OA12776A

OA12776A - Dynamic annular pressure control apparatus and method.

Info

Publication number: OA12776A
Application number: OA1200400218A
Authority: OA
Inventors: Egbert Jan Van Riet
Original assignee: Shell Int Research
Priority date: 2002-02-20
Filing date: 2003-02-19
Publication date: 2006-07-06
Also published as: WO2003071091A8; AU2003211155A1; RU2004127944A; NO338967B1; AU2003211155B9; AU2003211155B2; CA2477242C; EP1488073A1; EG23370A; EP1488073B1; CA2477242A1; AR038529A1; RU2301319C2; EP1488073B2; CN100535380C; CN1643233A; MXPA04008063A; WO2003071091A1; NO20043906L; WO2003071091A9

Abstract

A system and method for controlling formation pressures during drilling of a subterranean formation utilizing a selectively fluid backpressure system in which fluid is pumped down the drilling fluid return system in response to detected borehole pressures. A pressure monitoring system is further provided to monitor detected borehole pressures, model expected borehole pressures for further drilling and control the fluid backpressure system.

Description

1 . 012776

Field of the Invention

The présent method and apparatus are related to amethod for dynamic well borehole annular pressurecontrol, more specifically, a selectively closed-loop, 5 pressurized method for controlling borehole pressure during drilling and well completion.

Background of the Art

The exploration and production of hydrocarbons fromsubsurface formations ultimately requires a method to 10 reach and extract the hydrocarbons from the formation.

This is typically achieved by drilling a well with adrilling rig. In its simplest form, this constitutes a Λ land-based drilling rig that is used to support androtate a drill string, comprised of a sériés of drill 15 tubulars with a drill bit mounted at the end.

Furthermore, a pumping System is used to circulate afluid, comprised of a base fluid, typically water or oil,and various additives down the drill string, the fluidthen exits through the rotating drill bit and flows· back 20 to surface via the annular space formed between the borehole wall and the drill bit. The drilling fluidserves the following purposes: (a) Provide support to theborehole wall, (b) prevent formation fluids or gassesfrom entering the well, (c) transport the cuttings 25 produced by the drill bit to surface , (d) provide hydraulic power to tools fixed in the drill string and(d) cooling of the bit. After being circulated throughthe well, the drilling fluid flows back into a mudhandling System, generally comprised of a shaker table, 2 012776 to remove solids, a mud pit and a manual or automaticmeans for addition of various Chemicals or additives tokeep the properties of the returned fluid as required forthe drilling operation. Once the fluid has been treated,it is circulated back into the well via re-injection intothe top of the drill string with the pumping System.

During drilling operations, the fluid exerts a pressure against the wellbore wall that is mainly built- up of a hydrostatic part, related to the weight of the mud column, and a dynamic part related frictional pressure losses caused by, for instance, the fluid circulation rate or movement of the drill string. The total pressure (dynamic + static) that the fluid exerts on the wellbore wall is commonly expressed in terms of équivalent density. This "Equivalent Circulating Density" (or ECD) is defined as the density that a static columnΛ of fluid requires to obtain the same pressure as occursin .the well during drilling operations. Commonly, the ECDat a certain location in the well is calculated by thefollowing équation: ECD = P / (g * TVD) .

In which: P is the pressure at a certain location inthe well, g is the constant of gravity, TVD is the true vertical depth at a certain locationin the well.

During Over-Balanced Drilling" or "Conventionaldrilling" the mud density has to be kept between twomargins:

Firstly, the density is selected such that thehydrostatic pressure generated by the fluid column 012776 3 exceeds the surrounding formation pore pressure, wherebyformation fluid or gas is prevented from entering intothe borehole (primary well control). For this reason, theannulus the outlet at surface can be kept unrestrictedand therefore this System is referred to as 'open loop'.For reasons of safety and pressure control, a Blow-OutPreventer (BOP) is mounted on the well head, below therig floor which can shut off the wellbore in caseunwanted formation fluids or gas should enter thewellbore (secondary well control). Such unwanted inflowsare commonly referred to as "kicks". The BOP willnormally only be used in emergency i.e. well-controlsituations.

Secondly, the fluid density has to be selected such that the pressure in the well, while the fluid is static or during drilling operations, never exceeds theΛ formation fracture pressure or formation strength. If the^formation strength is exceeded, formation fractures willoccur which will create drilling problems such as fluidlosses and borehole instability.

The pressure margin with on one side the porepressure and on the other side the formation strength isknown as the "Operational Window". Thus a correct fluiddensity is critical for a safe and successful Over-Balanced Drilling operation.

