METHOD OF WELL CONTROL

Abstract

Methods and systems for well control are disclosed. The methods may include drilling, using a drilling system, a wellbore to a first depth within a formation using a drilling fluid with a first density. The methods may further include, while drilling the wellbore, obtaining, from the drilling system, a first value of each drilling parameter associated to the first depth, determining, using a first model, a first value of a formation pressure based on the first value of each drilling parameter and a value of the first density of the drilling fluid, and determining, using a second model, a first value of a drilling fluid drop based on the first value of the formation pressure. The methods may still further include drilling the wellbore to a second depth within the formation using the drilling fluid with a second density based on the first value of the drilling fluid drop.

Description

BACKGROUND

In the oil and gas industry, wellbores are drilled to penetrate hydrocarbon reservoirs within formations such that the hydrocarbons may be produced to the surface to be used as fuel. Drilling wellbores is time consuming, expensive, and complex. As such, data associated with the drilling conditions and/or formation may be acquired during drilling and/or when drilling is paused to ensure the formation is being drilled efficiently and safely such that prolific hydrocarbons may be produced to the surface following drilling and completion operations.

If data is not acquired or only acquired intermittently, changes in the drilling conditions and/or formation may not be realized in time to control the wellbore. A loss of control of the wellbore may cause a stuck pipe, kick, blowout, or lost circulation incident. Any incident may result in lost time, increased expenses, and added complexity.

SUMMARY

This summary is provided to introduce a selection of concepts that are further described below in the detailed description. This summary is not intended to identify key or essential features of the claimed subject matter, nor is it intended to be used as an aid in limiting the scope of the claimed subject matter.

In general, in one aspect, embodiments relate to a method. The method includes drilling, using a drilling system, a wellbore to a first depth within a formation using, at least in part, a drilling fluid with a first density. The method further includes, while drilling the wellbore, obtaining, from the drilling system, a first value of each drilling parameter associated to the first depth, determining, using a first model, a first value of a formation pressure based, at least in part, on the first value of each drilling parameter and a value of the first density of the drilling fluid, and determining, using a second model, a first value of a drilling fluid drop based, at least in part, on the first value of the formation pressure. The method still further includes drilling, using the drilling system, the wellbore to a second depth within the formation using, at least in part, the drilling fluid with a second density based, at least in part, on the first value of the drilling fluid drop.

In general, in one aspect, embodiments relate to a system. The system includes a drilling system and a computer system. The drilling system is configured to drill a wellbore to a first depth within a formation using, at least in part, a drilling fluid with a first density. The computer system is configured to, while drilling the wellbore, receive, from the drilling system, a first value of each drilling parameter associated to the first depth, determine, using a first model, a first value of a formation pressure based, at least in part, on the first value of each drilling parameter and a value of the first density of the drilling fluid, and determine, using a second model, a first value of a drilling fluid drop based, at least in part, on the first value of the formation pressure. The drilling system is further configured to drill the wellbore to a second depth within the formation using, at least in part, the drilling fluid with a second density based, at least in part, on the first value of the drilling fluid drop.

Other aspects and advantages of the claimed subject matter will be apparent from the following description and the appended claims.

BRIEF DESCRIPTION OF DRAWINGS

Specific embodiments of the disclosed technology will now be described in detail with reference to the accompanying figures. Like elements in the various figures are denoted by like reference numerals for consistency.

FIG. 1 illustrates a drilling system in accordance with one or more embodiments.

FIG. 2 displays formation pressure profiles in accordance with one or more embodiments.

FIG. 3 displays drilling fluid drop profiles in accordance with one or more embodiments.

FIG. 4 displays drilling fluid volume profiles in accordance with one or more embodiments.

FIG. 5 shows a flowchart in accordance with one or more embodiments.

FIG. 6 illustrates a computer system in accordance with one or more embodiments.

DETAILED DESCRIPTION

In the following detailed description of embodiments of the disclosure, numerous specific details are set forth in order to provide a more thorough understanding of the disclosure. However, it will be apparent to one of ordinary skill in the art that the disclosure may be practiced without these specific details. In other instances, well-known features have not been described in detail to avoid unnecessarily complicating the description.

Throughout the application, ordinal numbers (e.g., first, second, third, etc.) may be used as an adjective for an element (i.e., any noun in the application). The use of ordinal numbers is not to imply or create any particular ordering of the elements nor to limit any element to being only a single element unless expressly disclosed, such as using the terms “before,” “after,” “single,” and other such terminology. Rather, the use of ordinal numbers is to distinguish between the elements. By way of an example, a first element is distinct from a second element, and the first element may encompass more than one element and succeed (or precede) the second element in an ordering of elements.

It is to be understood that the singular forms “a,” “an,” and “the” include plural referents unless the context clearly dictates otherwise. Thus, for example, reference to “a first model” includes reference to one or more models.

Terms such as “approximately,” “substantially,” etc., mean that the recited characteristic, parameter, or value need not be achieved exactly, but that deviations or variations, including for example, tolerances, measurement error, measurement accuracy limitations and other factors known to those of skill in the art, may occur in amounts that do not preclude the effect the characteristic was intended to provide.

It is to be understood that one or more of the steps shown in the flowchart may be omitted, repeated, and/or performed in a different order than the order shown. Accordingly, the scope disclosed herein should not be considered limited to the specific arrangement of steps shown in the flowchart.

Although multiple dependent claims are not introduced, it would be apparent to one of ordinary skill that the subject matter of the dependent claims of one or more embodiments may be combined with other dependent claims.

In the following description of FIGS. 1-6, any component described regarding a figure, in various embodiments disclosed herein, may be equivalent to one or more like-named components described regarding any other figure. For brevity, descriptions of these components will not be repeated regarding each figure. Thus, each and every embodiment of the components of each figure is incorporated by reference and assumed to be optionally present within every other figure having one or more like-named components. Additionally, in accordance with various embodiments disclosed herein, any description of the components of a figure is to be interpreted as an optional embodiment which may be implemented in addition to, in conjunction with, or in place of the embodiments described regarding a corresponding like-named component in any other figure.

Methods and systems are disclosed to determine values of a formation pressure in real time as a wellbore is being drilled within a formation. Determining the value of the formation pressure at each discrete depth along the wellbore in real time may rely on empirical models and a value of each of multiple drilling parameters obtained while the wellbore is being drilled. The drilling parameters may be determined using drilling sensors that are a part of the drilling system configured to drill the wellbore.

