WO2016040310A1

WO2016040310A1 - Systems and methods for detection of an influx during drilling operations

Info

Publication number: WO2016040310A1
Application number: PCT/US2015/048922
Authority: WO
Inventors: Eric Van Oort; Ali Karimi VAJARGAH; Besmir B. HOXHA
Original assignee: Board Of Regents, The University Of Texas System
Priority date: 2014-09-09
Filing date: 2015-09-08
Publication date: 2016-03-17

Abstract

In some embodiments, a method for drilling operations includes indicating an influx event by detecting that a flow rate of a drilling fluid out of an annulus is increasing, and determining a location and an orientation of a drill bit in a wellbore at the influx event. Based on determining the influx event occurred in a gravitationally dominant flow section of the wellbore, the method further includes obtaining an annular pressure profile for a downhole pressure sensor, and comparing the obtained annular pressure profile with a simulated annular pressure profile. The simulated annular pressure profile is based on a set of multi-phase flow equations.

Description

SYSTEMS AND METHODS FOR DETECTION OF AN INFLUX DURING

DRILLING OPERATIONS TECHNICAL FIELD

[0001] The present disclosure relates generally to subterranean operations and, more particularly, to systems and methods for detection of an influx during drilling operations.

BACKGROUND

[0002] In typical drilling operations, a drill bit is used to drill though a variety of formations. Conventional drilling systems are open systems with the annulus being open to the atmosphere. As the well is drilled, fluid is pumped down the drill string, though the drill bit, and back through an annulus between the drill string and the sidewall of the wellbore or the casing to the surface. At the surface, the drilling fluid returns to pits for further processing and reuse.

[0003] Various hazards may be faced while drilling, especially in complex environments. For example, gasses and/or fluids may be encountered that are not the target material of the drilling operation. Often these gasses and/or fluids, such as oils or brines, may be at a high pressure and may contaminate the target material and/or create a "kick" that rises to the surface and could result in a "blow-out" that can become an unsafe and costly situation. The flow of fluids and/or gasses from the formation into the wellbore is referred to as "gas/fluid influx," an "influx," or an "influx event."

[0004] Managed pressure drilling (MPD) is a type of drilling that uses a closed system to control the annular pressure profile during the drilling operation. The annulus may not be open to the atmosphere. MPD operations may use a rotating control device (RCD), an automatic choke, and mud pumps to create a closed system. MPD operators use the RCD, choke, and pump to control annulus pressure and maintain an approximately constant bottomhole pressure during drilling operations. To control the annulus pressure, the pressure of a drilling fluid that flows through an annulus is maintained between the fracture pressure and the pore pressure, also referred to as "mud window," "mud pressure window," or "drilling window." Fracture pressure is the pressure that when applied may cause a formation to fail in tension whereby fractures are opened and the drilling fluid may become lost. Fracture pressure may be expressed as a gradient. Pore pressure is the pressure of the fluid contained within the pore space of a rock maintained at depth. Wellbore pressure is the pressure maintained in the wellbore to balance or exceed the pore pressure to prevent influxes. A certain density of fluid is required to generate the necessary wellbore pressure. The wellbore pressure may be increased by pressure applied at surface in an MPD system. One of the most important challenges associated with drilling wells is negotiating the window between fracture pressure and pore pressure with sufficient wellbore pressure.

[0005] Blow-out prevention and formation gas influx control are a concern in any drilling operation. Detecting when a gas influx event, or kick, occurs is difficult and early detection can be important to determine the appropriate action. For example, in some drilling operations, the response to a gas influx event is to shut the well in on the blow-out preventers (BOPs). However, detection of a gas influx based on typical procedures, such as monitoring pit gain or pump pressure, may not identify the gas influx until that gas influx has developed to a size large enough to complicate well operations. SUMMARY

[0006] In some embodiments, a method for drilling operations includes indicating an influx event by detecting that a flow rate of a drilling fluid out of an annulus is increasing, and determining a location and an orientation of a drill bit in a wellbore at the influx event. Based on determining the influx event occurred in a gravitationally dominant flow section of the wellbore, the method further includes obtaining an annular pressure profile for a downhole pressure sensor, and comparing the obtained annular pressure profile with a simulated annular pressure profile. The simulated annular pressure profile is based on a set of multi-phase flow equations. BRIEF DESCRIPTION OF THE DRAWINGS

[0007] For a more complete understanding of the present disclosure and its features and advantages, reference is now made to the following description, taken in conjunction with the accompanying drawings, which may include drawings that are not to scale and wherein the same reference numbers indicate the same features, in which:

[0008] FIGURE 1 illustrates an elevation view of an example embodiment of a drilling system in accordance with some embodiments of the present disclosure;

[0009] FIGURE 2 illustrates exemplary simulated pressure profile curves as a function of time in accordance with some embodiments of the present disclosure;

[0010] FIGURE 3 illustrates an exemplary simulated pressure derivative curves as a function of time in accordance with some embodiments of the present disclosure;

[001 1] FIGURE 4 illustrates exemplary pressure profile curves for a gas influx as a function of time in accordance with some embodiments of the present disclosure; and [0012] FIGURE 5 illustrates a flow chart of an example method for detection of an influx during drilling operations in accordance with some embodiments of the present disclosure.