Further, some of the additives from the pressurizedfluid adhéré to the formation and form an almostimperméable layer or "mud cake" on the borehole wall.

This mud cake helps to prevent drilling fluid fromleaking-off into the formation pores, and préserves andprotects the formation prior to the setting of casing aswill be discussed further below. 012776 4

Over-Balanced Drilling is the most commonly useddrilling method, however it has disadvantages asillustrated with the examples below:

Fig. 1 is an exemplary diagram of the "Operational5 Window" of the drilling process of a certain borehole section. On the horizontal axis, the hydrostatic pressureexerted by the drilling fluid is depicted and thevertical axis represents the vertical depth of theborehole. The formation pore pressure graph is 10 represented by line 10. Line 12 represents the formation fracture pressure. The pore pressure and fracturepressure show a step change, realistic for an over-pressured oil réservoir. Also shown in the graph is aprevious casing shoe depth 20. Both pore and fracture 15 pressure are only relevant and shown below the casing shoe. The hydrostatic fluid pressure is depicted by Λ line 16. The annular pressure generated by the>circulating fluid and its additives is represented by line 14. 20 Pressures in excess of the formation fracture pressure will resuit in the drilling fluid pressurizingthe formation walls to the extent that small cracks orfractures will open in the borehole wall and the fluidpressure overcomes the formation pressure with 25 significant fluid invasion and/or borehole instability.

For reasons of drilling performance (pénétration rate),and in case of a réservoir section, for minimum formationimpairment, the mud weight should preferably be selectedas close as possible to the formation pore pressure, 30 resulting in a small hydrostatic overbalance only at depth x. At depth y however, the pressure during drillingwill exceed the fracture pressure, this détermines the 012776 5 maximum depth that can be reached without setting a newcasing.

Drilling with over-balance results in invasion ofdrilling fluid including suspended fines into the pores 5 of the formation, that in the réservoir section adversely affects formation permeability, consequently negativelyimpacting hydrocarbon production during the life span ofthe well. Even if a fluid density can be chosen that willcreate a very small overbalance during static conditions, 10 it cannot be avoided that, due to ECD variations caused by the drilling process, periods with a higheroverbalance will occur.

In some cases, création of fissures or fractures inthe formation will occur while drilling with an over- 15 balance that exceeds the formation fracture pressure.

This will eventually resuit in such dramatic fluid loss Λ to the formation that the fluid level in the annulus,•required for pressure/well control can no longer bemaintained and the well starts to flow. In such an event, 20 the operator has to close the annulus at surface by closing the Blow Out Preventors (BOP) below the drillingrig floor to prevent further gas influx into the annulusand regain control over the pressure in the well. Thiswell control situation can normally only be cured by 25 filling the open hole section of the borehole with cernent requiring to set an additional casing or liner, possiblyresulting in a lost hole size.

Open-hole intervals of a bore-hole must from time totime be secured by casing. Because casing strings are 30 'telescopically' run and cemented in place concentrically, each successive casing string has asmaller diameter. Only a limited nuraber of standardiseddiameter casing diameters are available to an operation 012776 - 6 - for reaching the target depth. The maximum length of anopen-hole interval is mainly dictated by the width of the"operational window", the expected formation pressuresahead of the bit, and formation properties like strength 5 and stability. In critical formations (depleted réservoirs, deep-water operations), ECD variations duringthe drilling process, may be larger than the "operationalwindow" allows. This means that these kind of formationscan not, or only over a limited length be drilled with 10 Over-Balance drilling technology, and an additional casing string is required to secure the open holesection.

Another effect that is difficult to handle with"over-balanced drilling is known as "formation breathing" 15 or referred to as "formation ballooning". Formation breathing occurs when the hydrostatic drilling fluidΛ pressure is within, the small operational window but the•ECD during circulation exceeds the formation strength.

Or, alternatively, when the fluid pressure is within the 20 operational window and the formation has many natural fractures and/or is extremely permeable. Consequently,(large quantifies of) drilling fluid is lost in formationfractures during circulation but when circulation isinterrupted, the formation returns fluid, mostly of a 25 different density than the drilling fluid. This results in kicks, a well control problem, often resulting in alost hole section or a well. During the planning phase ofwells, the expectation of severe formation breathing mayresuit in cancelling the well based on risk analysis. 30 Formation fatigue ultimately resulting in instability of the borehole can be caused by ECD variations duringthe drilling process. It will be appreciated that it isnecessary to shut off the mud pumps from time to time 012776 7 during the drilling process, for instance to make upsuccessive drill pipe joints. When the pumps are shutoff, the annular pressure will reduce to the hydrostaticpressure. Similarly, when the pumps are turned back on,the annular pressure increases. The cyclic loading of theborehole wall can cause fatigue. ECD variations during the drilling process becomeincreasingly problematic when longer wells are drilledwith large horizontal outsteps. It will be appreciatedthat in general the ECD variations induced by dynamicprocesses such as fluid circulation or pipe movementincrease with the length of the well. The operationalwindow however will usually not vary significantly withina horizontal plain. Consequently, the maximum outstepthat can be reached is located at the point where the ECDvariations equal the margins set by the operational Λ window. - The current invention further builds on the inventiondescribed in US patent 6,352,129 by Shell Oil Company. Inthis patent a method and System are described to controlthe fluid pressure in a wellbore during drilling.