The value of the formation pressure at each discrete depth along the wellbore may be used to determine a value of a drilling fluid drop. In turn, the value of the drilling fluid drop may be used to adjust the density and, in some embodiments, the volume of the drilling fluid used by the drilling system as the wellbore continues to be drilled.

Drilling fluid may be colloquially referred to as “drilling mud” or simply “mud.” As such, the terms “drilling fluid,” “drilling mud,” and “mud” are considered synonymous and used interchangeably throughout the disclosure. However, a person of ordinary skill in the art will appreciate that drilling fluid may not include mud based on the common definition of mud. Further, the terms “well” and “wellbore” are considered synonymous and used interchangeably throughout the disclosure. However, a person of ordinary skill in the art will appreciate that a well often refers to a complete well and its casing while a wellbore often refers to an incomplete well still in the process of being drilled.

The disclosed methods may be an improvement over other methods for at least one of the following reasons. First, the value of the formation pressure may be determined in real time as the wellbore is being drilled within the formation. That is, the drilling system need not be removed from the wellbore and a well logging system deployed downhole to collect one or more well logs used to determine the value of the formation pressure. Thus, the disclosed methods may save time and reduce drilling costs as drilling need not pause and well logging systems need not be used. Second, the disclosed methods may allow for better well control because the value of the formation pressure can be determined more frequently and during drilling unlike other methods that rely on well logging systems that can only determine the value of the formation pressure intermittently while drilling is paused. Such an improvement may be particularly useful when drilling wellbores blind. Further, such an improvement may allow the drilling team to quickly respond to incidents, such as a kick or lost circulation incident, that would otherwise be difficult to control or unavoidable if the value of the formation pressure were only determined intermittently while drilling is paused as other methods do.

FIG. 1 illustrates a drilling system 100 drilling a wellbore 102 within a formation 104 in accordance with one or more embodiments. Although the drilling system 100 shown in FIG. 1 is used to drill a wellbore 102 on land, the drilling system 100 may be a marine wellbore drilling system. The example of the drilling system 100 shown in FIG. 1 is not meant to limit the present disclosure.

The drilling system 100 may include a drilling rig 106 situated on a land drill site, offshore platform, such as a jack-up rig, semi-submersible rig, or drill ship. The drilling rig 106 may be equipped with a hoisting system, such as a derrick 108, which can raise or lower a drillstring 110 and other parts of the drilling system 100 required to drill the wellbore 102. The drillstring 110 may include one or more connected drill pipes and a bottom hole assembly (BHA) 112 disposed at the distal end of the drillstring 110. The BHA 112 may include a drill bit 114 to cut into rock 116 of the formation 104. The BHA 112 may further include measurement-while-drilling (MWD) tools and logging-while-drilling (LWD) tools (not shown). The MWD tools may include drilling sensors 118 (such as, downhole drilling sensors and hydraulic sensors) configured to determine a value for each drilling parameter. Drilling parameters are discussed in detail below but, for reference, refer to parameters associated with the drilling operations and/or formation 104. The LWD tools may also include drilling sensors 118 configured to determine a value for each drilling parameter. Any value of each drilling parameter associated with the drilling system 100 downhole, such as those determined using the MWD and/or LWD tools, may be transmitted to the surface of the earth 120 using any suitable telemetry system known in the art, such as by mud pulse or wired drill pipe.

The drilling system 100 may control at least a portion of a drilling operation by providing controls to various components of the drilling operation. In one or more embodiments, the drilling system 100 may receive data from one or more drilling sensors 118 configured to determine a value of each drilling parameter of the drilling operation. As a non-limiting example, drilling sensors 118 may be configured to determine a value of the weight on bit (WOB), rate of rotation of the drillstring 110 (RPM), pumping rate of the drilling fluid (GPM), and rate of penetration of the drill bit 114 (ROP). Drilling may be considered complete when a drilling target within the hydrocarbon reservoir (not shown) is reached or the presence of hydrocarbons is established.

To begin drilling, or “spudding in,” the wellbore 102, the derrick 108 may be used to lower the drillstring 110, suspended from the derrick 108, towards the planned surface location 122 of the wellbore 102. In some embodiments, an engine, such as a diesel engine, may supply power to a top drive (not shown) to rotate the drillstring 110 via a drive shaft (not shown). In other embodiments, the engine may supply power to a rotary table 124 to rotate the drillstring 110 via a kelly 126. The weight of the drillstring 110 combined with the rotational motion of the drillstring 110 enables the drill bit 114 to bore the wellbore 102.

The near-surface of the formation 104 is typically made up of loose or soft sediment rock 116, so large diameter casing 128 (e.g., “base pipe” or “conductor casing”) is often put in place while drilling to stabilize and isolate the wellbore 102. At the top of the large diameter casing 128 is the wellhead (not shown), which serves to provide pressure control through a series of spools, valves, and/or adapters. The wellhead may include a blowout preventor (BOP) 130 that may be closed quickly to protect the drilling rig 106 and environment from unplanned oil or gas releases known as “blowouts.” Drilling, using successively smaller drill bits 114, may continue with successively smaller casing 128 or without any casing 128 once deeper and/or more compact rock 116 is reached. Drilling deviated or horizontal wellbores 102 may require specialized drill bits 114 and/or drilling systems 100.

At planned depth intervals, drilling may be paused and the drillstring 110 withdrawn from the wellbore 102. Sections of casing 128 (i.e., casing string) may be connected, inserted, and cemented into the wellbore 102. Casing string may be cemented in place by pumping cement and mud, separated by a “cementing plug,” from the surface of the earth 120 through the drillstring 110. The cementing plug and mud force the cement through the drillstring 110 and into an annulus (not shown) between the casing 128 and the wellbore 102. Once the cement cures, drilling may recommence. The drilling process is often performed in several stages. Therefore, drilling and casing cycles may be repeated, depending on the depth of the wellbore 102 and the pressure on the walls of the wellbore 102 from surrounding rock 116.

During drilling, a drilling fluid pump 134 may pump drilling fluid 136 through a standpipe 138, the kelly 126, and the BOP 130 installed on the wellhead and into the drillstring 110. For reference, the arrows in FIG. 1 show the direction of travel 140 of the drilling fluid 136. The drilling fluid pump 134, standpipe 138, kelly 126 and/or any other part of the drilling system 100 on the surface of the earth 120 may be equipped with or separated by one or more drilling sensors 118. Here, each drilling sensor 118 may be considered a surface drilling sensor, which may be further considered a rheology sensor. Hereinafter, the generic term “drilling sensor” may reference a downhole drilling sensor, surface drilling sensor, rheology sensor, and/or hydraulic sensor. Further, each drilling sensor 118 may be communicably coupled to a computer system 142. The computer system 142 is discussed in detail relative to FIG. 6.