DETAILED DESCRIPTION

[0013] The present disclosure is directed to a system and method for early detection of an influx during drilling operations. In some embodiments, the system and method may include results from a simulation that is conducted before or while drilling a new wellbore or section of an existing wellbore. The simulation results may be presented in the form of graphs or look up tables to enable timely detection of an influx. The simulation results may be compared to actual drilling results to identify an influx. The current disclosure may improve on prior simplified methods or commercial kick simulators to obtain the annular pressure profile and maximum casing pressure (casing peak pressure) that may result in unrealistic values and over-designing drilling operations.

[0014] Early influx detection in may depend on many parameters, such as wellbore geometry, type of drilling fluid, flow rate, well depth, formation over-balance, size of the kick, and other suitable parameters. In some embodiments, the annular pressure profile and maximum casing pressure may be predicted in real-time to generate increasingly accurate values.

[0015] The present disclosure discusses aspects of the invention relative to managed pressure drilling (MPD) operations. However, embodiments of the present disclosure may be utilized to detect an influx for any suitable method of drilling operation.

[0016] Constant bottom-hole pressure (CBHP) operation is one variant of MPD. Bottom-hole pressure (BHP) is the pressure at the bottom of a well, and may also be referred to as bottom-hole circulating pressure (BHCP) when drilling fluid is circulating in the wellbore. In MPD-CBHP operations, a drilling fluid may be utilized with a lower density than non-MPD methods. By controlling the annulus backpressure, a constant BHP may be maintained. Some benefits MPD-CBHP operations can include a faster response to the influx (with associated safety benefits) and a time and cost savings compared other drilling approaches. Further, MPD-CBHP operations may allow a deeper setting of casing shoes and may ultimately reduce the total number of casing strings required for reaching well total depth. Lowering the number of casing strings may allow a larger wellbore that may improve the ability of the wellbore to reach productivity objectives.

[0017] In some embodiments, a simulator generates simulated results based on actual and estimated drilling operation parameters, and the actual well response may be compared with simulated results to detect an influx event. Thus, influx detection may be improved by improving simulation methods for accurate comparison with actual well results from drilling operations. Simulations of the present disclosure may be based on two-phase flow equations and may be based on mass, energy, and/or momentum conservation. Simulations may produce annular pressure profiles that are used for comparisons. The present disclosure may allow for the optimal response to an influx event in a timely, convenient, and accurate manner.

[0018] FIGURE 1 illustrates an elevation view of an example embodiment of drilling system 100 in accordance with some embodiments of the present disclosure. Drilling system 100 is configured to provide drilling into one or more geological formations, in accordance with some embodiments of the present disclosure. Drilling system 100 is configured to provide managed pressure drilling (MPD) operations as discussed above. However, embodiments of the present disclosure may be utilized with other drilling systems, such as a drilling system with an annulus that is open to the atmosphere.

[0019] Drilling system 100 may include well site 102 and well surface 104. In some embodiments, well site 102 may include equipment that may have various characteristics and features associated with an offshore platform, a land drilling rig, a drill ship, semi- submersibles, and drilling barges. Various types of drilling equipment such as rotating control device (RCD) 106, blow out preventer (BOP) 108, mud pumps 110, mud tanks 112, automatic choke 1 14, flow meters 160 and/or any other suitable equipment may be located on well surface 104 and/or well site 102.

[0020] Drilling system 100 may include RCD 106 to provide assistance in pressurizing annulus 116 by adjusting automatic choke 114. RCD 106 may be fluidically connected or coupled via piping to and configured to close around drill string 1 18 and the top of casing string 120. In some embodiments, RCD 106 may additionally be connected via piping to other components of drilling system 100. RCD 106 closing around the exterior of drill string 118 isolates annulus 116 and allows annulus 116 to be pressurized. RCD 106 is a pressure-control device that may form a seal around drill string 118 while drill string 1 18 rotates. RCD 106 may be configured to control hydrocarbons or a mixture of hydrocarbons and other wellbore fluids and prevent their release to the atmosphere. RCD 106 may be rated to withstand a particular pressure (e.g., psi) and may be coupled to drill string 118 and/or the top of casing string 120. RCD 106 may assist with pressurizing annulus 1 16 by trapping pump pressure (from mud pumps 1 10) against RCD 106 or may be configured to allow active application of pressure to annulus 116 by use of a separate pumping system.

[0021] BOP 108 may be fluidically connected or coupled via piping to RCD 106. In some embodiments, BOP 108 may additionally be connected via piping to other components of drilling system 100. In some embodiments, RCD 106 may be located proximate to BOP 108. In some sub-sea drilling embodiments, RCD 106 may be located at well surface 104 while BOP 108 may be located at ocean floor 124 or any other suitable location. BOP 108 is one or more valves at the top of drill string 118, casing string 120, and/or wellbore 122 that may be closed if formation fluid pressures are excessive. By closing BOP 108, personnel at well site 102 may regain control of formation fluids, and procedures may be initiated to take other suitable action to control formation fluids. BOP 108 may be a valve of any of a variety of styles, sizes and pressure ratings. BOP 108 may be controlled by signals from computing system 150 or any other suitable control mechanism. BOP 108 may be operated remotely via hydraulic actuators, operated manually, or operated via any other suitable method.