To overcome the problems of Over-Balanced, openfluid circulation Systems, there hâve been developed anumber of closed fluid handling Systems. Examples ofthese include U.S. 6,035,952, to Bradfield et al. andassigned to Baker Hughes Incorporated. In this patent, aclosed System is used for the purposes of underbalanceddrilling, i.e., the annular pressure is maintained belowthe formation pore pressure.

Another method and System is described by H.L. Elkinsin US patent 6,374,925 and in continuation applicationUS 2002/0108783. That invention traps pressure within the 012776 - 8 - annulus by completely closing the annulus outlet whencirculation is interrupted.

Summary of the Présent Invention

To solve the above mentioned problems of the5 overbalance drilling system with an open circulation

System described in Background of the Art, the présentinvention is directed to a closed loop, overbalanceddrilling system having a variable overbalance pressurecapability for the purpose of automatically and

10 accurately achieving a desired downhole pressure or ECD during drilling and completing a well. The downholepressure is controlled by creating a variablebackpressure at the annulus exit at surface.

The présent invention utilizes information related to 15 the wellbore, drilling process, drill rig and drilling fluid as inputs to a model to predict downhole pressure. Λ

The predicted downhole pressure is then compared to ades-ired downhole pressure and the differential isutilized to adjust the backpressure system until 20 predicted and desired pressures are equal. The présent invention further utilizes actual downhole pressure tocalibrate the model and modify input parameters to moreclosely correlate predicted downhole pressures tomeasured downhole pressures. More particularly, the 25 présent invention contemplâtes a system for controlling annular pressure during the entire process of drilling ofa subterranean formation, comprising: a drill string extending into a borehole, whereby theannular space is formed between the drill string and the 30 borehole wall, the drill string including a bottom hole assembly and a longitudinal drilling fluid passage havingan outlet opening at the lower end part of the drillstring; 012776 9 a primary pump for selectively pumping a drillingfluid from a drilling fluid source, through said drillstring and into the annular; a fluid discharge conduit in fluid communication with5 said annular space for discharging said drilling fluid; a fluid backpressure System in fluid communicationwith said fluid discharge conduit, said fluidbackpressure System comprising a backpressure controldevice for controlling the backpressure in the discharge 10 conduit to increase annular space drilling fluid pressure; and a programmable pressure monitoring and control Systemfor controlling the fluid back pressure System, theprogrammable pressure monitoring and control System 15 arranged to calculate a predicted downhole pressure using a model, compare the predicted downhole pressure to a Λ desired downhole pressure, and to utilize thedif-ferential between the predicted and desired downholepressures to control the backpressure System. 20 In one aspect, the présent invention is capable of modifying annular pressure during circulation by theaddition of backpressure, thereby increasing the annularpressure without the addition of weighting additives tothe fluid. It will be appreciated that the use of 25 backpressure to increase annular pressure is more responsive to sudden changes in formation pore pressure.

In yet another aspect, the présent invention iscapable of maintaining constant annular pressure duringprimary pump shut down when drill pipe is being added to 30 or removed from the string. By maintaining constant pressure in the annulus the drilling problems describedin Background of the Art are reduced considerably oreliminated. 10 012776

In yet another aspect, the présent invention utilizes accurate mass-balance flow meters that permit accurate détermination of fluid gains or losses in the System and détermination of current pore pressure, permitting to 5 better manage the fluids involved in the operation and allow the System to predict and to adjust automaticallyfor changes in pore pressure.