Returning to the drilling fluid 136 shown in FIG. 1, the drilling fluid 136 may exit the drillstring 110 via openings in the drill bit 114. The drilling fluid 136 may travel up an annulus 132 that exists between the drillstring 110 and the wellbore 102. Again, for reference, the arrows in FIG. 1 show the direction of travel 140 of the drilling fluid 136. The drilling fluid 136 may travel through a flowline 144 and into a shale shaker 146. The shale shaker 146 may be configured to remove unwanted solids collected downhole from the drilling fluid 136. Unwanted solids may include rock cuttings created by the drill bit 114. The filtered drilling fluid 136 may be stored in a shaker tank 148. This flow of the drilling fluid 136 into and out of the wellbore 102 may be considered one circulation cycle. The filtered drilling fluid 136 may pass through a suction tank 150 and be re-circulated through the drillstring 110 and annulus 132 using the drilling fluid pump 134 as the drilling system 100 continues to drill the wellbore 102 deeper into the formation 104.

The drilling fluid 136 may be made up of a continuous phase, discontinuous phase, and, on occasion, gas phase. The continuous phase may be a liquid. The continuous phase may be used to categorize the type of drilling fluid 136 as gas, aqueous, or nonaqueous. Aqueous drilling fluids may be referred to as water-based muds and range from simple blends of water and clay to complex inhibitive or clay-stabilizing muds. Nonaqueous drilling fluids may be referred to as synthetic-based muds. Nonaqueous drilling fluids may include mineral oils, biodegradable esters, olefins, and other variants. The discontinuous phase may be a solid. In some embodiments, the solids may be considered lost circulation materials (LCM). As such, the drilling fluid 136 may be a blend of liquid and solid components. Each component may be designed to modify a specific property of the drilling fluid 136, such as the viscosity and/or density of the drilling fluid 136. However, a person of ordinary skill in the art will appreciate that drilling fluid 136 may be simply water or air and not include mud based on the common definition of mud, such as a mixture of clay and water. Further, the type of drilling fluid 136 used should in no way limit the present disclosure.

Drilling fluid 136 serves numerous purposes. First, the drilling fluid 136 may transport rock cuttings (hereinafter “cuttings”) created by the drill bit 114 downhole to the surface of the earth 120. Managing the ability of the drilling fluid to transport the cuttings up the annulus 132 (i.e., the carrying capacity of the drilling fluid 136) may be necessary to drill efficiently. Managing the carrying capacity of the drilling fluid 136 may also be necessary to minimize the potential for the drillstring 110 to get stuck, no longer rotate, and, thus, no longer drill (a condition known as “stuck pipe”). Second, the drilling fluid 136 may cool and lubricate the drill bit 114 after the drilling fluid 136 exits through the openings of the drill bit 114. The thermal energy (i.e., heat) from the drill bit 114 may then pass to the drilling fluid 136 and be carried by the drilling fluid 136 to the surface of the earth 120. Third, the drilling fluid 136 may power downhole motors, drilling sensors 118, and/or other hardware that steer the drill bit 114 or obtain a value for each drilling parameter in real time, for example.

Fourth and fifth, the drilling fluid 136 may balance or slightly overbalance the formation pressure and, thus, maintain well control. If the pressure of the drilling fluid 136 underbalances (or is less than) the formation pressure, formation fluids may enter the wellbore 102 during drilling. This condition of the formation fluids entering the wellbore 102 may be referred to as a “kick” or “underbalanced kick.” A kick may cause loss of well control that results in a blowout (i.e., an uncontrolled flow of formation fluids from the wellbore 102 to the surface of the earth 120). If the pressure of the drilling fluid 136 balances or slightly overbalances (or is nearly equal to) the formation pressure, the formation fluids may be maintained within the formation 104 such that drilling of the wellbore 102 may continue efficiently and safely. If the pressure of the drilling fluid 136 greatly overbalances (or is greater than) the formation pressure, the rock 116 of the formation 104 may fracture and the drilling fluid 136 may escape into the formation 104 during drilling. This condition is known as lost circulation. Lost circulation may be categorized into three levels based on the rate of the drilling fluid 136 that travels up the annulus 132: seepage loss (less than 20 barrels per hour (bbl/hr)), partial loss (greater than 20 bbl/hr but still some returns), and total loss (no returns).

As the drilling fluid 136 re-circulates through the wellbore 102 (i.e., the circulation cycles increase) as the wellbore 102 is being drilled deeper within the formation 104, the properties of the drilling fluid 136 and the properties of the formation 104 change. In particular, the formation pressure increases with increasing depth. As such, the properties of the drilling fluid 136 and the formation 104 may need to be evaluated frequently to ensure the formation pressure is adequately balanced or slightly overbalanced by the drilling fluid 136. To ensure the formation pressure is adequately balanced or slightly overbalanced by the drilling fluid 136 and well control is, thus, maintained, it may be useful to determine a value of the formation pressure in real time during drilling and adjust the density, and, in some embodiments, the volume, of the drilling fluid 136 based, at least in part, on the value of the formation pressure.

A value of the formation pressure (FP), in units of pounds per square inch (psi), may be determined as:

$\begin{array}{cc}\mathrm{FP}=0.5(\left(\mathrm{Depth}-\left(\mathrm{Depth}-\left(0.007\mathrm{EMW}\mathrm{Depth}\right)\right){\left(\frac{CDE}{ODE}\right)}^{1.2}\right)+\left(\mathrm{Depth}-\left(\mathrm{Depth}-\left(0.007\mathrm{EMW}\mathrm{Depth}\right)-\mathrm{CP}\right){\left(\frac{\mathrm{CDE}}{\mathrm{ODE}}\right)}^{1.2}\right),& \mathrm{Equation}\left(1\right)\end{array}$

where depth is the depth along the wellbore 102 in units of feet, such as a first depth 152 and a second depth 154, EMW is the effective mud weight (hereinafter also “effective drilling fluid density”) in units of pounds per cubic feet (pcf), CDE is corrected d-exponent, ODE is original d-exponent, and CP is the current pressure of the drilling fluid 136 in the annulus 132 in units of psi. The corrected d-exponent CDE and original d-exponent ODE may be measures of drillability. The ratio of the corrected d-exponent CDE and original d-exponent ODE may be referred to as a d-exponent ratio DR. Further, (0.007 EMW Depth) may be referred to as equivalent hydrodynamic pressure Phy in units of psi. Further still, FP+CP may be referred to as developed required drilling fluid density RDMW in units of pcf. A first model may include Equation (1), which may be considered an empirical model.

