System and Method for Drilling using Pore Pressure

Abstract

A system and method for drilling a borehole in a subsurface formation. A method includes rotating a drill bit to remove formation material from the subsurface formation at an end of the borehole. A value of mechanical specific energy applied to remove the formation material is calculated. A value of drilling efficiency is calculated based on the value of mechanical specific energy. Pore pressure of the subsurface formation in contact with the drill bit is calculated as a function of calculated drilling efficiency. Real-time operational decisions (such as adjusting density of drilling fluid or determining the final depth of the hole section) are made based on calculated pore pressure of the subsurface formation.

Description

CROSS REFERENCE TO RELATED APPLICATIONS

This application is a non-provisional application claiming priority to U.S. provisional application Ser. No. 62/147,252, filed on Apr. 14, 2015, entitled “System and Method for Drilling using Pore Pressure,” the entire disclosure of which is incorporated by reference herein.

BACKGROUND

Some subterranean formations are porous, containing fluid such as water, gas, or crude oil within the pores. The fluid within the formations is at a certain pressure termed the pore pressure. The pore pressure supports part of the weight of the overburden (weight of the overlying rock matrix and pore fluid), while the other part is supported by the grains of the rock. The terms formation pore pressure, formation pressure and fluid pressure are synonymous, referring to pore pressure.

To obtain hydrocarbons, such as oil and gas, boreholes are drilled into the subterranean formations. Pore pressure may be measured during the drilling operations. For example, pore pressure may be directly measured by sampling fluid from the formation using a downhole tool in contact with the borehole wall. Pore pressure measurements can be applied while drilling in the context of well control, in implementation of completion processes, and/or in reservoir development.

BRIEF DESCRIPTION OF THE DRAWINGS

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

FIG. 1 shows a system for drilling a borehole that calculates and applies pore pressure of the formation being drilled based on measurements made at the bit in accordance with an embodiment disclosed herein;

FIG. 2 shows a block diagram of a drilling control system that determines formation pore pressure based on mechanical specific energy (MSE) and controls drilling operations based on the determined formation pore pressure in accordance with an embodiment disclosed herein;

FIG. 3 shows a block diagram of a pore pressure calculator that can be used while drilling to determine formation pore pressure based on mechanical specific energy (MSE) in accordance with an embodiment disclosed herein;

FIG. 4 shows a flow diagram for a drilling control method that determines pore pressure of a formation based on MSE and drilling efficiency and controls drilling operations based on the determined pore pressure in accordance with an embodiment disclosed herein;

FIG. 5 shows an example of pore pressure determined using conventional methods and pore pressure established based on MSE in accordance with an embodiment disclosed herein; and

FIG. 6 shows an example of pore pressure determined using conventional d-exponent methods and pore pressure established based on MSE in accordance with an embodiment disclosed herein.

NOTATION AND NOMENCLATURE

In the following discussion and in the claims, the terms “including” and “comprising” are used in an open-ended fashion, and thus should be interpreted to mean “including, but not limited to . . . ”. The term “couple” is not meant to limit the interaction between elements to direct interaction between the elements and may also include indirect interaction between the elements described. The term “software” includes any executable code capable of running on a processor, regardless of the media used to store the software. Thus, code stored in memory (e.g., non-volatile memory), and sometimes referred to as “embedded firmware,” is included within the definition of software. The recitation “based on” is intended to mean “based at least in part on.” Therefore, if X is based on Y, X may be based on Y and any number of additional factors.

DETAILED DESCRIPTION

When drilling a borehole, the rate of formation penetration is affected by the difference in formation pore pressure and hydrostatic pressure exerted by the drilling fluid in the borehole. Accordingly, adjustments based on pore pressure measurements can be applied to improve drilling efficiency. Some conventional pore pressure computations apply the “d-exponent” or “corrected d-exponent” method to estimate pore pressure based on a relationship between d-exponent and a normal trendline of the d-exponent. Unfortunately, the empirical nature of the d-exponent method and the loose definition of the d-exponent normal trendline limit the method's predictive capabilities. There is a need and a desire for an alternative pore pressure computation method that is faster, performed in real time, more robust, more efficient, and more reliable than known methods. There is also a need for application of the pore pressure computations to drilling wells for recovery of hydrocarbons.

Embodiments of the present disclosure include an alternative to the d-exponent based pore pressure estimation methods. At least some embodiments of the pore pressure determination techniques disclosed herein exclude d-exponent computation. The pore pressure measurement techniques disclosed herein calculate pore pressure from drilling mechanical specific energy (MSE) and drilling efficiency trends using a combination of downhole drilling mechanics parameters and subsurface rock and stress data. Embodiments can compute formation pore pressure at the bit in real-time while drilling, and accordingly, can provide an advantage over conventional log-based methods. For example, in borehole sections where operational decisions are made based on pore pressure conditions at the bottom of the borehole, embodiments apply drilling parameters measured at the bit to provide important information that logging while drilling (LWD) measurements taken behind the bit (further up the bottom hole assembly (BHA) where LWD resistivity and sonic measurements are commonly taken) cannot provide. Furthermore, the pore pressure determination techniques disclosed herein provide pore pressure values much earlier than conventional methods because, using the techniques disclosed herein, the pressure values are provided for the formation material at the bit rather than at a tool some distance uphole of the bit. As a result, drilling decisions can be made, and appropriate drilling control applied, much earlier (e.g., 1-1.5 hours or more earlier) than when pressure measurement techniques based on tools uphole of the bit are applied. By allowing more timely control of the drilling process, embodiments of the pore pressure determination method disclosed herein can reduce unnecessary drilling and more accurately identify drilling targets.