Brief Description of the Drawings. A better understanding of the présent invention may 10 be obtained by referencing the following drawings in conjunction with the Detailed Description of thePreferred Embodiment, in which:

Figure 1 is a graph depicting annular pressures andformation pore and fracture pressures; 15 Figure 2a and 2b are schematic views of the apparatus of the preferred embodiment of the invention; Λ

Figure 3 is a block diagram of the pressure>monitoring and control System utilized in the preferred embodiment; 20 Figure 4 is a functional diagram of the operation of the pressure monitoring and control System;

Figure 5 is a graph depicting the corrélation ofpredicted annular pressures to measured annularpressures; 25 Figure 6 is a graph depicting the corrélation of predicted annular pressures to measured annular pressuresdepicted in Figure 5, upon modification of certain modelparameters;

Figure 7 is a graph depicting the method of the 30 présent invention as applied to at balanced drilling;

Figure 8 is a graph depicting how the method of the présent invention may be used to control variations information pore pressure in an overbalanced condition and; 012776 - 11 -

Figures 9A and 9B are graphs depicting how theprésent invention may be used to counteract annularpressure drops and spikes that accompany pump off/pump onconditions.

Detailed Description of the Preferred Embodiment

The présent invention is intended to achieve DynamicAnnulus Pressure Control (DAPC) of a well bore duringdrilling, completion and intervention operations.Structure of the Preferred Embodiment

Figure 2a is a schematic view depicting a surfacedrilling System employing the current invention. It willbe appreciated that an offshore drilling System maylikewise employ the current invention. The drillingSystem 100 is shown as being comprised of a drillingrig 102 that is used to support drilling operations. Manyof the components used on a rig 102, such as the kelly, Λ power tongs, slips, draw works and other equipment are>not shown for ease of depiction. The rig 102 is used tosupport drilling and exploration operations information 104. As depicted in Fig. 2a the borehole 106has already been partially drilled, casing 108 set andcemented 109 into place. In the preferred embodiment, acasing shutoff mechanism, or downhole deployment va-lve,110 is installed in the casing 108 to optionally shut-offthe annulus and effectively act as a valve to shut offthe open hole section when the entire drill string islocated above the valve.

The drill string 112 supports a bottom hole assembly (ΒΗΆ) 113 that includes a drill bit 120, a mud motor 118,a MWD/LWD sensor suite 119, including a pressuretransducer 116 to détermine the annular pressure, a checkvalve 10, to prevent backflow of fluid from the annulus.It also includes a telemetry package 122 that is used to 12 012776 transmit pressure, MWD/LWD as well as drillinginformation to be received at the surface.

As noted above, the drilling process requires the useof a drilling fluid 150, which is stored in 5 réservoir 136. The réservoir 136 is in fluid communications with one or more mud pumps 138 which pumpthe drilling fluid 150 through conduit 140. Theconduit 140 is connected to the last joint of the drillstring 112 that passes through a rotating control head 11 10 on top of the BOP 142. The rotating control head on top of the BOP forms, when activated, a seal around the drillstring 112, isolating the pressure, but still permittingdrill string rotation and reciprocation. The fluid 150is pumped down through the drill string 112 and the 15 BHA 113 and exits the drill bit 120, where it circulâtes the cuttings away from the bit 120 and returns them upΛ the open hole annulus 115 and then the annulus formed>between the casing 108 and the drill string 112. Thefluid 150 returns to the surface and goes through the 20 side outlet below the rotating head on top of the BOP, through conduit 124 and optionally through various surgetanks and telemetry Systems (not shown).

Thereafter the fluid 150 proceeds to what isgenerally referred to as the backpressure system 131. The 25 fluid 150 enters the backpressure system 131 and flows through an optional flow meter 126. The flow meter 126may be a mass-balance type or other high-resolution flowmeter. Utilizing the flow meter 126 and 152, an operatorwill be able to détermine how much fluid 150 has been 30 pumped into the well through drill string 112 and the amount of fluid 150 returning from the well. Based ondifférences in the amount of fluid 150 pumped versusfluid 150 returned, the operator is able to détermine 012776 - 13 - whether fluid 150 is being lost to the formation 104,i.e., a significant négative fluid differential, whichmay indicate that formation fracturing has occurred.Likewise, a significant positive differential would be 5 indicative of formation fluid or gas entering into the well bore (kick).

The fluid 150 proceeds to a wear résistant choke 130.It will be appreciated that there exist chokes designedto operate in an environment where the drilling fluid 150 10 contains substantial drill cuttings and other solids.

Choke 130 is one such type and is further capable ofoperating at variable pressures, flowrates and throughmultiple duty cycles. The fluid 150 exits the choke 130and flows through valve 5. Valve 5 allows fluid returning 15 from the well to be directed through the degasser 1 and solids séparation equipment 129 or to be directed to Λ réservoir 2. Optional degasser 1 and solids séparation:equipment 129 are designed to remove excess gas contaminâtes, including cuttings, from the fluid 150. 20 After passing solids séparation equipment 129, the fluid 150 is returned to réservoir 136.