Each of the variables in Equation (1) (e.g., depth, EMW, and CDE) is hereinafter referred to as a drilling parameter. Each drilling parameter may be associated with the drilling operations and/or formation 104 surrounding the wellbore 102 being drilled. A value of each drilling parameter may be known, such as being pre-determined by the drilling team, determined directly or indirectly from the drilling sensors 118, and/or determined from other models, some of which are described below. No value of a drilling parameter is required to be determined using a separate well logging system that requires drilling to pause. The previously-described MWD and LWD tools may not be considered separate well logging systems and, thus, may be used to determine a value of a drilling parameter. However, a person of ordinary skill in the art will appreciate that one or more other models not explicitly disclosed below may replace one or more models or be used in addition to one or more models disclosed below without departing from the scope of the disclosure. Further, a person of ordinary skill in the art will appreciate that while a value of a drilling parameter provided below may be known, determined directly or indirectly from drilling sensors 118, or determined from other models at a first depth 152, the value of the drilling parameter may alternatively or additionally be determined using any of these three methods at a second depth 154 without departing from the scope of the disclosure.

Returning to Equation (1), in some embodiments, a value of the depth in Equation (1) may be known based on how much drillstring 110 is deployed downhole during the drilling of the wellbore 102. In some embodiments, a value of the effective drilling fluid density EMW in Equation (1) may be determined as:

$\begin{array}{cc}\mathrm{EMW}=\left(\mathrm{MW}\left(\frac{\mathrm{CCA}}{\mathrm{CRF}}\right)+\mathrm{MW}\right)-\mathrm{BFF},& \mathrm{Equation}\left(2\right)\end{array}$

where MW is mud weight (hereinafter also “mud density,” “density of a drilling fluid,” or “drilling fluid with a density”) in units of pcf, CCA is cutting concentration in the annulus 132 in units of percent, CRF is circulation and rotation factor, and BFF is bit friction factor.

In some embodiments, a value of the cutting concentration in annulus 132 CCA in Equation (2) may be determined as:

$\begin{array}{cc}\mathrm{CCA}=0.0014\frac{\mathrm{RPP}\left({\mathrm{OH}}^2\right)}{\mathrm{GPM}},& \mathrm{Equation}\left(3\right)\end{array}$

where ROP is rate of penetration of the drill bit 114 in units of feet per hour, OH is open hole diameter of the wellbore 102 or drill bit size in units of inches, and GPM is pumping rate of the drilling fluid 136 in units of gallons per minute. A value of the rate of penetration of the drill bit 114 ROP, open hole diameter OH, and pumping rate GPM in Equation (3) may be pre-determined by the drilling team and/or determined directly or indirectly from one or more drilling sensors 118 as the target value and actual value may be different.

In some embodiments, a value of the circulation and rotation factor CRF in Equation (2) may be determined as:

$\begin{array}{cc}\mathrm{CRF}=\frac{\mathrm{GPM}+\mathrm{RPM}}{\left(\mathrm{GPM}-\mathrm{RPM}\right)},& \mathrm{Equation}\left(4\right)\end{array}$

where RPM is rate of rotation of the drillstring 110 in units of revolutions per minute (rpm). A value of the rate of rotation RPM in Equation (4) may be pre-determined by the drilling team and/or determined directly or indirectly from one or more drilling sensors 118 as the target value and actual value may be different.

In some embodiments, a value of the density of the drilling fluid MW in Equation (2) may be indirectly determined using, at least in part, one or more drilling sensors 118 located on the surface of the earth 120 when the drilling fluid 136 is between circulation cycles. In other embodiments, the value of the density of the drilling fluid MW may be indirectly determined downhole using, at least in part, one or more drilling sensors 118 during a circulation cycle when the drilling fluid 136 is downhole. In some embodiments, the value of the density of the drilling fluid MW may be determined based, at least in part, on the American Petroleum Institute (API) Specification 13B. The API Specification 13B may rely on one or more drilling sensors 118, specifically, one or more rheology sensors known as viscometers, to determine viscosity of the drilling fluid 136 at unique rates of rotation RPM, such as 600 rpm and 300 rpm, where the viscosity of the drilling fluid 136 at each RPM may be denoted R3 and R6. Viscosity may be in units of centipoise (cp). The viscosities R3, R6, R300, and/or R600 may be used, at least in part, to determine the plastic viscosity PV, yield point YP, and apparent viscosity of the drilling fluid 136. These viscosities and a pH value determined using a drilling sensor 118 may then be used, at least in part, to determine the value of the density of the drilling fluid MW. Further, in some embodiments, the density of drilling fluid MW may be updated such that the formation pressure FP is also updated. In these embodiments, the density of the drilling fluid MW may be updated in an effort to balance or slightly overbalance the formation pressure FP as the current formation pressure FP may be underbalanced or greatly overbalanced.

Returning to Equation (2), in some embodiments, a value of the bit friction factor BFF in Equation (2) may be determined as:

$\begin{array}{cc}\mathrm{BFF}=\frac{12\left(\mathrm{torq}\right)}{\mathrm{OH}\left(\mathrm{WOB}\right)},& \mathrm{Equation}\left(5\right)\end{array}$

where torq is torque of the drill bit 114 in units of pound-feet and WOB is weight on bit in units of pounds. The value of the torque and weight on bit WOB may be determined directly from drilling sensors 118.