[0022] Automatic choke 1 14 may be located proximate to RCD 106. In some embodiments, automatic choke 1 14 may be fluidically connected or coupled via piping to RCD 106. In some embodiments, automatic choke 114 may additionally be connected via piping to other components of drilling system 100. Automatic choke 114 may be a valve or series of valves used to adjust the pressure of drilling fluid 126. Adjustments to pressure may be based on opening and closing one or more valves in automatic choke 114. Automatic choke 1 14 may be a valve of any of a variety of styles, sizes and pressure ratings. Automatic choke 114 may be controlled by signals from computing system 150 or any other suitable control mechanism. Automatic choke 1 14 may be operated remotely via hydraulic actuators or operated via any other suitable method.

[0023] In some embodiments, RCD 106 and automatic choke 1 14 may be referred to as MPD manifold 1 2. MPD manifold 152 may be installed in parallel with other drilling fluid flow lines so that other types of drilling may be employed when MPD operations are not utilized. In this case, additional circulation methods as well as circulation through MPD manifold 152 may be employed. Annulus pressure may be applied to wellbore 122 at any time when MPD manifold 152 is utilized.

[0024] Mud tanks 1 12 may be used to store drilling fluid 126 that circulates through drilling system 100. Mud tanks 112 may also be referred to as "mud pits" or "pits." Mud tanks 112 may be fluidically connected or coupled via piping to automatic choke 114 and/or mud pumps 110. In some embodiments, mud tanks 1 12 may additionally be connected via piping to other components of drilling system 100. Mud tanks 1 12 may be one or more open-top containers, made of steel or other suitable material. The amount of drilling fluid 126 in mud tanks 112 may be monitored and communicated to personnel, computing system 150, or other suitable control mechanism. Additionally, mud tanks 1 12 may include temperature sensors, pressure sensors, filters, alarms, flow rate meters, or any other equipment suitable for monitoring, maintaining, and controlling drilling fluid 126 in mud tanks 112.

[0025] Mud pumps 110 circulate drilling fluid 126 through various components and subsystems of drilling system 100. Mud pumps 1 10 are fluidically connected or coupled via piping to RCD 106 and/or mud tanks 112. In some embodiments, mud pumps 110 may additionally be connected via piping to other components of drilling system 100. Mud pumps 1 10 may be configured to pump drilling fluid 126 from mud tanks 1 12 to flow down drill string 118. Mud pump 1 10 may include one or more pumps in various configurations. For example, mud pumps 110 may be configured in parallel or may be configured such that one pump is designated as an operating tower pump while additional pumps are designated as standby pumps. Thus, the operating pump normally pumps fluid, while the standby pump remains in standby in case the operating pump fails or another system condition requires the use of the standby pump. In alternate embodiments, mud pumps 110 are configured in series or a single pump is utilized. Mud pumps 110 may additionally include temperature sensors, flow rate meters, pressure sensors, filters, alarms, or any other suitable components to allow for monitoring and control of mud pumps 110. . Further, in some embodiments, mud pumps 110 may include an annular backpressure pump configured to provide active pressure to annulus 116.

[0026] Mud pumps 110 may be variable speed, thus allowing variable flow and/or pressure, or fixed speed pumps. Mud pumps 106 may be configured to maintain a consistent flow such as gallons per minute (gpm or gal/min). Further, mud pumps 110 may be particular horsepower (hp) pumps. Multiple flow rates may be identified for any drilling configuration or design. As example, a particular drilling configuration or design may specify a flow rate for mud pumps 110 of approximately 300 gpm to maintain proper wellbore cleaning. The maximum available flow rate for mud pumps 1 10 may be specified at approximately 800 gpm due to limitations of mud pumps 1 10. Given these parameters, a particular drilling configuration or design may specify an initial flow rate of approximately 500 gpm for mud pumps 1 10.

[0027] Flow meters 160 may include one or more mass flow meters or other types of flow meters configured to measure the flow rate of drilling fluid 126. Flow meters 160 may be fluidically connected or coupled via piping to automatic choke 114 and mud tanks 1 12, or any other suitable equipment. Flow meters 160 may measure the mass per unit time (e.g., kilograms per second) flowing through drilling system 100. Flow meters 160 may be rated with a specific accuracy and high-accuracy flow meters may be utilized in some embodiments. For example, flow meters 160 may have an accuracy of approximately +/- 5%. Flow meters 160 may be configured to monitor the flow rate out of annulus 1 16. In some embodiments, additional flow meters 160 may be configured to monitor the flow rate into drill string 118.

[0028] Drilling fluid 126 may circulate through drilling system 100 at a specified flow rate. Drilling fluid 126 may have varied physical properties based on the configuration or design of drilling operations. For example, drilling fluid 126 may be a water-based, such as water-based mud (WBM), with a density (or "mud weight") of approximately 12.6 pounds per gallon (ppg) or a non-aqueous fluid (NAF), such as oil- based mud (OBM) or synthetic-based mud (SBM). Pressure variation in SBM may be less pronounced than in WBM for the same size of a kick. In some embodiments, simulations may be designed to simulate a worst-case situation and thus, may be executed based on WBM properties and then extended to SBM properties.