According to an embodiment, FIG. 1 shows a schematic diagram of a system for drilling a borehole that calculates and applies pore pressure of the formation being drilled based on measurements made at the bit in accordance with principles disclosed herein. The drilling system 100 includes a derrick 104 supported by a drilling platform 102. The derrick 104 includes a floor 103 and a traveling block 106 for raising and lowering a drill string 108. The derrick supports a rotary table 112 that is rotated by a prime mover such as an electric motor controlled by a motor controller. A kelly 110 supports the drill string 108 as it is lowered through the rotary table 112.

The drill string 108 extends downward through the rotary table 112, and is made up of various components, including drill pipe 118 and components of the bottom hole assembly (BHA) 142 (e.g., bit 114, mud motor, drill collar, tools, etc.). The drill bit 114 is attached to the lower end of the drill string 108. The drill bit 114 disintegrates the subsurface formations 126 when it is rotated with weight-on-bit to drill the borehole 116. The weight-on-bit, which impacts the rate of penetration of the bit 114 through the formations 126, is controlled by a drawworks 136. In some embodiments of the drilling system 100, a top drive may be used to rotate the drill string 108 rather than rotation by the rotary table 112 and the kelly 110. In some applications, a downhole motor (mud motor) is disposed in the drilling string 108 to rotate the drill bit 114 in lieu of or in addition to rotating the drill string 108 from the surface. The mud motor rotates the drill bit 114 when drilling fluid passes through the mud motor under pressure. The rate of penetration (ROP) of the drill bit 114 into the borehole 116 for a given formation is dependent on weight-on-bit, drill bit rotational speed, and other factors.

As indicated above, during drilling operations a suitable drilling fluid 138 from a mud tank 124 is circulated under pressure through the drill string 108 by a mud pump 120. The drilling fluid 138 passes from the mud pump 120 into the drill string 108 via fluid line 122 and the kelly 110. The drilling fluid 138 is discharged at the borehole bottom through nozzles in the drill bit 114. The drilling fluid 138 circulates to the surface through the annular space 140 between the drill string 108 and the sidewall of borehole 116, and returns to the mud tank 124 via a solids control system (not shown) and a return line 142. The drilling fluid 138 transports cuttings from the borehole 116 into the reservoir 124 and aids in maintaining borehole integrity. The solids control system separates the cuttings from the drilling fluid 138, and may include shale shakers, centrifuges, and automated chemical additive systems. The density of the drilling fluid 138 may be adjusted based on the pore pressure of the formations 126.

Various sensors are employed in drilling system 100 for monitoring a variety of surface-controlled drilling parameters and downhole conditions. For example, a sensor disposed in the fluid line 122 measures and provides information about the drilling fluid flow rate and pressure. A surface torque sensor and a rotational speed sensor associated with the drill string 108 measure and provide information about the torque applied to the drill string 108 and the rotational speed of the drill string 108, respectively. Additionally, a sensor associated with traveling block 106 may be used to measure and provide the hook load of the drill string 108. Additional sensors are associated with the motor drive system to monitor proper drive system operation. These include, but are not limited to, sensors for detecting such parameters as motor speed (RPM), winding voltage, winding resistance, motor current, and motor temperature. Other sensors are used to indicate operation and control of the various solids control equipment.

The BHA 142 may also include a measurement-while-drilling and/or a logging-while-drilling assembly containing sensors for measuring drilling dynamics, drilling direction, formation parameters, downhole conditions, etc. Outputs of the sensors may be transmitted to the surface using any suitable downhole telemetry technology known in the art (e.g., wired drill pipe, mud pulse, etc.).

Because the sensors disposed in the BHA 142 are located at a substantial distance (e.g. 10-15 meters or more) from the drill bit 114, measurement data provided from the BHA may not accurately represent conditions at the drill bit 114. For a given borehole location, measurements made at the BHA 142 may be substantially delayed relative to the time which the drill bit 114 was at the given borehole location. Such measurement delay may cause corresponding undesirable delay in control of the drilling parameters. For example, if drilling is to be halted at a particular borehole location or when specified conditions are present at the drill bit 114, sensors in the BHA 142 may not identify the particular location or conditions until the drill bit 114 has advanced well past the location. To overcome the delays imposed by sensors in the BHA 142, additional sensors may be included in or at the drill bit 114 to provide measurements of formation parameters, drilling parameters, etc. at the drill bit 114. For example, a torque sensor located at the drill bit 114 may measure torque applied at the drill bit 114 to remove material at the end of the borehole 116. Similarly, a sensor located at the drill bit 114 may measure weight on the drill bit 114. Additional sensors at the drill bit 114 may measure formation parameters or other parameters of interest.

Outputs from the various sensors are provided to a drilling control system 128 via a connection 132 that may be wired or wireless. The drilling control system 128 controls the various parameters of the drilling process ((e.g., applied torque and rotational speed of the drill string, the axial position and speed of the drill string, weight-on-bit, the density, pressure, and/or flow rate of the drilling fluid, etc.). For example, the drilling control system 128 may control the drawworks 138, a prime mover, a top drive, the mud pump 120 etc.

The drilling control system 128 processes the sensor outputs to evaluate and control the drilling process. The drilling control system 128 includes a pore pressure calculator 144. The pore pressure calculator 144 computes the pore pressure of the formations 126 at the drill bit 114 based on MSE determined from drilling parameters measured at the drill bit 114. Because the pore pressure values computed by the pore pressure calculator 144 are provided significantly earlier than pore pressure values derived from BHA measurements, the drilling control system 128 can provide more accurate and timely control of drilling than conventional drilling systems.