Returning to Equation (1), in some embodiments, a value of the corrected d-exponent CDE in Equation (1) may be determined as:

$\begin{array}{cc}\mathrm{CDE}=\left(\left(\frac{\log \left(\left(\frac{\mathrm{ROP}}{60\mathrm{RPM}}\right)\left(\frac{\mathrm{SPP}+\mathrm{CPM}}{\mathrm{SPP}-\mathrm{GPM}}\right)\right)}{\log \left(\left(\frac{12000\mathrm{WOB}}{1000000\mathrm{OH}}\right)\left(\frac{\mathrm{Torq}+\mathrm{JIF}}{\mathrm{Torq}-\mathrm{JIF}}\right)\right)}\right)\left(\frac{\mathrm{ECD}}{\mathrm{EMW}}\right)\right),& \mathrm{Equation}\left(6\right)\end{array}$

where SPP is standpipe pressure in units of psi, JIF is jet drill bit impact force in units of pounds, and ECD is equivalent circulating density of the drilling fluid 136 in the annulus 132 against the formation 104 in units of pcf. A value of the standpipe pressure SPP may be determined from drilling sensors 118. In some embodiments, a value of the jet drill bit impact force JIF may be determined as:

$\begin{array}{cc}\mathrm{JIF}=\frac{(22\times {10}^{-5}{\mathrm{GPM}}^2\mathrm{MW}\left(1+\mathrm{CCA}+{\left(2\mathrm{CCA}\right)}^{0.5}\right)}{\mathrm{TFA}},& \mathrm{Equation}\left(7\right)\end{array}$

where TFA is total drill bit nozzles flow area in units of square inches. A value of the total drill bit nozzles flow area TFA may be determined as:

$\begin{array}{cc}\mathrm{TFA}=(\frac{3.14}{4}{\left(n1{\left(\frac{d1}{32}\right)}^2+\dots +ni\left(\frac{\mathrm{di}}{32}\right)\right)}^2,& \mathrm{Equation}\left(8\right)\end{array}$

where ni is the count of drill bit nozzles (e.g., 1, 2, 3, etc.) and di is the diameter of the associated drill bit nozzle in units of inches.

A value of the equivalent circulating density ECD in Equation (6) may be determined as:

$\begin{array}{cc}\mathrm{ECD}=\mathrm{EMW}+\left(\left(\left(\frac{0.1}{\mathrm{OH}-\mathrm{OD}}\right)\left(\mathrm{YPc}+\frac{\mathrm{Meffavg}\left(\mathrm{VannC}\right)}{300\left(\mathrm{OH}-\mathrm{OD}\right)}\right)\right)7.481\right),& \mathrm{Equation}\left(9\right)\end{array}$

where OD is outer drillstring diameter in units of inches, YPc is corrected yield point in units of cp, Meffavg is average drilling effective viscosity in units of cp, and VannC is corrected average mud velocity in units of feet per minute (ft/min).

A value of the corrected yield point YPc may be determined as:

$\begin{array}{cc}\mathrm{YPc}=\left(\frac{3\left(\mathrm{YP}+\mathrm{LSYP}\right)}{4\mathrm{YP}}\right),& \mathrm{Equation}\left(10\right)\end{array}$

where LSYP is low shared yield point in units of cp and LSYP=2R3−R6.

A value of the average drilling effective viscosity Meffavg in Equation (9) may be determined as:

$\begin{array}{cc}\mathrm{Meffavg}=0.5\left(\mathrm{Meff}2+\mathrm{Meff}1\right),\mathrm{where}& \mathrm{Equation}\left(11\right)\end{array}$ $\begin{array}{cc}\mathrm{Meff}2=\mathrm{PV}+200\left(\frac{\left(\mathrm{YP}+\mathrm{LSYP}\right)}{\mathrm{YP}}\right)\mathrm{YP}\left(\frac{\mathrm{dc}}{\mathrm{Vann}}\right),& \mathrm{Equation}\left(12\right)\end{array}$ $\begin{array}{cc}\mathrm{Vann}=\mathrm{Va}*\cos \left(\mathrm{HA}\right)+\mathrm{Vct}\sin \left(\mathrm{HA}\right),& \mathrm{Equation}\left(13\right)\end{array}$ $\begin{array}{cc}\mathrm{Va}=\left(\frac{245\mathrm{GPM}}{\mathrm{OH}-\mathrm{OD}}\right),& \mathrm{Equation}\left(14\right)\end{array}$

where OH−OD is hydraulic diameter Dh in units of inches,

$\begin{array}{cc}\mathrm{dc}=0.375{\mathrm{CSF}}^3\sqrt{\left({\mathrm{OH}}^2-{\mathrm{OD}}^2\right)\mathrm{CCA}}+0.1\left(\frac{\mathrm{ROP}}{\mathrm{RPM}}\right),& \mathrm{Equation}\left(15\right)\end{array}$ $\begin{array}{cc}\mathrm{CSF}=\frac{\mathrm{Vct}}{\mathrm{Vann}},& \mathrm{Equation}\left(16\right)\end{array}$ $\begin{array}{cc}\mathrm{Vct}=\frac{0.02\left(\mathrm{ROP}{\mathrm{OH}}^2\right)}{\left({\mathrm{OH}}^2-{\mathrm{OD}}^2\right)},\mathrm{and}& \mathrm{Equation}\left(17\right)\end{array}$ $\begin{array}{cc}\mathrm{Meff}1=0.5\left(\mathrm{PV}+\mathrm{MF}\right).& \mathrm{Equation}\left(18\right)\end{array}$

In Equations (11)-(18), Meff1 is primary average effective mud viscosity in units of cp, Meff2 is secondary average effective mud viscosity in units of cp, de is average drilling cutting size in units of inches, Vann is new average annular velocity in units of ft/min, Va is average mud annular velocity in units of ft/min, Vct is average cuttings transport velocity in units of ft/min, HA is inclination angle of the wellbore 102 in units of degrees, CSF is cuttings shape factor, and MF is funnel viscosity (i.e., the time it takes for one quart of drilling fluid 136 to flow through a Marsh funnel) in units of seconds.

Returning to Equation (1), a value of the original d-exponent ODE may be determined as:

$\begin{array}{cc}\mathrm{ODE}=\frac{\log \left(\frac{\mathrm{ROP}}{60\mathrm{RPM}}\right)}{\log \left(\frac{12000\mathrm{WOB}}{1000000\mathrm{OH}}\right)}.& \mathrm{Equation}\left(19\right)\end{array}$

FIG. 2 displays formation pressure profiles in accordance with one or more embodiments. The first formation pressure profile 200 displays a value of the formation pressure 202 determined using Equation (1) at discrete depths 204 along the wellbore 102 in real time as the wellbore 102 is drilled.