[0029] Drilling system 100 may include computing system 150. Computing system 150 may be communicatively coupled to any component of drilling system 100 and configured to control, monitor, maintain, or perform any other suitable function. Computing system 150 may include any instrumentality or aggregation of instrumentalities operable to compute, classify, process, transmit, receive, store, display, record, or utilize any form of information, intelligence, or data. For example, computing system 150 may include one or more personal computers, storage devices, servers, or any other suitable device and may vary in size, shape, performance, functionality, and price. Computing system 150 may include random access memory (RAM), one or more processing resources, such as a central processing unit (CPU) or hardware or software control logic, or other types of volatile or non-volatile memory. Additional components of computing system 150 may include one or more disk drives, one or more network ports for communicating with external devices, one or more input/output (I/O) devices, such as a keyboard, a mouse, or a video display. Computing system 150 may be configured to permit communication over any type of network, such as a wireless network, a local area network (LAN), or a wide area network (WAN) such as the Internet. Furthermore, computing system 150 may be located in any suitable enclosure, and may be located on well surface 104, on a ship, on shore, or in any other suitable location.

[0030] Drilling system 100 may include drill string 118 associated with drill bit 128 that may be used to form a wide variety of wellbores or bore holes such as wellbore 122. Drill string 1 18 includes drill bit 128 as a part of bottom-hole assembly (BHA) 130. BHA 130 may be formed from a wide variety of components configured to form a wellbore 122. For example, components of BHA 130 may include, but are not limited to, drill bits (e.g., drill bit 128), drill collars, rotary steering tools, directional drilling tools, downhole drilling motors, reamers, hole enlargers or stabilizers. The number of components, such as drill collars and different types of components included in BHA 130, may depend upon anticipated downhole drilling conditions and the type of wellbore that is expected to be formed by drill string 1 18 and drill bit 128. For example, BHA 130 may include a drill collar with a length of approximately 500 feet.

[0031] In some embodiments, drill string 118 may include one or more downhole sensors 162 located periodically along drill string 118. Downhole sensors 162 may be pressure sensors, temperature sensors, and/or any other sensor that provides information that may be used to monitor and control drilling operations. Information from downhole sensors 162 is transferred to well surface 104 by cables, wirelessly, or in any other suitable method. For example, wired drill pipe (WDP) technology allows for data transfer between downhole sensors 162 and/or tools in BHA 130 and well surface 104. Using WDP, downhole measurements may be transferred in real-time to the well surface 104 during drilling operations. In some embodiments, WDP may consist of high strength coaxial cables and/or low-loss inductive cables with signal repeaters placed periodically along drill string 118. For example, downhole sensors 162 may be pressure sensors to monitor the annular pressure at different locations along drill string 118 and transmit readings using WDP technology.

[0032] Wellbore 122 may be defined in part by casing string 120 that may extend from well surface 104 to a selected downhole location. Portions of wellbore 122 as shown in FIGURE 1 that do not include casing string 120 may be described as "open hole." Casing string 120 may include multiple strings linked together to reach casing setting depth. The bottom of casing string 120 at the casing setting depth may be referred to as "casing shoe," such as casing shoe 148. For example, casing string 120 may have a casing setting depth of approximately 9,000 feet.

[0033] Various types of drilling fluid 126 may be pumped from well surface 104 through drill string 1 18 to attached drill bit 128. Such drilling fluids 126 may be directed to flow from drill string 118 to respective nozzles included in drill bit 128. The drilling fluid may be circulated back to well surface 104 through annulus 116 defined in part by outside diameter 132 of drill string 118 and inside diameter 134 of wellbore 122. Inside diameter 134 may be referred to as the "sidewall" of wellbore 122. Annulus 116 may also be defined by outside diameter 132 of drill string 118 and inside diameter 136 of casing string 120.

[0034] In some embodiments, drilling fluid 126 circulates down drill string 118 and through drill bit 128 to annulus 1 16, then from annulus 1 16 through BOP 108. Drilling fluid 126 circulates through RCD 106 and though automatic choke 114 to mud tanks 112. Mud pumps 110 may circulate drilling fluid 126 out of mud tanks 112 and back to drill string 1 18 through RCD 106 and BOP 108. [0035] In some embodiments, drilling system 100 is located in area 138 that includes ocean floor 124, layers 140, productive formation 142, and target reservoir 144. Reservoir 144 may be any geological formation targeted for production. For example, reservoir 144 may contain oil, gas, or any other targeted material. Layers 140 represent geological layers of area 138. Area 138 may have any number, composition, and/or arrangement of layers 140. Different layers 140a, 140b, and 140c may have different densities, thicknesses, or other characteristics that may affect drilling operations. In the illustrated embodiment, layer 140c includes productive formation 142. Productive formation 142 may include gas, water, brine, oil, or any other gas or fluid. For example, productive formation 142 may represent a high pressure gas bearing zone. Productive formation 142 may not be the target of drilling operations for wellbore 122. Productive formation 142, when penetrated, may propel an influx, which is a fluid mixture or gas that may have been anticipated, or a "kick," which is an unanticipated influx, up through annulus 116.

[0036] In some embodiments, MPD-CBHP operations attempt to maintain the pressure at the bottom of wellbore 122 at a value slightly greater than the formation pressures to substantially prevent influxes from entering into wellbore 122. In other words, MPD-CBHP operations are conducted at balance or overpressure where the pressure in annulus 1 16 at bottomhole is equivalent to or slightly higher than the formation pressure. Operating at balance or overpressure, in contrast to underbalanced, assists in minimizing the introduction of influxes into annulus 116. Hydrostatic pressure is defined as pressure due to a stagnant column of fluid. Mud hydrostatic pressure is a function of the density of the mud (or mud weight) and the true vertical depth (TVD). TVD is a measurement of the vertical depth from a horizontal plane, for example drilling surface 104. As an example, drilling system 100 may be drilling at TVD of approximately 14,000 feet. Maintaining total pressure at a value slightly greater than formation pressure may result in preventing influxes into wellbore 122, and also keeping the annular pressure within integrity limits of formation weak zones (e.g., minimum fracture pressure) and equipment at well surface 104. In some embodiments, constant BHP may be maintained by "mass balance check," which equalizes flow into drill string 118 and flow out of annulus 116. In some embodiments, constant BHP may be maintained by adjustments to equipment at well surface 104 based on measurements of the BHP. BHP measurements may be acquired, for example, from measurement while drilling (MWD) technology or WDP technology.