The pore pressure calculator 144 computes MSE while drilling. MSE is a measure of drilling performance, and can be defined as the work required to pulverize a unit volume of rock with the drill bit 114. MSE is related to the drilling parameters torque, rotary speed, weight on bit, and rate of penetration, all of which may be recorded during a drilling operation. MSE, which has the units of pressure (pounds per square inch (psi) or megapascal (MPa)), can be computed as:

$\begin{array}{cc}\mathrm{MSE}=\frac{480\times T\times \mathrm{RPM}}{d^2\times \mathrm{ROP}}=\frac{4\times \mathrm{WOB}}{\pi d^2}& \left(1\right)\end{array}$

where:
T is torque;
RPM is revolutions per minute;
ROP is rate of penetration;
WOB is weight on bit; and
d is borehole diameter.

Embodiments of the pore pressure calculator 144 can use MSE to establish pore pressure because the stress state of rocks in the subsurface is determined in part by the pressure of the fluid contained in the rock pores. Therefore, pore pressure is a determining factor for the energy required to break the rock of formations 126 with drill bit 114.

MSE can be used to assess the efficiency of rotary drilling by monitoring the amount of mechanical energy being put into the system 100 during drilling and comparing it with rock strength at depth. Drilling efficiency (DE) is defined as the ratio of the rock's confined compressive strength (CCS) to the MSE, which is a measure of energy required to energy spent to break the rock with the bit 114 under in-situ conditions.

$\begin{array}{cc}\mathrm{DE}=\frac{\mathrm{CCS}}{\mathrm{MSE}}& \left(2\right)\end{array}$

Rock strength typically increases with depth as the rock compacts and supporting confining compressive stresses increase. CCS accounts for both unconfined compressive strength (UCS) and change in rock strength due to the confining stresses applied on the rock during drilling. CCS can be calculated from UCS for a given confining stress as follows:

$\begin{array}{cc}\mathrm{CCS}=\mathrm{UCS}+\Delta p\left(\frac{1+\sin \theta }{1-\sin \theta }\right),& \left(3\right)\end{array}$

where θ is the angle of internal friction. Both UCS and θ can be derived from acoustic log correlations. Empirical relationships between UCS, friction angle, and compressional velocity for Gulf of Mexico Miocene and Pliocene shales may be computed as:

UCS=0.43V_p^3.2, and

θ=1.532V_p^0.5148  (4)

In the borehole 116, for the rock immediately below the cutters of the drill bit 114, the confining stress is considered to be differential pressure, Δp, which is defined as the difference between the wellbore pressure (the equivalent circulating density, ECD) and the formation pore pressure. Because drilling bit performance is affected by differential pressure, improved drilling performance can be expected when differential pressure decreases. For instance, during underbalance drilling, drilling performance generally improves as either pore pressure increases, or ECD is held low relative to pore pressure. For substantially impermeable shales, the pore pressure that influences drilling response at the instant of drilling is the local pressure at the depth of cut zone, which may be perturbed relative to the far-field pore pressure. Immediately below the bit, during deformation, the formation expands slightly and pore pressure may be instantaneously decreased by a stress perturbation from the far field stress. Skempton's theory can be applied to correct for this stress induced pore pressure:

p_Skempton=pp−α(OBG−ECD),  (5)

where OBG is overburden pressure/stress.

The permeability correction factor, α, is ⅓ for totally impermeable rock. For most rocks, α can be correlated to porosity in a linear or non-linear fashion. The following permeability correction factor correlations with porosity may be applied:

α=⅓(1−2φ), or  (6)

α=⅓(1−4φ²).  (7)

MSE and bit performance, are influenced by differential pressure, Δp, because the energy required to break the rock depends on Δp. However, under optimum drilling conditions, drilling efficiency (Eq. (2)), may not change significantly if differential pressure does not change. The response of drilling efficiency to differential pressure for similar lithology indicates that DE can be utilized for pore pressure estimation.

Pore pressure can be estimated from log data by utilizing a comparison between a measured value such as sonic slowness or resistivity, and an estimate of what that value should be under normal pressure conditions—a value referred to as the normal compaction trendline. In contrast, embodiments of the pore pressure calculator 144 apply DE and MSE to compute pore pressure.

DE is a function of CCS as shown in equation (2), and CCS is a function of pore pressure as shown in equation (3). Because pore pressure is unknown, and confined compressive strength cannot be computed without knowing pore pressure, embodiments of the pore pressure calculator 144 calculate a pseudo drilling efficiency (DE_p) for pore pressure estimation as follows:

$\begin{array}{cc}{\mathrm{DE}}_p=\frac{{\mathrm{CCS}}_n}{\mathrm{MSE}}& \left(8\right)\end{array}$

where CCS_n is the confined compressive strength assuming normal pressure conditions.

For pore pressure calculation, the pore pressure calculator 144 compares DE_p against a normal drilling efficiency trendline (DE_trend), which can be calculated from a normal compaction trend porosity by using a power function such as:

DE_trend=aφ_n^b  (10)

where:
a is the coefficient of drilling trendline from porosity trendline;
φ_n is normal compaction trend porosity; and
b is exponent of drilling efficiency trend line from porosity trendline.

FIG. 5 shows an example of a drilling efficiency trendline 502 and pseudo drilling efficiency values 504.

The coefficients a and b in this trendline model can be derived using calibration pressure data from offset wells 134. An advantage of a drilling efficiency trendline based on porosity is that the same porosity trendline models which are used in sonic and resistivity based pressure estimation methods can be used for the drilling efficiency approach.

Some embodiments of the pore pressure calculator 144 apply the pseudo drilling efficiency and drilling efficiency trendline to compute pore pressure as follows:

$\begin{array}{cc}p=p_n+\Delta \mathrm{DE}\times \mathrm{MSE}\times \left(\frac{1-\sin \theta }{1+\sin \theta }\right)\mathrm{where}& \left(11\right)\\ \Delta \mathrm{DE}={\mathrm{DE}}_p-{\mathrm{DE}}_{\mathrm{trend}}& \left(12\right)\end{array}$

In addition to being used to calculate ΔDE, the pore pressure calculator 144 applies MSE to calculate pore pressure in equation (11). Some embodiments apply an alternative to equation 11, which directly applies MSE to compute pore pressure, as shown in equation (13).

