Hydraulics –Surge and Swab Pressures

•Swabbing
–When the drillstring is picked up to make a connection or trip out of the well, the mud in the annulus must fall to replace the volume of pipe pulled from the well.
–The hydrostatic pressure is momentarily reduced while the mud is falling in the annulus.
•Surging
–When the drillstring or casing is lowered or run into the well, mud is displaced from the well.
–The frictional pressure losses from the flow of mud in the annulus as it is displaced by the pipe causes pressures in excess of the hydrostatic pressure of the column of mud in the wellbore.
•Swab and surge pressures are related to the mud’s rheological properties:
–The mud’s gel strengths
–The speed at which the pipe is pulled from, or run into, the well
–The annular dimensions
–The length of drillstring in the well
•The rheological properties affect swab and surge pressures in the same manner as they affect annular pressure losses.
•Increases in either the plastic viscosity or the yield point will increase the swab and surge pressures.
•Since the maximum (not average) swab and surge pressures must be less than the pressures needed to swab the well in or break the formation down, swab and surge pressures must be calculated for the maximum drill string velocity when tripping.
•This is generally calculated as one-and-one-half times the average drill string velocity.
VMaxDrillstring(ft/min per stand) =(1.5 x stand length (ft) x 60 sec)/(min seconds per stand)
•The annular velocity must be calculated for each annular space.
•These annular velocities should be substituted into the API equations for the annular pressure losses for each interval.
•The swab and surge pressures are then calculated in the same manner as the ECD.
AVSwab-Surge(ft/min) =(VMaxDrillstring(ft/min) x drillstring displacement (bbl/ft))/(annular capacity (bbl/ft))
•The object of calculating swab and surge pressures is to determine safe pulling and running speeds and minimized trip times.
•This is done by changing the maximum or minimum time per stand and recalculating the swab and surge pressures until times per stand are found where the swab and surge pressures plus the hydrostatic pressure is approximately equal to the formation pressure and fracture pressure.
•This time per stand is only relevant for the present length of drillstring in the well.
•As pipe is removed from the hole, the drillstring length decreases and the bottom hole assembly will be pulled into large diameter casing.
•This will make it possible to pull each stand faster without risk of swabbing in the well.
•When tripping in to the well, the length of drillstring will be increasing and the annular spaces will decrease as the BHA is run into smaller diameters.
•This will require that the running time per stand be increased to avoid fracturing the formation.
•The swab and surge pressures should be calculated at either 500-or 1,000-ft intervals.
•Slip Velocity
–Free settling occurs when a single particle falls through a fluid without interference from other particles or container walls
•For Slip velocity we use stokes law
VS=( gC x DS*2(rS-rL))/(46.3μ)
–VS= Slip or settling velocity (ft/sec)
–gC= Gravitational constant (ft/sec2)
–DS= Diameter of the solid (ft)
–rS= Density of solid (lb/ft3)
–rL= Density of liquid (lb/ft3)
–μ= Viscosity of liquid (cP)
•This equation is a mathematical expression of events commonly observed:
–The larger the difference between the density of the cutting and the density of the liquid the faster the solid will settle.
–The larger the particle is the faster it settles
–The lower the liquid’s viscosity (1/μ), the faster the settling rate.

Hydraulics –ECD-Bit Hydraulics

•Equivalent circulating density (ECD)

–The pressure on a formation while circulating is equal to the total annular circulating pressure losses from the point of interest to the bell nipple, plus the hydrostatic pressure of the mud.
–This force is expressed as the density of mud that would exert a hydrostatic pressure equivalent to this pressure.
Formula for ECD
ECD (lb/gal) = Pa(psi)/ 0.052 x TVD (ft)
•Excessive ECD may cause losses by exceeding fracture gradient on a well
.•It is important to optimize rheological properties to avoid excessive ECD.

Bit Hydraulics

•In addition to bit pressure loss, several other hydraulics calculations are used to optimize the drilling performance.
•These include hydraulic horsepower, impact force and jet velocity calculations.
•Hydraulic Horsepower (hhp)
–The recommended hydraulic horsepower (hhp) range for most rock bits is 2.5 to 5.0 Horsepower per Square Inch (HSI) of bit area.
–Low hydraulic horsepower at the bit can result in low penetration rates and poor bit performance.
•Hydraulic Horsepower (hhp)
–The bit hydraulic horsepower cannot exceed the total system hydraulic horsepower.
hhpb= QPBit/1,740
–Q = Flow rate (gpm)
–PBit= Bit pressure loss (psi)
•Hydraulic Horsepower (hhp)
–Hydraulic Horsepower per square inch
HSI = 1.27 x hhpb/Bit Size*2
–Bit Size = Bit diameter (in.)
–System Hydraulic HorsepowerhhpSystem= PTotalQ1,714
–PTotal= Total system pressure losses (psi)