The value of the formation pressure FP 202 determined at each discrete depth 204 (hereinafter, simply “depth”) using Equation (1), which relies on a value of the density of the drilling fluid MW, may be used to determine a value of a mud level drop (hereinafter, also “drilling fluid drop”) in the annulus 132. In some embodiments, the value of the mud level drop MLD, in units of feet, may be determined as:

$\begin{array}{cc}\mathrm{MLD}=\frac{\mathrm{FP}}{0.007\mathrm{EMW}}.& \mathrm{Equation}\left(20\right)\end{array}$

A second model may include Equation (20), which may rely on other models, such as Equations (1) and (2) among others. Further, the second model may be considered an empirical model. If the value of the drilling fluid drop MLD increases between circulation cycles, the increase may be an indicator that the pressure of the drilling fluid 136 is underbalancing the formation pressure and, in turn, the formation fluids may be entering the wellbore 102, which may cause a kick or blowout. If the value of the drilling fluid drop MLD decreases between circulation cycles, the decrease may be an indicator that the pressure of the drilling fluid 136 is greatly overbalancing the formation pressure and, in turn, the formation 104 may have fractured and drilling fluid 136 is now being lost into the formation 104, which may cause lost circulation.

A person of ordinary skill in the art will appreciate that Equation (20) could be used to determine a value of the drilling fluid drop MLD 302 intermittently based on a value of the formation pressure FP 202 determined intermittently (i.e., not in real time) using a well logging system.

Returning to FIG. 2, for comparison, the second formation pressure profile 206 is determined using, at least in part, a well logging system deployed downhole intermittently while drilling is paused.

FIG. 3 displays drilling fluid drop profiles in accordance with one or more embodiments. The first drilling fluid drop profile 300 displays a value of the drilling fluid drop 302 determined using Equation (20) at depths 204 along the wellbore 102 in real time as the wellbore 102 is drilled. For comparison, the second drilling fluid drop profile 304 is determined using, at least in part, a well logging system deployed downhole intermittently while drilling is paused.

To reduce the likelihood of a stuck pipe, kick, blowout, and/or lost circulation and, thus, maintain well control, the density and, in some embodiments, the volume of the drilling fluid 136 may be adjusted by the drilling team while the wellbore 102 is being drilled to balance or slightly overbalance the formation pressure. To do so, the drilling team may monitor the value of the formation pressure FP and the value of the drilling fluid drop MLD in real time and adjust the density and, in some embodiments, the volume of the drilling fluid 136 accordingly. This process may be repeated in real time during the drilling of the wellbore 102 deeper into the formation 104.

In some embodiments, the volume of the drilling fluid 136 may be increased to mitigate a kick (i.e., mitigate formation fluids entering the wellbore 102). The volume of the drilling fluid 136 that mitigates a kick may be referred to as “kill-weight mud” or “kill mud.” In these embodiments, the volume of the drilling fluid RKM, in units of barrel (bbl), may be determined where:

$\begin{array}{cc}\mathrm{RKM}=\mathrm{MLD}\left(\frac{{\mathrm{OH}}^2-{\mathrm{OD}}^2}{1029.4}\right).& \mathrm{Equation}\left(21\right)\end{array}$

FIG. 4 displays drilling fluid volume profiles in accordance with one or more embodiments. The first drilling fluid volume profile 400 displays a value of the volume of the drilling fluid RKM 402 using Equation (21) at depths 204 along the wellbore 102 in real time as the wellbore 102 is being drilled. For comparison, a second drilling fluid volume profile 404 is determined using, at least in part, a well logging system deployed downhole intermittently while drilling is paused.

A person of ordinary skill in the art will appreciate that if a value of the drilling fluid drop MLD 302 were determined intermittently (i.e., not in real time), Equation (21) could be used to determine a value of the volume of the drilling fluid RKM 402 intermittently.

FIG. 5 describes a method of adjusting a density of a drilling fluid in accordance with one or more embodiments. In step 500, a wellbore 102 is drilled to a first depth 152 within a formation 104. The wellbore 102 may be drilled using a drilling system 100 as described relative to FIG. 1. In some embodiments, the wellbore 102 may be drilled blind. Further, the wellbore 102 may be drilled using a drilling fluid 136 with a first density. In some embodiments, the first density of the drilling fluid 136 may correspond to a value of the first density pre-determined by the drilling team, especially, if drilling to the first depth 152 corresponds to the first circulation cycle of the drilling fluid 136. In other embodiments, the first density of the drilling fluid 136 may correspond to the value of the drilling parameter MW indirectly determined using one or more drilling sensors 118 located on the surface of the earth 120 when the drilling fluid 136 is between circulation cycles. In still other embodiments, the first density of the drilling fluid 136 may correspond to the value of the drilling parameter MW indirectly determined downhole using, at least in part, one or more drilling sensors 118 during a circulation cycle when the drilling fluid 136 is downhole. As such, the first density of the drilling fluid 136 may be different than the original density of the drilling fluid 136.

Further, in some embodiments, the wellbore 102 may be drilled to the first depth 152 additionally using a first volume of the drilling fluid 136. Similar to the first density of the drilling fluid 136, the first volume may be pre-determined, determined above the surface of the earth 120, or determined downhole. As such, the first volume of the drilling fluid 136 may be different than the original volume of the drilling fluid 136.

Further still, in some embodiments, the wellbore 102 may be drilled to the first depth 152 additionally using the drilling system 100 with a first value of a first drilling parameter. The first drilling parameter may be any drilling parameter previously discussed that is associated to the drilling system 100. For example, the first drilling parameter may be the rate of rotation of the drillstring 110 RPM or pumping rate of the drilling fluid GPM.

Steps 505, 510, and 515 are performed while the wellbore 102 is being drilled.

In step 505, a first value of each drilling parameter associated to the first depth 152 is obtained from the drilling system 100. A drilling parameter may be any drilling parameter used within Equations (1)-(21). In some embodiments, one or more of the drilling parameters may be a rheology parameter. The first value of each drilling parameter may be known, such as being pre-determined by the drilling team, determined directly or indirectly from drilling sensors 118, and/or determined from one or more models, such as, but not limited to, Equations (1)-(21). As previously described, drilling sensors 118 may include downhole drilling sensors and surface drilling sensors. One or more downhole drilling sensors and/or one or more surface drilling sensors may be a rheology sensor or a hydraulic sensor.

Because step 505 is being performed while the wellbore 102 is being drilling, drilling of the wellbore 102 need not pause for any value of a drilling parameter to be obtained.

In step 510, a first value of a formation pressure FP 202 is determined. The first value of the formation pressure FP 202 may be determined using the first value of one or more drilling parameters obtained in step 505, a value of the first density of the drilling fluid 136 used in step 500, and a first model. The first model may include Equation (1) as well as any other model used to determine any of the values of the drilling parameters within Equation (1).