$\begin{array}{cc}p=\mathrm{ECD}-\left({\mathrm{DE}}_{\mathrm{trend}}\times \mathrm{MSE}-\mathrm{UCS}\right)\times \left(\frac{1-\sin \theta }{1+\sin \theta }\right)& \left(13\right)\end{array}$

While the system 100 is illustrated with reference to an onshore well and drilling system, embodiments of the system 100 are also applicable to offshore wells. In such embodiments, the drill string 108 may extend from a surface platform through a riser assembly, a subsea blowout preventer, and a subsea wellhead into the subsea formations.

FIG. 2 shows a block diagram of the drilling control system 128. The drilling control system 128 includes a processor 202, a display device 204, and program/data storage 208. The processor 202 is also coupled to the various sensors 216 and actuators 228 of the drilling system 100, and to the stored offset well drilling data 206. In some embodiments of the drilling control system 128, the processor 202 and program/data storage 208 may be embodied in computer, such as a desktop computer, notebook computer, a blade computer, a server computer, or other suitable computing device known in the art.

The actuators 228 include mechanisms and/or interfaces that are controlled by the processor 202 to affect drilling operations. For example, the processor 202 may control rotation speed of the drill string 108 by controlling an electric motor through a motor controller, or may similarly control weight-on-bit by controlling a motor in the drawworks 136. Various other types of actuators controlled by the processor 202 include solenoids, telemetry transmitters, valves, etc.

The display 204 includes one or more display devices used to convey information to a drilling operator or other user. The display 204 may be implemented using one or more display technologies known in that art, such as liquid crystal, cathode ray, plasma, organic light emitting diode, vacuum fluorescent, electroluminescent, electronic paper, or other display technology suitable for providing information to a user.

The sensors 216 are coupled to the processor 202, and, as discussed above, include sensors for measuring various drilling system operation parameters used by the processor 202 to compute pore pressure of the formations being drilled. Weight-on-bit sensors (e.g., a strain gauges) coupled to the traveling block 106 or disposed in the BHA 142 or the drill bit 114 measure the portion of the weight of the drill string 108 applied to the drill bit 114. Torque sensors (e.g., strain gauges) coupled to the drill string 108 (e.g., at the drill bit 114) measure the torque applied to the drill bit 114. Rate of penetration sensors detect motion of the traveling block 106 and/or extension of the line supporting the traveling block 106, or other indications of the drill string 108 descending into the borehole 116. Speed sensors 224 (e.g., angular position sensors) disposed in the BHA 142, at the drill bit 114, or at the surface detect rotational speed of the drill bit 114.

The processor 202 is configured to execute instructions retrieved from storage 208. The processor 202 may include any number of cores or sub-processors. Suitable processors include, for example, general-purpose processors, digital signal processors, and microcontrollers. Processor architectures generally include execution units (e.g., fixed point, floating point, integer, etc.), storage (e.g., registers, memory, etc.), instruction decoding, peripherals (e.g., interrupt controllers, timers, direct memory access controllers, etc.), input/output systems (e.g., serial ports, parallel ports, etc.) and various other components and sub-systems.

Software programming, including instructions executable by the processor 202, is stored in the program/data storage 208. The program/data storage 208 is a non-transitory computer-readable medium. Computer-readable storage media include volatile storage such as random access memory, non-volatile storage (e.g., ROM, PROM, a hard drive, an optical storage device (e.g., CD or DVD), FLASH storage), or combinations thereof.

The program/data storage 208 includes a drilling control module 230 that when executed causes the processor 202 to control drilling operations. The drilling control module 230 includes a pore pressure calculation module 212 that includes instructions that when executed cause the processor 202 to compute a pore pressure value for the formations at the drill bit 114 based on measurements provided by the sensors 216 and the stored offset well data 206 as described herein.

The pore pressure calculation module 212 includes MSE calculation instructions 226, DE calculation instructions 214, and pore pressure calculation instructions 214. The MSE calculations cause the processor 202 to compute an MSE value based on measurements made at the drill bit 114 as described herein. The DE calculations instructions 214 cause the processor 202 to compute pseudo drilling efficiency and a drilling efficiency trendline based on MSE and stored offset well data 206 as disclosed herein. The pore pressure calculation instructions 214 cause the processor 202 to compute pore pressure for the formations 126 proximate the drill bit 114 based on MSE and drilling efficiency values as disclosed herein.

The stored offset well data 206 includes data acquired while drilling other wells in the vicinity of borehole 116, and may be stored local to the processor 202 (e.g., in storage disposed proximate to the drilling system 100) or remote from the processor 202 and accessed via a communication network (e.g., the internet). The stored offset well data 206 may include acoustic log data, normal hydrostatic pressure data, downhole pressure (equivalent circulation density), and/or overburden pressure/stress data acquired while drilling one or more offset wells 134.

The drill settings module 210 includes instructions that when executed cause the processor 202 to manipulate the actuators 228 to control the drilling operation. More specifically, the drill settings module 210 may set or change parameter that affect drilling in response to formation pore pressure measurements provided by execution of the pore pressure calculation module 212. The drill settings module 214 may also provide a control interface (e.g., via the display 204) and a user input device (e.g., keyboard, mouse, trackball, touchscreen, motion sensors, etc.) that allows a drilling operator to enter drilling control information into the drilling control system 128. For example, the drill settings module 214 may provide a user interface that allows the drilling operator to change WOB, drill string RPM, etc. applied to drill the borehole 116.