[0037] In some embodiments, using real time downhole annular pressure data to identify variations in pressure may allow detection of an influx event, determination of the location of the influx, and determination of the rising velocity of the influx. A simulation may be used to predict variations in an annular pressure profile during drilling operations. The annular pressure profile may be monitored during drilling operations and compared to the simulated profile. Variations between the profiles may be used to detect that an influx event has occurred. However, due to the complex nature of predicting the annular pressure profile, which may be time-dependent and involve a multi-phase flow, it may be helpful to develop and apply a gas influx simulator.

[0038] An assumption in simplistic gas influx handling approach may be that the influx enters the wellbore as a single bubble or a slug (e.g., a pocket of gas) and maintains that structure throughout the wellbore. However, this assumption may be conservative and pressures calculated from a single bubble assumption may be higher than actually experienced. Thus, a more precise approach may be useful to improve accuracy of simulations of a gas influx.

[0039] In some embodiments, gas influx may enter the wellbore and rise in annulus 116 shown as gas top 164. Above gas top 164, drilling fluid 126 may be in liquid-phase, e.g., drilling fluid with solids. In multi-phase region 166, the gas influx may consist of multi-phases, e.g., liquid (or gas dissolved in the drilling fluid) and gas. Accordingly, in some embodiments, multi-phase flow equations may be utilized to improve the accuracy of predictions of the annular pressure profile. For example, a drift-flux model may be utilized. With some simplifications, equations for the drift- flux model may be as follows: [0040]

d Ap HQ d(Av_lPlHQ ₌

at a_¾ B

, d AVg_PgHg) _ Source ₍ .

dt dx g V sink ' ^ ' d(AX_PlHj) djAXviPiHi) _ ^

dt dx 9 ^ ' d_{Av_lPlH_l+Av_gPgH_g)

at

v ^/

Pg = Pg(P,T) (5)

_Pl = _Pl(P,T,X) (6)

¾ ~ Commix V_siip (7)

//.+ ¾ = 1 (8)

where:

yO = density of liquid, gas, or mixture, as indicated;

v = velocity of liquid, gas, mixture, or slip, as indicated;

H_g and Hi = gas fraction and liquid fraction, respectively;

A = area;

P = pressure;

T= temperature;

Θ = pipe inclination angle;

Co = distribution parameter; and

rhg = rate of gas dissolution

[0041] Equations (1) through (3) represent conservation of mass for drilling fluid (liquid) phase, free gas, and dissolved gas. Equation (4) represents the conservation of momentum for the mixture. Equations (5) and (6) represent equations of state to calculate z factor (gas deviation factor), gas density, and liquid density at a given pressure and temperature. Equation (7) represents the relationship between the velocities of the two phases. Equation (8) represents that the sum of the gas fraction and liquid fraction equals one. In some embodiments, the above model may be used to simulate a gas influx event in a wellbore of a particular geometry. [0042] In drilling operation simulations using a water-based drilling fluid (e.g., WBM), a gas influx enters the wellbore and the annulus pressure at substantially all downhole sensors 162 may increase in MPD-CBHP operations. Changes in pressure profiles at certain locations may be expected. Thus, detecting an increase in annulus pressure may provide an early indication of a gas influx event. Moreover, when the gas top, such as gas top 164, rises to a particular downhole sensor 162, the annulus pressure at that particular downhole sensor 162 may vary. Annular pressure variations may be dependent on the wellbore geometry and the gas influx flow rate. To locate the specific position of the gas influx, pressure derivative curves may be utilized. For example, the location of the gas influx may be determined based on reaching a particular downhole sensor in which the pressure derivative curve varies according to the simulated pattern.

[0043] In some embodiments, simulations using a NAF, such as SBM or OBM, indicate that pressure variations may be less than detected with WBM because hydrocarbon influx may be dissolved in SBM or OBM systems. Thus, in drilling operations using SBM or OBM, downhole sensors 162 with increased accuracy may be useful.

[0044] In some embodiments, one or more simulations are run to determine the impact of a gas influx on wellbore parameters, such as the annular pressure profile. Simulations may not be possible to run on the well site in real-time, either due to extended time required for complicated simulations, availably of a suitable simulator and rig personnel expertise. In some embodiments, the methods and systems disclosed may rely on generating look up tables or graphs based on gas influx simulation data for different well configuration scenarios prior to drilling a new wellbore or a new section. As such, a gas influx may be detected by comparing the actual well data with the simulated information in a quick, convenient, and accurate manner. In some embodiments, simulations may be run for several wellbore geometries with different reservoir and drilling fluid properties to examine the applicability of the methods of the present disclosure. [0045] FIGURE 2 illustrates exemplary simulated pressure profile curves as a function of time in accordance with some embodiments of the present disclosure. Simulated profiles 200a and 200b may be based on simulations of a pressure sensor at a particular depth. For example, simulated profile 200a may be based on a sensor depth of approximately 11,800 feet and simulated p profile lot 200b may be based on a sensor depth of approximately 11,500 feet. Simulated profiles 200a and 200b illustrate the increase in pressure as a function of time based on a simulation using multi-phase flow equations.