Two way valve 125 is provided for either feedingfluid 150 from réservoir 136 via conduit 119A or fromréservoir 2 (trip tank) via conduit 119B to a 25 backpressure pump 128. The trip tank is normally used on a rig to monitor fluid gains and losses during trippingoperations. In the présent invention, this functionalityis maintained.

In operation, valve 125 would select either 30 conduit 119A or conduit 119B, and the backpressure pump 128 engaged to ensure sufficient flow passes thechoke system to be able to maintain backpressure, evenwhen there is no flow coming from the annulus 115. 012776 - 14 -

The ability to provide adjustable backpressure duringthe entire drilling and completing process is asignificant improvement over conventional drillingSystems.

The preferred embodiment of the présent invention further includes a flow meter 152 in conduit 100 to measure the amount of fluid being pumped downhole.

Alternatively, the volume can be calculated from the rig pump stroke count and volume. It will be appreciated that by monitoring the flow in and out of the well and the volume pumped by the backpressure pump 128, and further taking into account al substances moving in and out of the annulus at surface, the System is readily able to détermine the amount of fluid 150 being lost to the formation, or conversely, the amount of formation fluid leaking to the borehole 106. Λ

Figure 2b depicts an alternative embodiment of the>system. In this embodiment the backpressure pump is notrequired to maintain sufficient flow through the chokeSystem when the flow through the well needs to be shutoff for any reason such as adding another drill pipejoint. In this embodiment, an additional two way valve 6is placed downstream of the rig pump 138 in conduit-140.This valve allows fluid from the rig pumps to becompletely diverted from conduit 140 to conduit 7, notallowing flow from the rig pump 138 to enter the drillstring 112. By maintaining pump action of pump 138,sufficient flow through the manifold to controlbackpressure, is ensured. DAPC Monitoring System

Figure 3 is a block diagram of the pressuremonitoring System 146 of the preferred embodiment of theprésent invention. System inputs to the monitoring _ 15. 012776

System 146 include the downhole pressure 202 that hasbeen measured by sensor packagell9z transmitted by MWDpuiser package 122 (or other telemetry System) andreceived by transducer equipment (not shown) on the 5 surface. Other System inputs include pump pressure 200, input flow rate 204 from flow meter 152 or from mud pumpstrokes compensated for efficiency, pénétration rate andstring rotation rate, as well as weight on bit (WOB) andtorque on bit (TOB) that may be transmitted from the 10 · BHA 113 up the annulus as a pressure puise. Return flow is optionally measured using flow meter 126. Signaisreprésentative of the data inputs are transmitted to acontrol unit 230, which is in it self comprised of adrill rig control unit 232, a drilling operator's 15 station 234, a DAPC processor 236 and a back pressure programmable logic controller (PLC) 238, ail of which are Λ connected by a common data network or industrial type>bus 240. The DAPC processor 236 serves three functions,monitoring the State of the borehole pressure during 20 drilling operations, predicting borehole response to continued drilling, and issuing commands to thebackpressure PLC to control the variable choke 130 andbackpressure pump 128. The spécifie logic associated withthe DAPC processor 236 will be discussed further below. 25 Calculation of Backpressure

A schematic model of the functionality of the DAPC pressure monitoring System 146 is set forth in Figure 4.The DAPC processor 236 includes programming to carry outcontrol functions and Real Time Model Calibration 30 functions. The DAPC processor receives input data from various. sources and continuously calculâtes in real timethe correct backpressure set-point to achieve the desireddownhole pressure. The set-point is then transferred to 16 012776 the programmable logic controller 238, which génératesthe control signais for positioning of the choke, valvesand adjusting backpressure pump 128. The input parametersfall into three main groups. The first are relativelyfixed parameters 250, including parameters such as well,drill string, hole and casing geometry, drill bit nozzlediameters, and well trajectory. While it is recognizedthat the actual well trajectory may vary from the plannedtrajectory, the variance may be taken into account with acorrection to the planned trajectory. Also within thisgroup of parameters are température profile of the fluidin the annulus and the fluid composition. As with thegeometrical parameters, these are generally known and donot vary quickly over the course of the drillingoperations. In particular, with the DAPC System, oneobjective is keeping the fluid 150 density and Λ composition relatively constant, using backpressure to•provide the additional pressure for control of theannulus pressure.