FIG. 3 shows a block diagram of an embodiment of the pore pressure calculator 144. The pore pressure calculator 144 includes a processor 202, a display device 204, and program/data storage 208. The processor 202 is also coupled to the stored offset well drilling data 206. In some embodiments of the pore pressure calculator 144, the processor 202 and program/data storage 208 may be embodied in computer, such as a desktop computer, notebook computer, a blade computer, a server computer, or other suitable computing device known in the art. The various components of the pore pressure calculator 144 are as described herein with respect to the drilling control system 128.

FIG. 4 shows a flow diagram for a method 400 for determining pore pressure of a formation based on MSE and drilling efficiency in accordance with principles disclosed herein. Though depicted sequentially as a matter of convenience, at least some of the actions shown can be performed in a different order and/or performed in parallel. Additionally, some embodiments may perform only some of the actions shown. In some embodiments, at least some of the operations of the method 400, as well as other operations described herein, can be implemented as instructions stored in a computer readable medium (e.g., storage 208) and executed by one or more processors (e.g., processor 202).

In block 402 one or more offset wells 134 are drilled and drilling data for the offset wells 134 is acquired and stored as stored offset well data 206. Offset well data acquired and stored may include acoustic log data, normal hydrostatic pressure data, downhole pressure (equivalent circulation density), and/or overburden pressure/stress data.

In block 404, the pore pressure calculator 144 computes CCS under normal pressure from the offset well data. The pore pressure calculator 144 may compute CCS based on UCS and angle of internal friction as shown in equation (3), where UCS and angle of internal friction are provided from the stored offset well data 206.

In block 406, the pore pressure calculator 144 computes a drilling efficiency trendline from the stored offset well data 206. The pore pressure calculator 144 may compute the drilling efficiency trendline as shown in equation (10), where normal compaction trend porosity is provided from the stored offset well data 206.

In block 408, the borehole 116 is being drilled and drilling parameters applied by the system 100 are being acquired while drilling. The drilling parameters measured may include torque, weight on bit, rate of penetration, rotational speed, bit size, etc. Parameters may be measured at the surface, in the BHA 142, or other drilling equipment. Some of the drilling parameters are measured at the drill bit 114. For example, torque and weight on bit may be measured at the drill bit 114 and transmitted to the surface for use in pore pressure calculation.

Inaccuracies in surface measurements of downhole parameters are often significant due to interaction of the drillstring 108 with the wall of the borehole 116, and surface to downhole correction factors may not be reliable because the correction can vary with depth due to increasing tubular contact forces and friction at depth. For torque and weight on bit, only measurements made at the bit 114 accurately represent the energy applied to remove material from the formation being drilled. Therefore, the pore pressure calculator 144 employs measurements made at the drill bit 114 to calculate pore pressure based on MSE and DE.

For pore pressure calculation, accurate measurement of downhole torque is important for MSE computation because the torque term in MSE often dominates the WOB term. In rotary drilling, particularly with polycrystalline diamond compact (PDC) bits, the energy that is spent shearing the rock due to torque is markedly larger than the work done to crush the rock in compression by WOB. In addition, lateral forces due to torque on the cutters are applied over a significantly larger helical distance during rotary drilling compared to the applied WOB over the relatively small axial advancement of the bit. Consequently, the work done by torque, which is the product of the applied lateral forces and distance, is considerably higher than that of done by WOB over the bit penetration. Therefore, embodiments of the pore pressure calculator 144 apply torque measured at the drill bit 114 to compute MSE and formation pore pressure. Conventional d-exponent methods may not consider the effects of torque on pore pressure determination (e.g., d-exponent may apply only WOB).

In block 410, the pore pressure calculator 144 computes MSE based on the acquired drilling parameters. The pore pressure calculator 144 may compute MSE as shown in equation (1) using torque and/or weight on bit measured at the drill bit 114.

In block 412, the pore pressure calculator 144 computes a pseudo drilling efficiency value for the drilling of the borehole 116. The pore pressure calculator 144 may compute pseudo drilling efficiency as shown in equation (8) using CCS computed from the stored offset well data 206 and MSE computed using measurements at the drill bit 114.

In block 414, the pore pressure calculator 144 computes the difference of the pseudo drilling efficiency and the drilling efficiency trendline as shown in equation (12). The pore pressure calculator 144 may compute the drilling efficiency trendline as shown in equation (10) using normal compaction trend porosity from the stored offset well data 206.

In block 416, the pore pressure calculator 144 computes pore pressure for the formations at the drill bit 114 (i.e., the formation material in contact with the drill bit 114) based on MSE and drilling efficiency as shown in equation (11).

In block 418, the drilling control system 128 applies the formation pore pressure computed by the pore pressure calculator 144 to control various aspects of the drilling operation. For example, based on the pore pressure value, the drilling control system 128 may determine that that drilling of a hole section is complete and halt drilling of the hole section. Similarly, the drilling control system 128 may adjust the density of the drilling fluid circulated in the borehole 116 based on the calculated pore pressure. By calculating the pore pressure of the formation material located at drill bit 114 as disclosed herein, the pore pressure calculator 144 significantly reduces the time required to determine the pore pressure at a given location of the borehole 116, and in turn provides a substantial improvement in drilling technology relative to conventional pore pressure estimation technologies.

FIG. 5 shows an example of pore pressure determined using conventional methods and pore pressure calculated based on MSE in accordance with principles disclosed herein. The conventionally determined pore pressure values 506 are derived from sonic log data using conventional methods. Pore pressure values calculated as disclosed herein 508 are computed based on MSE and drilling efficiency using torque and weight on bit measurements made at the drill bit 114. As shown in FIG. 5, the MSE/DE derived pore pressure values 508 compare favorably with the sonic derived pore pressure values 506.