[0046] FIGURE 3 illustrates an exemplary simulated pressure derivative curves as a function of time in accordance with some embodiments of the present disclosure. Plot 300 includes curve 302, which corresponds to simulated profile 200a shown in FIGURE 2. Plot 300 also includes curve 304, which corresponds to simulated profile 200b shown in FIGURE 2. The location of a gas influx may be determined by monitoring the variations in pressure derivative curves for each sensor. For example, peaks 306 and 308 may indicate the location of the gas influx at time approximately 75 seconds and 160 seconds, respectively, after the influx event.

[0047] FIGURE 4 illustrates exemplary pressure profile curves for a gas influx as a function of time in accordance with some embodiments of the present disclosure. Result profile 400a and 400b may be based on results after an influx event. For example, result profile 400a and 400b may be based on results approximately 15 minutes after an influx event where the gas top is at approximately 8,760 feet. Result p profile lot 400a corresponds to simulated profile 200a shown in FIGURE 2, and result profile 400b corresponds to simulated profile 200b shown in FIGURE 2. Comparison of the corresponding simulated profile and result profile may assist in determining the state of the influx. For example, similarity between simulated profile 200a and result profile 400a may indicate the influx is in a gas state and determining whether a gas is liberated from the simulation.

[0048] FIGURE 5 illustrates a flow chart of example method 500 for detection of an influx during drilling operations in accordance with some embodiments of the present disclosure. FIGURE 5 includes FIGURES 5 A and 5B. For illustrative purposes, method 500 is described with respect to drilling system 100, discussed with respect to FIGURE 1; however, method 500 may be used for well control when an influx is encountered in any appropriate drilling system. The steps of method 500 can be performed by a user, electronic or optical circuits, various computer programs, models, or any combination thereof, configured to process drilling data. The programs and models may include instructions stored on a non-transitory computer-readable medium and operable to perform, when executed, one or more of the steps described below. The computer- readable media can include any system, apparatus, or device configured to store and retrieve programs or instructions such as a hard disk drive, a compact disc, flash memory, or any other suitable device. The programs and models may be configured to direct a processor or other suitable unit to retrieve and execute the instructions from the computer readable media. Collectively, the user, circuits, or computer programs and models used to process seismic traces may be referred to as a "control tool." For example, the control tool may be computing system 150 located on well site 102, discussed with reference to FIGURE 1. In some embodiments, the control tool is located elsewhere, and receives information stored during the drilling operations. For example, computing system 150 may record drilling information and deliver them to an on-shore computing system for processing at a later time.

[0049] At step 502, the control tool monitors flow rate in and flow rate out at the well surface. For example, at well surface 104, discussed with reference to FIGURE 1, flow into drill string 118 may be determined by pump rate of mud pumps 110 and flow out of annulus 1 16 may be measured by one or more flow meters 160. Flow meters 160 may monitor for small variations in flow rate (e.g., approximately +/- 5% of flow rate) in and out of the well. Flow meters 160 may be communicatively coupled to the control tool and report, transfer, or otherwise transmit information to the control tool in substantially real time, periodically, as requested, and/or in any other suitable manner. In drilling configurations that utilize a NAF, such as an OBM or SBM, continuous monitoring of flow rate out may be recommended based on the low pressure variations experienced by downhole sensors 162.

[0050] At step 504, the control tool detects that flow out is increasing and/or exceeds flow in. As example, the control tool may detect a change in the flow rate out at flow meters 160. The control tool may determine an increase in flow rate out by monitoring measurements from flow meters 160. In some embodiments, the control tool may receive an alert from another component of drilling system 100 that indicates a flow rate change beyond a specified level. For example, an alert may be received when flow rate out increases by approximately 10% above a preset flow rate or the flow rate in.

[0051] At step 506, the control tool determines whether the increase in flow rate out is unexpected. In some cases, the flow rate out may increase due to an expected event. For example, the increase in flow rate out may be based on a corresponding change in the flow rate in, such as stopping or starting mud pumps 110. As another example, the control tool may determine if the increase in flow rate out is due to expected wellbore breathing. In such a case, the flow rate out may increase due to drilling fluid 126 returning from closing fractures downhole in wellbore 122. In cases with expected increases in flow rate out, the flow rate out may reduce to be approximately equal to flow rate in in a relatively short time period, e.g., approximately one to five minutes. If the flow rate out does not shortly return to approximate the flow rate in, then the increase in flow rate may not be due to an expected event. If the increase in flow rate out is unexpected, method 500 may proceed to step 508. If the increase in flow rate out is expected, method 500 may return to step 502.

[0052] At step 508, the control tool indicates detection of an influx event and initiates emergency level 1 procedures. The control tool may activate an alarm or otherwise notify rig personnel to take action based on the influx. Emergency level 1 procedures may include notifying rig personnel that an influx event is occurring and to remain alert. In non-MPD operations, a flow check may be conducted and personnel should be ready to close the BOP In MPD operations, personnel or systems should be prepared to take the proper response. [0053] At step 510, the control tool determines the location and orientation of the drill bit at the time of the influx event. The control tool may determine the depth and direction that drill bit 128 was operating when the influx event occurred.