The second group of parameters 252 are highlyvariable in nature and are sensed and logged in realtime. The rig data acquisition System provides thisinformation via common data network 240 to the DAPC;processor 236. This information includes flow rate dataprovided by both downhole and return flow meters 152 and126 and/or by measurement of pump strokes, respectively,the drill string rate of pénétration (ROP) or velocity,the drill string rotational velocity, the bit depth, andthe well depth, ail the latter being derived from directrig sensor measurements. Furthermore, downhole pressuredata 254 is provided by a pressure sensing tool locatedin the bottom hole assembly. Data gathered with this toolis transmitted to surface by the downhole telemetry 012776 17 package 122. It is appreciated that most of currenttelemetry Systems hâve limited data transmission capacityand/or velocity. The measured pressure data couldtherefore be received at surface with some delay. OtherSystem input parameters are the desired set-point for thedownhole pressure 256 and the depth at which the set-point should be maintained. This information is usuallyprovided by the operator.

The control module 258 calculâtes the pressure in the annulus over the full well bore length utilizing various models. The pressure in the well bore is a function not only of the static pressure or weight of the fluid column in the well, but also includes pressures losses caused by drilling operations, including fluid displacement by the drill string, frictional pressure losses caused by fluid motion in the annulus (ECD), and other factors. In orderΛ to calculate the pressure within the well, the controlmodule 258 considers the well as a finite number oféléments, each assigned to a segment of well bore length.In each of the éléments the dynamic pressure and thefluid weight is calculated and used to détermine thepressure differential 262 for the segment. The segmentsare summed and the pressure differential for the entirewell profile is determined.

It is known that the flow rate of the fluid 150 beingpumped downhole is proportional to the flow velocity offluid 150 at any location in the wellbore and may be usedto détermine dynamic pressure loss as the fluid is beingcirculated. The fluid 150 density is calculated in eachsegment, taking into account the fluid compressibility,estimated cutting loading and the thermal expansion ofthe fluid for the specified segment, which is itselfrelated to the température profile for that segment of 012776 - 18 - the well. The fluid viscosity at the température profilefor the segment is also instrumental in determiningdynamic pressure losses for the segment. The compositionof the fluid is also considered in determining 5 compressibility and the thermal expansion coefficient.

The drill string ROP is related to the surge and swabpressures encountered during drilling operations as thedrill string is moved into or out of the borehole. Thedrill string rotation is also used to détermine dynamic 10 pressure losses, as it créâtes a frictional force between the fluid in the annulus and the drill string. The bitdepth, well depth, and well/string geometry are ail usedto help create the borehole segments to be modelled. Inorder to calculate the weight of the fluid, the preferred 15 embodiment considers not only the hydrostatic pressure exerted by fluid 150, but also the fluid compression, Λ fluid thermal expansion and the cuttings loading of the>fluid seen during operations. Ail of these factors gointo calculation of the "static pressure". 20 Dynamic pressure considers many of the same factors in determining static pressure. However, it furtherconsiders a number of other factors. Among them is theconcept of laminar versus turbulent flow. The flow -characteristics are a function of the estimated 25 roughness, hole and string geometry and the flow velocity, density and viscosity of the fluid. The aboveincludes borehole eccentricity and spécifie drill pipegeometry (box/pin upsets) that affect the flow velocityseen in the borehole annulus. The dynamic pressure 30 calculation further includes cuttings accumulation downhole, string movement's (axial movement and rotation)effect on dynamic pressure of the fluid. 19 012776

The pressure differential 262 for the entire annulusis calculated and compared to the set-point pressure 251in the control module 264. The desired backpressure 266is then determined and passed on to a programmable logic 5 controller 238, which generates control signais for the choke 121, backpressure pump 128 and valves.

Calibration and Correction of the Backpressure

The above discussion of how backpressure is generallycalculated utilized several downhole parameters, 10 including downhole pressure and estimâtes of fluid viscosity and fluid density. These parameters aredetermined downhole and transmitted up the mud columnusing pressure puises which travel to surface atapproximately the speed of Sound. This travelling speed 15 and the limited bandwidth of such Systems usually cause a delay between measuring the data downhole and receiving Λ the data at surface. This delay can range from a few^seconds up to several minutes. Consequently, downholepressure measurements can not be input to the DAPC model 20 on a real time basis. Accordingly, it will be appreciated that there is likely to be a différence between themeasured downhole pressure, when transmitted up to thesurface, and the predicted downhole pressure for thatdepth at the time the data is received at surface. For 25 this reason, the downhole pressure data is time stamped or depth stamped to allow the control system tosynchronize the received pressure data with historicalpressure prédictions stored in memory. Based on thesynchronised historical data, the DAPC system uses a 30 régression method to compute adjustments to some input parameters to obtain the best corrélation betweenprédictions and measurements of downhole pressure. Thecorrections to input parameters may be made by varying 012776 - 20 - any of the available variable input parameters. In thepreferred embodiment, only the fluid density and thefluid viscosity are modified in order to correct thepredicted downhole pressure. Further, in the présent 5 embodiment the actual downhole pressure measurement is used only to calibrate the calculated downhole pressure.It is not utilized to directly adjust the backpressureset-point. If novel telemetry Systems offer increasedbandwidth or reduced transmission delay, it may then be 10 practical to include real time downhole pressure and température information for direct backpressure set-pointadjustments.