FIG. 6 shows an example of pore pressure determined using conventional d-exponent methods 602 and pore pressure calculated based on MSE 604 in accordance with an embodiment disclosed herein. The d-exponent methodology is often used to establish a quantitative estimate of formation pore pressure as well as qualitative detection of abnormal formation pressure. A d-exponent equation modified to include mud weight, known as the corrected d-exponent (dXc), is shown in equation (14).

$\begin{array}{cc}\mathrm{dXc}=\frac{\log \left(\frac{\mathrm{ROP}}{60\mathrm{RPM}}\right)}{\log \left(\frac{12\mathrm{WOB}}{d}\right)}\left(\frac{p_n}{p_w}\right)& \left(144\right)\end{array}$

where:
RPM is revolutions per minute;
ROP is rate of penetration;
WOB is weight on bit;
d is borehole diameter;
p_n is normal hydrostatic pressure; and
p_w is downhole pressure (downhole mud weight or ECD).

The pore pressure can be derived from the departure of the calculated dXc from a normal trend line established from the dXc trend in a representative shallower section in the well.

$\begin{array}{cc}p=\frac{\mathrm{dXc},n}{\mathrm{dXc}}p_n& \left(14\right)\end{array}$

In FIG. 6, both the dXc method and the DE/MSE based technique of the present disclosure have been applied to a same well dataset. The dXc method has been applied using a single normal trend line, which was established by fitting the dXc data through the normally pressured section between 10000-11000 ft. Both dXc and the DE/MSE based technique provide a reasonable estimate of pore pressure for the bottom hole section. However, in the two hole sections immediately below salt, pore pressure trends estimated using the dXc method are a poor match to the log derived pressure curve, while the DE/MSE technique yields a result with considerably less scatter, and which more closely follows the sonic-derived pore pressure curve. It may be possible to reduce the scatter in dXc results by establishing a new trendline for each hole section, once enough section has been drilled to characterize the drilling conditions unique to the hole section. The disadvantage of such an approach is that increasing the number of local calibrations of the dXc trendlines, increasingly skews the dXc method towards being a qualitative pore pressure indicator that must always be used in conjunction with conventional log-based approaches, rather than as a truly independent quantitative pressure estimation method.

In contrast to the DE/MSE technique, which is an energy based approach and takes into account both torque and WOB, the dXc parameter considers only weight on bit (compare equation (1) with equation (14)). Because dXc considers only WOB, changes in drilling variables that are not related to pore pressure, such as bit size, bit type, and mud properties, etc., can often lead to dXc variations that are misinterpreted as having pore pressure significance. A common practice to compensate, when attempting to use dXc for pore pressure estimation, is to use multiple trendlines (e.g., for each hole section). But such trendline breakage leads to an increased level of subjectivity, and will adversely affect the confidence, in pore pressure estimates from the dXc approach.

Various embodiments of systems and methods for pore pressure determination and drilling control based on the pore pressure determination have been disclosed herein. In an embodiment, a method for drilling a borehole in a subsurface formation includes 1) rotating a drill bit to remove formation material from the subsurface formation at an end of the borehole; 2) calculating a value of mechanical specific energy applied to remove the formation material; 3) calculating a value of drilling efficiency based on the value of mechanical specific energy; 4) calculating pore pressure of the subsurface formation in contact with the drill bit as a function of calculated drilling efficiency; and/or 5) controlling the drilling based on calculated pore pressure of the subsurface formation. The method may also include acquiring a measurement of downhole torque applied at the drill bit and weight on bit applied at the drill bit to perform the rotating; and calculating the value of mechanical specific energy based on the acquired measurement of torque and weight on bit at the drill bit. The method may also include calculating the pore pressure based on a product of the value of mechanical specific energy and the calculated drilling efficiency. The method may also include calculating the pore pressure based on an angle of internal friction derived from offset well data. The method may also include calculating confined compressive strength of the formation based on normal pore pressure; and calculating the value of drilling efficiency as a ratio of the calculated confined compressive strength to the value of mechanical specific energy. The method may also include calculating a trend of normal drilling efficiency based on pressure data from an offset well; and calculating the pore pressure as a function of a difference of the value of drilling efficiency and the trend of normal drilling efficiency. The method may also include determining whether the calculated pore pressure is within a predetermined pressure range; and controlling the drilling operation responsive to the calculated pore pressure being within the predetermined pressure range. In the method, controlling the drilling may include at least one of changing drilling fluid density and changing drill bit movement. The method may also calculate the pore pressure of the subsurface formation prior to a formation parameter measurement tool disposed uphole of the drill bit (e.g., disposed in a bottom hole assembly) reaching a location of the subsurface formation corresponding to the calculated pore pressure.

A system for drilling a borehole in a subsurface formation includes a drill string; a drill bit positioned at an end of the drill string to extend the borehole into the subsurface formation; and a drilling control system. The drilling control system includes: a pore pressure calculator and drilling control logic. The pore pressure calculator is configured to calculate pore pressure of the formation in contact with the drill bit. The pore pressure calculator is further configured to: calculate a value of drilling efficiency for the drilling of the borehole based on a drilling parameter measured at the bit; and calculate the pore pressure as a function of the calculated value of drilling efficiency. The drilling control logic is configured to control the drilling based on calculated pore pressure. The pore pressure calculator may be configured to: calculate a value of mechanical specific energy applied to drill the formation; and calculate the value of drilling efficiency based on the value of mechanical specific energy. The pore pressure calculator may be configured to: acquire a measurement of torque applied at the drill bit and weight on bit applied at the drill bit to drill the formation; and calculate the value of mechanical specific energy based on the acquired measurement of torque and weight on bit at the drill bit. The measurement of torque applied at the drill bit may be acquired in a bottom hole assembly of the drill string. The measurement of torque applied at the drill bit may be a measurement of torque applied in a portion (a percentage, e.g., 1/10th) of the drill string nearest the drill bit. The pore pressure calculator may be configured to: calculate the pore pressure based on the value of mechanical specific energy. The pore pressure calculator may be configured to: calculate confined compressive strength of the formation based on normal pore pressure; and calculate the value of drilling efficiency as a ratio of calculated confined compressive strength to the value of mechanical specific energy. The pore pressure calculator may be configured to: calculate a trend of normal drilling efficiency based on pressure data from an offset well; and calculate the pore pressure as a function of a difference of the value of drilling efficiency and the trend of normal drilling efficiency. The drilling control logic may be configured to: determine whether the calculated pore pressure is within a predetermined pressure range; and change at least one of drilling fluid density and drill bit movement based responsive to the calculated pore pressure being within the predetermined pressure range.