[0054] At step 512, the control tool determines if the influx entered the wellbore in a gravitationally dominant flow section of the wellbore. A gravitationally dominant flow section may be a vertical or approximately vertical section of the wellbore. In such a section, annular pressure readings at downhole pressure sensors, such as downhole sensors 162, may provide an additional indicator of the presence, location, and rising velocity of the influx. In horizontal or nearly horizontal sections (e.g., not gravitationally dominant flow), the annular pressure variations at pressure sensors may not be as significant such that the location and rising velocity of the influx may not be as simple to identify. The control tool may determine if the influx entered in a gravitationally dominant flow section by determining the location and orientation of drill bit 128 when the influx is detected. If drill bit 128 is drilling a vertical or approximately vertical section when the influx is detected, then the control tool may determine that the influx entered the wellbore in a gravitationally dominant flow section. If the influx entered the wellbore in a gravitationally dominant flow section of the wellbore, method 500 may proceed to step 514. Otherwise, method 500 may proceed to step 526.

[0055] At step 514, the control tool obtain an annular pressure profile based on one or more of the downhole pressure sensors. The observed annular pressure profile may be real-time readings from pressure sensors or may be recorded data obtained by the control tool. Thus, the control tool may calculate, gather, obtain, observe, or otherwise collect an annular pressure profile based on one or more downhole sensors 162. For example, a particular downhole sensor 162 proximate to casing shoe 148, e.g., approximately 9,000 feet, may transmit pressure data via WDP technology to the control tool. The control tool may obtain an annular pressure profile at the depth of casing shoe 148.

[0056] At step 16, the control tool compares the obtained annular pressure profile and the simulated annular pressure profile of a gas influx event. The simulated annular pressure profile may be based on a two-phase equation model, such as the model discussed with reference to Equations (1) through (8). The simulated annular pressure profile may be based on a gas influx at a similar depth as the obtained annular pressure profile, e.g., approximately 9,000 feet.

[0057] At step 518, the control tool may determine if the obtained annular pressure profile is similar to the simulated annular pressure profile. For example, the control tool may perform statistical analysis or correlations to determine if there is sufficient similarity between the simulated and obtained annular pressure profiles. The evaluation may be a visual comparison or may include analysis of derivative curves (pressure or flow). For example, comparison may be made between simulated profile 200a, shown with reference to FIGURE 2A, with the real time profile obtained from sensors, e.g., result profile 400a, shown with reference to FIGURE 4A. Comparisons can be used to determine the influx type and influx movement in the wellbore.. If the simulated annular pressure profile is not sufficiently similar to the obtained annular pressure profile from downhole pressure sensors, method 500 may proceed to step 520. Otherwise, method 500 may proceed to step 522.

[0058] At step 520, the control tool determines that the influx is in a gas state. The influx may remain in a gas state if WBM is used in lieu of SBM. Further, an influx in a gas state may cause downhole sensors 162 to detect larger variations in pressure than if the influx is in a liquid state. Thus, the control tool may monitor for such variations in pressure and indicate the location and rising speed of the influx.

[0059] At step 522, the control tool determines that the influx is in a liquid state, e.g., dissolved gas in a NAF such as an OBM or SBM. Because the influx is in a liquid state, the pressure variations may be smaller and more difficult to detect. Additionally, the dissolved gas may release— transition from a liquid to a gas— from the solution when the pressure decreases below the bubble point pressure. The control tool may monitor for smaller pressure variations at downhole sensors 162 and may indicate the depth at which the dissolved gas is liberated from the solution. At such a depth, the pressure variations detected by downhole sensors 162 may increase. Due to gas solubility in a NAF, the location of the influx may be difficult to determine. Therefore, simulations may be run for multiple scenario to determine the influx location.

[0060] At step 524, the control tool indicates the state of the influx and initiates emergency level 2 procedures. The control tool may activate an alarm or otherwise notify rig personnel to take action based on the state of the influx. Emergency level 2 procedures may include notifying rig personnel that the influx or kick is very probable and personnel should be prepared to take appropriate action.

[0061] At step 526, the control tool determines if there are variations in pit gain or pump pressure. When an influx occurs, the flow rate out increases resulting in a change in drilling fluid level in the mud tanks (e.g., mud tanks 1 12 discussed with reference to FIGURE 1). Pit gain is measured in volume (e.g., barrels (bbl)) as a function of time (min). Determining the variation in pit gain may indicate the size of the influx. Because a variation in pit gain may not occur quickly following an influx event and may not occur at all if the influx is not large (e.g., if the influx is less than approximately 10 bbl), a variation in pit gain may confirm a larger influx event. If the control tool determines there are variations in pit gain, method 500 may proceed to step 528. Otherwise, method 500 may proceed to step 530.

[0062] At step 528, the control tool indicates the variation in pit gain and initiates emergency level 3 procedures. The control tool may activate an alarm or otherwise notify rig personnel to take action based on the state of the influx. Emergency level 3 procedures may include closing the BOP in non-MPD operations or taking the appropriate action in MPD operations.

[0063] At step 530, the control tool determines that there is a possible malfunction in the drilling system. Based on the lack of variation in pit gain (step 524), the control tool may indicate that there is a either a small influx or a malfunction in drilling system 100. For example, a particular downhole sensor 162 may be malfunctioning. The control tool may communicate to the rig personnel to stay alert and may initiate trouble-shooting procedures. [0064] Modifications, additions, or omissions may be made to method 500 without departing from the scope of the present disclosure. For example, the steps may be performed in a different order than that described and some steps may be performed at the same time. For example, step 510 may be performed before step 506. Further, more steps may be added or steps may be removed without departing from the scope of the disclosure. Additionally, each individual step may include additional steps without departing from the scope of the present disclosure.