In step 515, a first value of a drilling fluid drop MLD 302 is determined. The first value of the drilling fluid drop 302 may be determined using the first value of the formation pressure FP 202 determined in step 510 and a second model. In some embodiments, determining the first value of a drilling fluid drop MLD 302 may further rely on the first value of one or more drilling parameters obtained in step 505. The second model may include Equation (20) as well as any other model used to determine any of the values of the drilling parameters within Equation (20).

In step 520, the wellbore 102 is drilled to a second depth 154 within the formation 104. The wellbore 102 may continue to be drilled using the drilling system 100 as described relative to FIG. 1. Further, the wellbore 102 may be drilled using the drilling fluid 136 with a second density. The second density may be adjusted based, at least in part, on the first value of the drilling fluid drop MLD 302 determined in step 515.

For example, as previously described, if the first value of the drilling fluid drop MLD 302 has increased relate to a previously-determined value of the drilling fluid drop MLD 302, the increase may indicate that the pressure of the drilling fluid 136 is underbalancing the formation pressure and, in turn, formation fluids are entering the wellbore 102, which may cause a kick or blowout. In these cases, the second density of the drilling fluid 136 may need to be increased relative to the first density of the drilling fluid 136 to balance or slightly overbalance the formation pressure.

If the first value of the drilling fluid drop MLD 302 has decreased relative to the previously-determined value of the drilling fluid drop MLD 302, the decrease may indicate that the pressure of the drilling fluid 136 is greatly overbalancing the formation pressure and, in turn, the formation 104 may have fractured and drilling fluid 136 is being lost into the formation 104, which may cause lost circulation. In these cases, the second density of the drilling fluid 136 may need to be decreased relative to the first density of the drilling fluid 136 to balance or slightly overbalance the formation pressure.

In some embodiments, the wellbore 102 may continue to be drilled to the second depth 154 additionally using a second volume of the drilling fluid 136. That is, the volume of the drilling fluid 136 may be adjusted in real time during drilling. In some embodiments, the second volume of the drilling fluid 136 may be based on the first value of the formation pressure FP 202 and/or the first value of the drilling fluid drop MLD 302.

In other embodiments, the wellbore 102 may continue to be drilled to the second depth 154 additionally using the drilling system with a second value of the first drilling parameter. That is, the value of the first drilling parameter may be adjusted in real time during drilling.

Steps 500, 505, 510, 515, and 520 may be repeated in real time as the wellbore 102 continues to be drilled to deeper depths 204 within the formation 104 until the drilling target within the hydrocarbon reservoir is reached or the presence of hydrocarbons is established. As such, in some embodiments, a first formation pressure profile 200 may be determined using the value of the formation pressure FP 202 associated to two or more depths 204. FIG. 2 displays a first formation pressure profile 200. Further, in some embodiments, a drilling fluid drop profile 300 may be determined using the value of the drilling fluid drop MLD 302 associated to two or more depths 204. FIG. 3 displays a first drilling fluid drop profile 300. Further still, in some embodiments, a first drilling fluid volume profile 400 may be determined using the value of the volume of the drilling fluid RKM 402 associated to two or more depths 204. The first formation pressure profile 200, first drilling fluid drop profile 300, and/or first drilling fluid volume profile 400 may be used by the drilling team to monitor the value of the formation pressure FP 202, the value of the drilling fluid drop MLD 302, and/or the value of the volume of the drilling fluid RKM 402 in real time. In turn, the drilling team may use the first profiles to adjust the density and, in some embodiments, the volume of the drilling fluid 136 in real time.

FIG. 6 depicts a block diagram of a computer system 142 used to provide computational functionalities associated with described algorithms, methods, functions, processes, flows, and procedures as described in this disclosure, according to one or more embodiments. As noted in FIG. 1, the computer system 142 may be communicably coupled to the drilling system 100 such that the computer system 142 may perform steps 505, 510, and 515 as described in FIG. 5. The illustrated computer 142 is intended to encompass any computing device such as a server, desktop computer, laptop/notebook computer, wireless data port, smart phone, personal data assistant (PDA), tablet computing device, one or more processors within these devices, or any other suitable processing device, including both physical or virtual instances (or both) of the computing device. Additionally, the computer 142 may include a computer that includes an input device, such as a keypad, keyboard, touch screen, or other device that can accept user information, and an output device that conveys information associated with the operation of the computer 142, including digital data, visual, or audio information (or a combination of information), or a GUI.

The computer 142 can serve in a role as a client, network component, a server, a database or other persistency, or any other component (or a combination of roles of a computer system for performing the subject matter described in the instant disclosure. The illustrated computer 142 is communicably coupled with a network 630. In some implementations, one or more components of the computer 142 may be configured to operate within environments, including cloud-computing-based, local, global, or other environment (or a combination of environments).

At a high level, the computer 142 is an electronic computing device operable to receive, transmit, process, store, or manage data and information associated with the described subject matter. According to some implementations, the computer 142 may also include or be communicably coupled with an application server, e-mail server, web server, caching server, streaming data server, business intelligence (BI) server, or other server (or a combination of servers).

The computer 142 can receive requests over network 630 from a client application (for example, executing on another computer 142) and responding to the received requests by processing the said requests in an appropriate software application. In addition, requests may also be sent to the computer 142 from internal users (for example, from a command console or by other appropriate access method), external or third-parties, other automated applications, as well as any other appropriate entities, individuals, systems, or computers.

Each of the components of the computer 142 can communicate using a system bus 603. In some implementations, any or all of the components of the computer 142, both hardware or software (or a combination of hardware and software), may interface with each other or the interface 604 (or a combination of both) over the system bus 603 using an application programming interface (API) 612 or a service layer 613 (or a combination of the API 612 and service layer 613. The API 612 may include specifications for routines, data structures, and object classes. The API 612 may be either computer-language independent or dependent and refer to a complete interface, a single function, or even a set of APIs. The service layer 613 provides software services to the computer 142 or other components (whether or not illustrated) that are communicably coupled to the computer 142. The functionality of the computer 142 may be accessible for all service consumers using this service layer. Software services, such as those provided by the service layer 613, provide reusable, defined business functionalities through a defined interface. For example, the interface may be software written in JAVA, C++, or other suitable language providing data in extensible markup language (XML) format or another suitable format. While illustrated as an integrated component of the computer 142, alternative implementations may illustrate the API 612 or the service layer 613 as stand-alone components in relation to other components of the computer 142 or other components (whether or not illustrated) that are communicably coupled to the computer 142. Moreover, any or all parts of the API 612 or the service layer 613 may be implemented as child or sub-modules of another software module, enterprise application, or hardware module without departing from the scope of this disclosure.