A system for calculating pore pressure of a subsurface formation includes a processor and a storage that is coupled to the processor. The storage device contains instructions that when executed cause the processor to: 1) calculate a value of mechanical specific energy applied at a drill bit to remove material from the subsurface formation; 2) calculate a value of drilling efficiency for drilling the formation; and 3) calculate pore pressure of the formation in contact with the drill bit as a function of the value of drilling efficiency and the mechanical specific energy. The instructions may also cause the processor to acquire a measurement of torque applied at the drill bit to remove the material from the subsurface formation; and calculate the value of mechanical specific energy based on the acquired measurement of torque applied at the drill bit. The instructions may also cause the processor to calculate the pore pressure based on a product of the value of mechanical specific energy and the value of drilling efficiency. The instructions may also cause the processor to calculate confined compressive strength of the formation based on normal pore pressure; and calculate the value of drilling efficiency as a ratio of the calculated confined compressive strength to the value of mechanical specific energy. The instructions may also cause the processor to calculate a trend of normal drilling efficiency based on pressure data received from an offset well; and calculate the pore pressure as a function of a difference of the value of drilling efficiency and the trend of normal drilling efficiency. The instructions may also cause the processor to calculate the pore pressure as shown in equation (11) or (13).

A method for drilling a borehole in a subsurface formation includes: 1) rotating a drill bit to remove formation material from the subsurface formation at an end of the borehole; 2) calculating a value of mechanical specific energy applied to remove the formation material; 3) calculating a value of drilling efficiency for drilling the borehole; 4) calculating pore pressure of the subsurface formation in contact with the drill bit as a function of the drilling efficiency and the mechanical specific energy; and 5) controlling the drilling based on calculated pore pressure of the subsurface formation. The method may also include acquiring a measurement of downhole torque applied at the drill bit and weight on bit applied at the drill bit to perform the rotating, and calculating the value of mechanical specific energy based on the acquired measurement of torque and weight on bit at the drill bit. The method may also include acquiring the measurement of downhole torque applied at the drill bit in a bottom hole assembly of a drill string, or acquiring the measurement of downhole torque applied at the drill bit in a 1/10 of a drill string nearest the drill bit. The method may also include calculating the pore pressure based on an angle of internal friction derived from offset well data. The method may also include calculating confined compressive strength of the formation based on normal pore pressure, and calculating the value of drilling efficiency as a ratio of the calculated confined compressive strength to the value of mechanical specific energy. The method may also include determining whether the calculated pore pressure is within a predetermined pressure range, and controlling the drilling operation responsive to the calculated pore pressure being within the predetermined pressure range. Controlling the drilling may include at least one of changing drilling fluid density and changing drill bit movement. The pore pressure of the subsurface formation may be calculated prior to a formation parameter measurement tool disposed uphole of the drill bit reaching a location of the subsurface formation corresponding to the calculated pore pressure. The method may also include calculating the pore pressure based on a product of the value of mechanical specific energy and the value of drilling efficiency. The method may also include calculating a trend of normal drilling efficiency based on pressure data from an offset well, and calculating the pore pressure as a function of a difference of the value of drilling efficiency and the trend of normal drilling efficiency. The method may also include calculating the pore pressure based on equation (11). The method may also include calculating a trend of normal drilling efficiency based on pressure data from an offset well, and calculating the pore pressure as a product of the trend and the value of mechanical specific energy. The method may also include calculating the pore pressure based on equation (13). In some embodiments, a system is configured to perform any of the operations of the method.

In the drawings and description of the present disclosure, like parts are typically marked throughout the specification and drawings with the same reference numerals. The drawing figures are not necessarily to scale. Certain features of the invention may be shown exaggerated in scale or in somewhat schematic form, and some details of conventional elements may not be shown in the interest of clarity and conciseness. The present disclosure is susceptible to embodiments of different forms. Specific embodiments are described in detail and are shown in the drawings, with the understanding that the present disclosure is to be considered an exemplification of the principles of the disclosure, and is not intended to limit the disclosure to that illustrated and described herein. It is to be fully recognized that the different teachings and components of the embodiments discussed below may be employed separately or in any suitable combination to produce desired results.

The above discussion is meant to be illustrative of various principles and embodiments of the present disclosure. While certain embodiments have been shown and described, modifications thereof can be made by one skilled in the art without departing from the spirit and teachings of the disclosure. The embodiments described herein are exemplary only, and are not limiting. Accordingly, the scope of protection is not limited by the description set out above, but is only limited by the claims which follow, that scope including all equivalents of the subject matter of the claims.

Claims

1. A method for drilling a borehole in a subsurface formation, comprising:

rotating a drill bit to remove formation material from the subsurface formation at an end of the borehole;

calculating a value of mechanical specific energy applied to remove the formation material;

calculating a value of drilling efficiency based on the value of mechanical specific energy;

calculating pore pressure of the subsurface formation in contact with the drill bit as a function of calculated drilling efficiency; and

controlling the drilling based on calculated pore pressure of the subsurface formation.