Figure 5 depicts the operation of the DAPC controlSystem demonstrating an uncalibrated DAPC model. It will 15 be noted that the downhole pressure measurement while drilling (PMWD) 400 is shifted in time as a resuit of theΛ time delay for the signal to be selected and transmitted• to .surface. As a resuit, there exists a significantoffset between the DAPC predicted pressure 404 and the 20 non-time stamped PMWD 400. When the PMWD is time stamped and shifted back in time 402, the differential betweenPMWD 402 and the DAPC predicted pressure 404 issignificantly less when compared to the non-time shiftedPMWD 400. Nonetheless, the DAPC predicted pressure 25 differs significantly. As noted above, this differential is addressed by modifying the model inputs for fluid 150density and viscosity. Based on the new estimâtes, inFig. 6, the DAPC predicted pressure 404 more closelytracks the time stamped PMWD 402. Thus, the DAPC model 30 uses the PMWD to calibrate the predicted pressure and modify model inputs to more accurately predict downholepressure throughout the entire borehole profile. 21 012776

Based on the DAPC predicted pressure, the DAPCcontrol System 236 will calculate the requiredbackpressure level 266 and transmit it to theprogrammable logic controller 240. The programmablecontroller 240 then generates the necessary controlsignais to choke 130, valves 121 and 123, andbackpressure pump 128 to achieve the desiredbackpressure.

Applications of the DAPC System

The advantage in utilizing the DAPC backpressureSystem may be readily in the chart of Fig. 7. Thehydrostatic pressure of the drilling fluid is depicted inline 302. As may be seen, the pressure increases as alinear function of the depth of the borehole according tothe simple formula: P = pgTVD + C (1j

Where P is the pressure, p is the fluid density, g is theaccélération of gravity, TVD is the vertical depth, and Cis the backpressure. The use of the DAPC permits anoperator to continuously adjust the annular pressure byadjusting the backpressure at surface. In this manner,the downhole pressure can be varied, as indicated by.line 303, in such a way that the downhole pressure -rèmains within the operational window limited by the porepressure 300 and the fracture pressure 306. It will beappreciated that the différence between the DAPCmaintained annular pressure 303 and the pore pressure 300, known as the overbalance pressure, issignificantly less than the overbalance pressure seenusing conventional. Highly overbalanced conditions canadversely affect the formation permeability be forcinggreater amounts of drilling fluid including fines intothe formation pore spaces. Furthermore, a high 012776 overbalance may reduce the rate of pénétration that canbe achieved.

Another application of the DAPC System is depicted inFig. 8. At depth z, a sudden increase in pore pressure 5 occurs, typical for for instance a small gas pocket.

Utilizing présent techniques, the answer would be toincrease the fluid density to prevent influx of formationfluids (commonly referred to as kick) and sloughing offof the borehole mud cake. The resulting increase in 10 density modifies the pressure profile applied by the fluid from line 321 to 321b.

Using the DAPC technique, the alternative response tothe pressure increase seen, would be to applybackpressure to the fluid to shift the pressure profile 15 to the right, such that pressure profile 322 more closely matches the pore pressure, as opposed to pressureprofile 321b. . The DAPC method of pressure control may also be used-to control a major well event, such as a fluid or gas 20 influx. Under présent methods, in the event such as a gas kick, the only option was to close the BOPs toeffectively shut in the well, and circulate out the gasthrough the kill manifold, and weight up the drillingfluid to provide additional annular pressure. For this 25 purpose, a supply of heavily weighted fluid, e.g., 18 pounds per gallon (ppg) (3.157 kg/1) is constantlyavailable during drilling operations.

Utilizing the présent DAPC technique, when aformation fluid influx is detected, the backpressure is 30 increased to the point where influx stops, as opposed to adding heavily weighted fluid. The influx is thencirculated out of the well while the system maintains a 012776 - 23 10 15 20 constant downhole pressure by adjusting the surface backpressure. A further application of the DAPC technique relatesto prevent problème with "formation breathing". Becausethe System is capable of maintaining a constant downholepressure, cyclic loss and gain of fluid will be reduceddramatically.