[0065] This disclosure encompasses all changes, substitutions, variations, alterations, and modifications to the example embodiments herein that a person having ordinary skill in the art would comprehend. Similarly, where appropriate, the appended claims encompass all changes, substitutions, variations, alterations, and modifications to the example embodiments herein that a person having ordinary skill in the art would comprehend. Moreover, reference in the appended claims to an apparatus or system or a component of an apparatus or system being adapted to, arranged to, capable of, configured to, enabled to, operable to, or operative to perform a particular function encompasses that apparatus, system, component, whether or not it or that particular function is activated, turned on, or unlocked, as long as that apparatus, system, or component is so adapted, arranged, capable, configured, enabled, operable, or operative.

Claims

WHAT IS CLAIMED IS:

1. A method for drilling operations, comprising:

indicating an influx event by detecting that a flow rate of a drilling fluid out of an annulus is increasing;

determining a location and an orientation of a drill bit in a wellbore at the influx event; and

based on determining the influx event occurred in a gravitationally dominant flow section of the wellbore:

obtaining an annular pressure profile for a downhole pressure sensor; and comparing the obtained annular pressure profile with a simulated annular pressure profile, the simulated annular pressure profile based on a set of multiphase flow equations.

2. The method of Claim 1, further comprising, based on the obtained annular pressure profile being similar to the simulated annular pressure profile:

determining that an influx from the influx event is in a gas state;

determining a location of the influx; and

determining a rising velocity of the influx.

3. The method of Claim 1 further comprising, based on the obtained annular pressure profile being dissimilar to the simulated annular pressure profile:

determining that an influx from the influx event is in a liquid state;

determining a depth in the wellbore that a dissolved gas is liberated from the liquid state.

4. The method of Claim 1, wherein the set of multi-phase flow equations are based on a drift-flux model.

5. The method of Claim 1, further comprising, determining if there are variations in a pit gain of a mud tank that contains the drilling fluid.

6. The method of Claim 1, wherein the drilling fluid comprises a water-based drilling fluid.

7. The method of Claim 1 , wherein the drilling fluid comprises a nonaqueous fluid.

8. A system for drilling operations, comprising:

a wellbore including an annulus;

a flow meter configured to measure the flow rate of a drilling fluid out of the annulus;

a computing system communicatively coupled to the flow meter, the computing system configured to :

indicate an influx event by detecting that a flow rate of the drilling fluid out of the annulus is increasing;

determine a location and an orientation of a drill bit in a wellbore at the influx event; and

obtain an annular pressure profile for a downhole pressure sensor; and

compare the generated annular pressure profile with a simulated annular pressure profile, the simulated annular pressure profile based on a set of multi-phase flow equations.

9. The system of Claim 8, wherein the computing system is further configured to, based on the obtained annular pressure profile being similar to the simulated annular pressure profile: determine that an influx from the influx event is in a gas state;

determine a location of the influx; and

determine a rising velocity of the influx.

10. The system of Claim 8, wherein the computing system is further configured to, based on the obtained annular pressure profile being dissimilar to the simulated annular pressure profile:

determine that an influx from the influx event is in a liquid state;

determine a depth in the wellbore that a dissolved gas is liberated from the liquid state.

11. The system of Claim 8, wherein the set of multi-phase flow equations are based on a drift-flux model.

12. The system of Claim 8, wherein the computing system is further configured to determine if there are variations in a pit gain of a mud tank that contains the drilling fluid.

13. The system of Claim 8, wherein the drilling fluid comprises a water-based drilling fluid.

14. The system of Claim 8, wherein the drilling fluid comprises a non-aqueous fluid.

15. A non-transitory computer-readable medium, comprising instructions that, when executed by a processor, cause the processor to:

indicate an influx event by detecting that a flow rate of a drilling fluid out of an annulus is increasing; determine a location and an orientation of a drill bit in a wellbore at the influx event; and

obtain an annular pressure profile for a downhole pressure sensor; and compare the generated annular pressure profile with a simulated annular pressure profile, the simulated annular pressure profile based on a set of multiphase flow equations.

16. The non-transitory computer-readable medium of Claim 15, wherein the processor is further caused to, based on the obtained annular pressure profile being similar to the simulated annular pressure profile:

determine that an influx from the influx event is in a gas state;

determine a location of the influx; and

determine a rising velocity of the influx.

17. The non-transitory computer-readable medium of Claim 15, wherein the processor is further caused to, based on the obtained annular pressure profile being dissimilar to the simulated annular pressure profile:

determine that an influx from the influx event is in a liquid state;

18. The non-transitory computer-readable medium of Claim 15, wherein the set of multi-phase flow equations are based on a drift-flux model.

19. The non-transitory computer-readable medium of Claim 15, wherein the processor is further caused to determine if there are variations in a pit gain of a mud tank that contains the drilling fluid.

20. The non-transitory computer-readable medium of Claim 15, wherein the fluid comprises a water-based drilling fluid.

21. The non-transitory computer-readable medium of Claim 15, wherein the drilling fluid comprises a non-aqueous fluid.