2. The method of claim 1, further comprising:

acquiring a measurement of downhole torque applied at the drill bit and weight on bit applied at the drill bit to perform the rotating; and

calculating the value of mechanical specific energy based on the acquired measurement of torque and weight on bit at the drill bit.

3. The method of claim 1, further comprising:

calculating the pore pressure based on a product of the value of mechanical specific energy and the calculated drilling efficiency; and

calculating the pore pressure based on an angle of internal friction derived from offset well data.

4. The method of claim 1, further comprising:

calculating confined compressive strength of the formation based on normal pore pressure; and

calculating the value of drilling efficiency as a ratio of the calculated confined compressive strength to the value of mechanical specific energy.

5. The method of claim 1, further comprising:

calculating a trend of normal drilling efficiency based on pressure data from an offset well; and

calculating the pore pressure as a function of a difference of the value of drilling efficiency and the trend of normal drilling efficiency.

6. The method of claim 1, further comprising:

determining whether the calculated pore pressure is within a predetermined pressure range; and

controlling the drilling operation responsive to the calculated pore pressure being within the predetermined pressure range; wherein controlling the drilling comprises at least one of changing drilling fluid density and changing drill bit movement.

7. The method of claim 1, wherein the pore pressure of the subsurface formation is calculated prior to a formation parameter measurement tool disposed uphole of the drill bit reaching a location of the subsurface formation corresponding to the calculated pore pressure.

8. A system for drilling a borehole in a subsurface formation, comprising:

a drill string;

a drill bit positioned at an end of the drill string to extend the borehole into the subsurface formation; and

a drilling control system comprising: a pore pressure calculator configured to calculate pore pressure of the formation in contact with the drill bit, the pore pressure calculator configured to: calculate a value of drilling efficiency for the drilling of the borehole based on a drilling parameter measured at the bit; and calculate the pore pressure as a function of the calculated value of drilling efficiency; and drilling control logic configured to control the drilling based on calculated pore pressure.

9. The system of claim 8, wherein the pore pressure calculator is configured to:

calculate a value of mechanical specific energy applied to drill the formation; and

calculate the value of drilling efficiency based on the value of mechanical specific energy.

10. The system of claim 9, wherein the pore pressure calculator is configured to:

acquire a measurement of torque applied at the drill bit and weight on bit applied at the drill bit to drill the formation; and

calculate the value of mechanical specific energy based on the acquired measurement of torque and weight on bit at the drill bit.

11. The system of claim 10, wherein the measurement of torque applied at the drill bit is acquired in a bottom hole assembly of the drill string; or the measurement of torque applied at the drill bit is a measurement of torque applied in a 1/10 of the drill string nearest the drill bit.

12. The system of claim 8, wherein the pore pressure calculator is configured to calculate the pore pressure based on mechanical specific energy.

13. The system of claim 8, wherein the pore pressure calculator is configured to:

calculate confined compressive strength of the formation based on normal pore pressure; and

calculate the value of drilling efficiency as a ratio of calculated confined compressive strength to the value of mechanical specific energy.

14. The system of claim 8, wherein the pore pressure calculator is configured to:

calculate a trend of normal drilling efficiency based on pressure data from an offset well; and

calculate the pore pressure as a function of a difference of the value of drilling efficiency and the trend of normal drilling efficiency.

15. The system of claim 8, wherein the drilling control logic is configured to:

determine whether the calculated pore pressure is within a predetermined pressure range; and

change at least one of drilling fluid density and drill bit movement responsive to the calculated pore pressure being within the predetermined pressure range.

16. A system for calculating pore pressure of a subsurface formation, comprising:

a processor;

a storage device coupled to the processor and containing instructions that when executed cause the processor to: calculate a value of mechanical specific energy applied at a drill bit to remove material from the subsurface formation; calculate a value of drilling efficiency for drilling the formation; and calculate pore pressure of the formation in contact with the drill bit as a function of the value of drilling efficiency and the mechanical specific energy.

17. The system of claim 16, wherein the instructions cause the processor to:

acquire a measurement of torque applied at the drill bit to remove the material from the subsurface formation;

calculate the value of mechanical specific energy based on the acquired measurement of torque applied at the drill bit; and

calculate the pore pressure based on a product of the value of mechanical specific energy and the value of drilling efficiency.

18. The system of claim 16, wherein the instructions cause the processor to:

calculate confined compressive strength of the formation based on normal pore pressure;

calculate the value of drilling efficiency as a ratio of the calculated confined compressive strength to the value of mechanical specific energy;

calculate a trend of normal drilling efficiency based on pressure data received from an offset well; and

calculate the pore pressure as a function of a difference of the value of drilling efficiency and the trend of normal drilling efficiency.

19. The system of claim 16, wherein the instructions cause the processor to calculate the pore pressure as: p = p n + Δ   DE × MSE × ( 1 - sin   θ 1 + sin   θ ), where:

p is calculated pore pressure;

pn is normal hydrostatic pressure;

ΔDE is a difference of the value of drilling efficiency and a trend of normal drilling efficiency;

MSE is the value of mechanical specific energy; and

θ is angle of internal friction.

20. The system of claim 16, wherein the instructions cause the processor to calculate the pore pressure as: p = ECD - ( DE trend × MSE - UCS ) × ( 1 - sin   θ 1 + sin   θ ), where:

p is calculated pore pressure;

ECD is equivalent circulating density;

DEtrend is a trend of normal drilling efficiency;

MSE is the value of mechanical specific energy;

UCS is unconfined compressive strength; and

θ is angle of internal friction.