An additional application of the DAPC techniquerelates to its use in non-continuous circulating Systemsand is depicted in Fig. 9. As noted above, pressurevariations and spikes 502 and 504 that occur when the mudpumps are turned off to make/break new pipe connectionscan cause borehole instability. This pressure drop 502 issubsequently followed by a pressure increase 504 when thepumps are turned back on for drilling operations. This isdepicted in Fig. 9A. Furthermore, these variations in Λ annular pressure 500 can adversely affect the boreholemud cake, and can resuit in fluid invasion into theformation. As shown in Fig. 9B, the DAPC Systembackpressure 506 may be apply an pressure to the annulusso that the downhole pressure variations are compensated.Thus the DAPC backpressure System is capable ofmaintaining a relatively stable downhole pressure duringthe entire drilling process.

Although the invention has been described withreference to a spécifie embodiment, it will beappreciated that modifications may be made to the Systemand method described herein without departing from theinvention. 25

Claims

24 012776 WECLAIM:

1. A System for controlling formation pressure during the drilling of a subterranean formation, comprising: 5 a drill string extending into a borehole, the drill string including a bottom hole assembly, the bottom hole assembly comprising, drill bit, sensors, and a telemetry systemcapable of receiving and transmitting data, including sensor data, said sensor dataincluding at lcast pressure and température data; a surface telemetry system for receiving data and transmitting commands to the 10 bottom hole assembly; a primary pump for selectively pumping a drilling fluid from a drilling fluidsource, through said drill string, out said drill bit and into an annular space created as saiddrill string pénétrâtes the formation; a fluid discharge conduit in fluid communication with said annular space for15 discharging said drilling fluid to a réservoir to clean said drilling fluid for reuse; a fluid backpressure system connected to said fluid discharge conduit; said fluidbackpressure system comprised of a flow meter, a fluid choke, a backpressure pump, afluid source, whereby said backpressure pump may be selectively activated to increaseannular space drilling fluid pressure 20 a pressure monitoring system, capable of receiving drilling operational data, said drilling operational data including drill string weight on bit, drill string torque on bit,drilling fluid weight, drilling fluid volume, primary and backpressure pump pressures,drilling fluid flow rates, drill string rate of pénétration, drill string rotation rate, and sensordata transmitted by said bottom hole assembly, wherein said pressure monitoring system 25 utilizes said drilling operational data to: monitor existing said annular space pressures during drilling operations; 7model borehole expected pressures for continued drilling; andcontrol said primary pump and fluid backpressure system in response to existingannular pressures and borehole expected pressures. 25 012776
2. The System of claim 1, wherein said pressure monitoring System fuither includescommunication means, processing means, and control means for controlling said primarypump and fluid backpressure System.
3. The System of claim 1, wherein said fluid backpressure System fluid source is saiddrilling fluid source.
4. The system of claim 1, wherein said fluid backpressure System fluid source is saidfluid discharge outlet.
5. A method for controlling formation pressure during the drilling of a subterraneanformation, the steps comprising: deploying a drill string extending into a borehole, the drill string including abottom hole assembly, the bottom hole assembly comprising, drill bit, sensors, and atelemetry System capable of receiving and transmitting data, including sensor data, saidsensor data including at least pressure and température data; providing a surface telemetry system for receiving data and transmittingcommands to said bottom hole assembly; selectiveiy pumping a drilling fluid utilizing a primary pump from a drilling fluidsource, through said drill string, out said drill bit and into an annular space created as saiddrill string pénétrâtes the formation; providing a fluid discharge conduit in fluid communication with said annular spacefor discharging said drilling fluid to a réservoir to clean said drilling fluid for reuse; selectiveiy increasing annular space drilling fluid pressure utilizing a fluidbackpressure system connected to said fluid discharge conduit; said fluid backpressuresystem comprised of a flow meter, a fluid choke, a backpressure pump, and a fluid source; providing a pressure monitoring system for receiving drilling operational data, saiddrilling operational data including drill string weight on bit, drill string torque on bit,drilling fluid weight, drilling fluid volume, primary and backpressure pump pressures,drilling fluid flow rates, drill string rate of pénétration, drill string rotation rate, and sensordata transmitted by said bottom hole assembly, wherein said pressure monitoring system,utilizing said drilling operational data, further monitors existing said annular space pressures during drilling operations; models borchole expected pressures for continued drilling; an<P 27 Controls said primary pump and fluid backpressure System in response to existing annular pressures and borchole expected pressures.
6. The method of claim S, wherein said pressure monitoring System further includes communication means, processing means, and control means for controlling said primarypump and fluid backpressure system.
7. The method of claim 5, wherein said fluid backpressure System fluid source is said 10 drilling fluid source.
8. The method of claim 5, wherein said fluid backpressure System fluid source is saidfluid discharge outlet.