Nozzle Velocity

–Although more than one nozzle size may be run in a bit, the nozzle velocity will be the same for all of the nozzles.
–Nozzle velocities of 250 to 450 ft/sec are recommended for most bits.
–Nozzle velocities in excess of 450 ft/sec may erode the cutting structure of the bit.
•Nozzle Velocity
Vn(ft/sec) = 417.2 x Q/(Dn1*2+ Dn2*2+ Dn3*2+ …)
–Q = Flow rate (gpm)
–Dn= Nozzle diameter (32nds in.)
–Q = Flow rate (gpm)
•Percent pressure drop at the bi
t–It is generally desired to have 50 to 65% of surface pressure used across the bit.
%PBit= PBit x 100/PTotal
•Hydraulic impact force (IF)
IF (lb) = Vn x Qr/1,930
–Vn= Nozzle velocity (ft/sec)
–Q = Flow rate (gpm)
–r = Density (lb/gal)
–Impact force per inch squaredIF (psi) = 1.27 x IF (lb)/Bit Size*2

Hydraulics –Pressure losses

•The circulating system of a drilling well is made up of a number of components or intervals, each with a specific pressure drop.
•The sum of these interval pressure drops is equal to the total system pressure loss or the measured standpipe pressure.
•The total pressure loss for this system can described mathematically as:
PTotal= PSurf Equip+ PDrillstring+ PBit+ PAnnulus
•Surface pressure losses include losses between the standpipe pressure gauge and the drill pipe.
–This includes the standpipe, kellyhose, swivel, and kellyor top drive.
–To calculate the pressure loss in the surface connections, use the API pipe formula for pressure loss in the drill pipe.
•Top Drive Surface connections
–There is no current standard case for top drive units.
–The surface connections of most of these units consist of an 86-ft standpipe and 86 ft of hose with either a 3.0-or 3.8-in. ID. In addition, there is an “S”pipe that is different on almost every rig.
•Drill String Pressure losses
–The pressure loss in the drillstring is equal to the sum of the pressure losses in all of the drillstring intervals, including drill pipe, drill collars, mud motors, MWD/LWD/PWD or any other downhole tools.
•Friction Factor
–Before calculating the pressure loss, the Fanning friction factor (fp) is calculated next with different equations being used for laminar and turbulent flow.
–This friction factor is an indication of the resistance to fluid flow at the pipe wall.
–The friction factor in these calculations assumes a similar roughness for all tubulars.
•Formulas for friction Factor–If the Reynolds number is less than or equal to 2,100:
fp= 16/NRep
–If the Reynolds number is greater than or equal to 2,100
fp=((log n + 3.93)/50)/NRep((1.75 –log n)/7)
•Pipe Interval Pressure loss
–Drillstring (including drill collars) intervals are determined by the ID of the pipe.
–The length of an interval is the length of pipe that has the same internal diameter.
–The following equation is used to calculate the pressure loss for each drillstring interval.
•Formula for Pipe Pressure loss
•Pp(psi) =( fp x Vp*2 x r x L)/(92,916 x D)
•Vp= Velocity (ft/min)
•D = ID pipe (in.)
•r = Density (lb/gal)
•L = Length (ft)
•Pressure loss for motors and tools
–If the drillstring contains a downhole motor; an MWD, LWD or PWD tool; a turbine or a thruster, their pressure losses must be included in the system pressure losses when calculating the system’s hydraulics.
–These pressure losses can significantly change the pressure available at the bit, as well as bypass flow around the bit.
–The pressure loss through MWD and LWD tools varies widely with mud weight, mud properties, flow rate, tool design, tool size and the data transmission rate.
–Some manufacturers publish pressure losses for their tools but these pressure losses can be conservative, because they are usually determined with water.
–The pressure loss across motors and turbines cannot be accurately determined by formula, but, again, this pressure loss data is available from the suppliers.
–Regular nozzle type bit
Pbit= 156rQ*2/(Dn1*2+ Dn2*2+ Dn3*2+ …)*2
–Diamond type coring bitPbit= rQ*2/10,858(TFA)*2
–r = Density (lb/gal)
–Q = Flow ratio (gpm)
•Pressure loss in the annulus
–The total annular pressure loss is the sum of all of the annular interval pressure losses.
–Annular intervals are divided by each change in hydraulic diameter.
–A change in drillstring outside diameter and/or a change in casing, liner or open hole inside diameter would result in a hydraulic diameter change.
–As with the drillstring pressure loss equations, the friction factor must first be determined before calculating the pressure loss for each annular section.
–The pressure loss for each interval must be calculated separately and added together for the total annular pressure loss.
This equation is used to calculate the individual interval pressure losses.
Pa(psi) =( fa xVa x 2r x Lm)/((92,916 x D2)-D1)
–Va= Velocity (ft/min)
–D2= ID hole or casing (in.)
–D1= OD Drill pipe or collars (in.)
–r = Density (lb/gal)
–Lm= Length (ft)
-fa as before


–TFA = Total Flow Area (in.2)

Hydraulics

•Once the rheological properties for a fluid have been determined and modeled to predict flow behavior, hydraulics calculations are made to determine what effect this particular fluid will have on system pressures.
•The critical pressures are total system pressure (pump pressure), pressure loss across the bit and annular pressure loss (converted to ECD)
•Many wells are drilled under pressure limitations imposed by the drilling rig and associated equipment.
–The pressure ratings of the pump liners and surface equipment and the number of mud pumps available limit the circulating system to a maximum allowable circulating pressure.
•It is imperative to optimize drilling fluid hydraulics by controlling the rheological properties of the drilling fluid to avoid reaching this theoretical limit.
–This is especially true in extended-reach drilling.
•Fluids in laminar flow “act”differently than fluids in turbulent flow.
–These differences make it necessary to use different equations to determine the pressure losses in laminar and turbulent flow.
–Different equations are also required to calculate the pressure losses in the annulus and drillstring because of different geometries.
•The first step in hydraulics calculations is to determine which stage of flow is occurring in each geometric interval of the well.
•The velocity of the fluid in each of these intervals can be determined with the following equations.

