. The method of claim 10, wherein estimating the lower boundary further comprises correlating monitored surface parameters including gas-at-surface, flowline pressure, and difference in the inflow and the outflow to evaluate the pore pressure at the current depth.

12. The method of claim 10, wherein updating the normal compaction trendline for the formation ahead of the bottom hole assembly comprises substituting at least the estimated pressure value indicative of the pore pressure back into a calculation of the normal compaction trendline as a function of a measured pressure variable in the closed-loop drilling system, an empirical pressure variable for the closed-loop drilling system, an overburden stress variable, and a drilling exponent variable.

13. The method of claim 1, wherein calculating the normal compaction trendline comprises using a calculation of the normal compaction trendline as a function of measured pressures in the closed-loop drilling system, empirical pressures, overburden stress, and drilling exponent.

14. The method of claim 1, wherein estimating the upper boundary comprises estimating a formation pressure gradient by determining, from the signature loss, a pressure value indicative of a current bottom hole pressure being equal to or greater than a fracture pressure.

15. The method of claim 1, wherein to adjust the parameter in the drilling operation, the method comprises adjusting the at least one choke in communication with the drilling fluid from the wellbore.

16. The method of claim 1, wherein adjusting the parameter in the drilling operation comprises adjusting at least one of: a flow rate of the drilling fluid out of the wellbore using the at least one choke, a pressure of flow of the drilling fluid out of the wellbore using the at least one choke, a current value of the surface backpressure in the wellbore, a mass flow rate of the drilling fluid out of the wellbore, a pressure during make-up of a drillpipe connection while drilling with the closed-loop drilling system, a pressure during a loss detected while drilling with the closed-loop drilling system, or a flow rate during a kick detected while drilling with the closed-loop drilling system.

17. The method of claim 1, further comprising determining an imbalance between the outflow and the inflow as a determined imbalance, wherein adjusting the parameter in the drilling operation is based on the determined imbalance.

18. The method of claim 1, wherein measuring the outflow of the drilling fluid from the wellbore comprise measuring the outflow with a flowmeter in communication with the outflow; and wherein measuring the inflow of the drilling fluid into the wellbore comprise measuring the inflow with a flowmeter in communication with the inflow.

19. A programmable storage device having program instructions stored thereon for causing a programmable control device to perform a method of drilling a wellbore with drilling fluid using a drilling system according to claim 1.

20. A drilling system for drilling a wellbore in a formation with drilling fluid, the drilling system comprising: at least one pump disposed at an inlet of the drilling system and operable to pump the drilling fluid into the wellbore when drilling the wellbore with the drilling system;at least one choke disposed at an outlet of the drilling system and operable to adjust flow of the drilling fluid from the wellbore when drilling the wellbore with the drilling system;storage storing a hydraulics model of the drilling system drilling the wellbore;a sensor configured to measure a value of surface backpressure upstream of the at least one choke; anda programmable control device communicatively coupled to the storage and the sensor, the programmable control device being configured to: calculate normal compaction trendlines for intervals of the wellbore to be drilled in the formation;monitor inflow at the inlet, outflow at the outlet, and the value of the surface backpressure during drilling of the wellbore in a drilling operation using the drilling system; andwhile drilling in the drilling operation, repeatedly: define a dynamic drilling window for the interval of the wellbore being drilled in the formation by using the normal compaction trendline for the interval;estimate a lower boundary for the interval of the dynamic drilling window as an estimated lower boundary by reducing the surface backpressure while simultaneously monitoring the inflow and the outflow until a signature influx is measured;estimate an upper boundary for the interval of the dynamic drilling window as an estimated upper boundary by increasing the surface backpressure while simultaneously monitoring the inflow and the outflow until a signature loss is measured;update the normal compaction trendline for the interval in the formation ahead of a bottom hole assembly based on the estimated upper and lower boundaries; andadjust a parameter in the drilling operation to drill at a target bottom hole pressure within the dynamic drilling window.