The computer 142 includes an interface 604. Although illustrated as a single interface 604 in FIG. 6, two or more interfaces 604 may be used according to particular needs, desires, or particular implementations of the computer 142. The interface 604 is used by the computer 142 for communicating with other systems in a distributed environment that are connected to the network 630. Generally, the interface 604 includes logic encoded in software or hardware (or a combination of software and hardware) and operable to communicate with the network 630. More specifically, the interface 604 may include software supporting one or more communication protocols associated with communications such that the network 630 or interface's hardware is operable to communicate physical signals within and outside of the illustrated computer 142.

The computer 142 includes at least one computer processor 605. Although illustrated as a single computer processor 605 in FIG. 6, two or more processors may be used according to particular needs, desires, or particular implementations of the computer 142. Generally, the computer processor 605 executes instructions and manipulates data to perform the operations of the computer 142 and any algorithms, methods, functions, processes, flows, and procedures as described in the instant disclosure.

The computer 142 also includes a memory 606 that holds data for the computer 142 or other components (or a combination of both) that can be connected to the network 630. For example, memory 606 can be a database storing data consistent with this disclosure. Although illustrated as a single memory 606 in FIG. 6, two or more memories may be used according to particular needs, desires, or particular implementations of the computer 142 and the described functionality. While memory 606 is illustrated as an integral component of the computer 142, in alternative implementations, memory 606 can be external to the computer 142.

The application 607 is an algorithmic software engine providing functionality according to particular needs, desires, or particular implementations of the computer 142, particularly with respect to functionality described in this disclosure. For example, application 607 can serve as one or more components, modules, applications, etc. Further, although illustrated as a single application 607, the application 607 may be implemented as multiple applications 607 on the computer 142. In addition, although illustrated as integral to the computer 142, in alternative implementations, the application 607 can be external to the computer 142.

There may be any number of computers 142 associated with, or external to, a computer system containing a computer 142, wherein each computer 142 communicates over network 630. Further, the term “client,” “user,” and other appropriate terminology may be used interchangeably as appropriate without departing from the scope of this disclosure. Moreover, this disclosure contemplates that many users may use one computer 142, or that one user may use multiple computers 142.

Although only a few example embodiments have been described in detail above, those skilled in the art will readily appreciate that many modifications are possible in the example embodiments without materially departing from this invention. Accordingly, all such modifications are intended to be included within the scope of this disclosure as defined in the following claims.

Claims

1. A method comprising: drilling, using a drilling system, a wellbore to a first depth within a formation using, at least in part, a drilling fluid with a first density;while drilling the wellbore: obtaining, from the drilling system, a first value of each of a plurality of drilling parameters associated to the first depth,determining, using a first model, a first value of a formation pressure based, at least in part, on the first value of each of the plurality of drilling parameters and a value of the first density of the drilling fluid, anddetermining, using a second model, a first value of a drilling fluid drop based, at least in part, on the first value of the formation pressure; anddrilling, using the drilling system, the wellbore to a second depth within the formation using, at least in part, the drilling fluid with a second density based, at least in part, on the first value of the drilling fluid drop.

2. The method of claim 1, further comprising determining a formation pressure profile based, at least in part, on the first value of the formation pressure associated to the first depth and a second value of the formation pressure associated to the second depth.

3. The method of claim 1, further comprising determining a drilling fluid drop profile based, at least in part, on the first value of the drilling fluid drop associated to the first depth and a second value of the drilling fluid drop associated to the second depth.

4. The method of claim 1, wherein drilling the wellbore comprises blind drilling the wellbore.

5. The method of claim 1, wherein drilling the wellbore to the first depth within the formation further comprises using, at least in part, the drilling fluid with a first volume.

6. The method of claim 5, wherein drilling the wellbore to the second depth within the formation further comprises using, at least in part, the drilling fluid with a second volume.

7. The method of claim 1, wherein drilling the wellbore to the first depth within the formation further comprises using the drilling system with a first value of a first drilling parameter, wherein the plurality of drilling parameters comprises the first drilling parameter.

8. The method of claim 7, wherein drilling the wellbore to the second depth within the formation further comprises using the drilling system with a second value of the first drilling parameter.

9. The method of claim 1, wherein the plurality of drilling parameters comprises a rheology parameter.

10. The method of claim 1, wherein determining the first value of the formation pressure comprises: determining a first value of a d-exponent and a first value of a corrected d-exponent based, at least in part, on the first value of each of the plurality of drilling parameters;determining, using the first model, the first value of the formation pressure based, at least in part, on the first value of the d-exponent, the first value of the corrected d-exponent, and the value of the first density of the drilling fluid.

11. A system comprising: a drilling system configured to: drill a wellbore to a first depth within a formation using, at least in part, a drilling fluid with a first density; anda computer system configured to, while drilling the wellbore: receive, from the drilling system, a first value of each of a plurality of drilling parameters associated to the first depth,determine, using a first model, a first value of a formation pressure based, at least in part, on the first value of each of the plurality of drilling parameters and a value of the first density of the drilling fluid, anddetermine, using a second model, a first value of a drilling fluid drop based, at least in part, on the first value of the formation pressure,wherein the drilling system is further configured to drill the wellbore to a second depth within the formation using, at least in part, the drilling fluid with a second density based, at least in part, on the first value of the drilling fluid drop.

12. The system of claim 11, wherein the drilling system comprises a plurality of drilling sensors.

13. The system of claim 12, wherein each of the plurality of drilling sensors is configured to obtain the first value of each of the plurality of drilling parameters.

14. The system of claim 12, wherein the plurality of drilling sensors comprises a rheology sensor.

15. The system of claim 12, wherein the plurality of drilling sensors comprises a surface drilling sensor.

16. The system of claim 12, wherein the plurality of drilling sensors comprises a downhole drilling sensor.

17. The system of claim 12, wherein the plurality of drilling sensors comprises a hydraulic sensor.

18. The system of claim 11, wherein the drilling system is configured to blind drill the wellbore.

19. The system of claim 11, wherein the computer system is further configured to determine a formation pressure profile based, at least in part, on the first value of the formation pressure associated to the first depth and a second value of the formation pressure associated to the second depth.

20. The system of claim 11, wherein the computer system is further configured to determine a drilling fluid drop profile based, at least in part, on the first value of the drilling fluid drop associated to the first depth and a second value of the drilling fluid drop associated to the second depth.