Bulk Velocity

•Average bulk velocity in pipe (Vp):
Vp (ft/min) = 24.48 x Q (gpm)/(D)*2(in.)
•Average bulk velocity in annulus:Va (ft/min) =24.48 x Q (gpm)/ ((D2)*2–(D1)*2)(in.)

–V = Velocity (ft/min)
–Q = Flow ratio (gpm)
–D = Diameter (in.)

Reynolds Number

•The Reynolds number (NRe) is a dimensionless number that is used to determine whether a fluid is in laminar or turbulent flow.
–A Reynolds number less than or equal to 2,100 indicates laminar flow.
–A Reynolds number greater than 2,100 indicates turbulent flow.
–Earlier API hydraulics bulletins and many hydraulics programs that predate the current API hydraulics bulletin define laminar and turbulent flow differently.
•The general formula for Reynolds number is:
NRe= V Dr/μ
V = Velocity
D = Diameter
r = Density
μ= Viscosity
•The Reynolds number for inside the pipe is:
NRep= 15.467 x Vp x D x r/μep
•The Reynolds number for the annulus is:
NRea= 15.467x Va x (D2-D1) x r/μea
•D = ID drill pipe or drill collars
•D2= ID hole or casing
•D1= OD drill pipe or drill collars
•μep= Effective viscosity (cP) pipe
•μea= Effective viscosity (cP) annulus

Critical Velocity

•The critical velocity is used to describe the velocity where the transition occurs from laminar to turbulent flow.
•Flow in the drill pipe is generally turbulent.
•The equations for critical velocity in the pipe and in the annulus are listed below.
•Critical Pipe Velocity Vcp(ft/min)= ((38727 x Kp)/r)*(1/(2-n)) x ((1.6/D)x((3n+1)/4n)* (n(2-n))
•Critical Pipe Flow rate Qca(gpm)= VcpD*2/24.51
•Critical Annular Velocity Vca(ft/min)= ((25818 x Ka)/r)*(1/(2-n)) x ((2.4/(D2-D1))x((3n+1)/4n) *(n(2-n))
•Critical Annular Flow rate Qca(gpm)= Vca(D2-D1)*2/24.51

Rheology

•Fluid types
–There are two basic types of fluids, Newtonian and non-Newtonian.
–Rheological and hydraulic models have been developed to characterize the flow behavior of these two types of fluids.
•Newtonian fluids have a constant viscosity at a given temperature and pressure condition. Common Newtonian fluids include:
–Diesel
–Water
–Glycerin
–Clear brines
•Non-Newtonian fluids have viscosities that depend on measured shear rates for a given temperature and pressure condition. Examples of non-Newtonian fluids include:
–Most drilling fluids
–Cement

Rheological models

•Rheological models help predict fluid behavior across a wide range of shear rates.
•Most drilling fluids are non-Newtonian, pseudoplasticfluids.
•The most important rheological models that pertain to them are the:
–Bingham model
–Power law model
–Yield-power law or modified power law

•The Bingham model describes laminar flow using the following equation:
t = YP + (PV ×y)
–Where
–t is the measured shear stress in lb/100 ft2
–YP is the yield point in lb/100 ft2
–PV is the plastic viscosity in cP
–y is the shear rate in sec-1
•Current API guidelines require the calculation of YP and PV using the following equations:
•PV = 600rpm–300rpm
•YP = 300rpm–PV
•The power law model describes fluid rheological behavior using the following equation:
t = K ×(y)to the power n
•This model describes the rheological behavior of polymer-based drilling fluids that do not exhibit yield stress (i.e., viscosifiedclear brines).
•Some fluids viscosifiedwith biopolymers can also be described by power-law behavior.
•The general equations for calculating a fluid's flow index and consistency index are:
n =( log(t2/t1))/(log(y2/y1))
K = (t2)/(y2to the power n)
t is the calculated shear stress in lb/100 ft2
•t2is the shear stress at higher shear rate (600 rpm)
•t1is the shear stress at lower shear rate (300 rpm)
•n is the flow index
•y is the shear rate in sec-1
•y2is the higher shear rate (600)
•y1is the lower shear rate (300)
•K is the consistency index
•Because most drilling fluids exhibit yield stress, the Yield-power law [YPL]) model describes the rheological behavior of drilling muds more accurately than any other model.
•The YPL model uses the following equation to describe fluid behavior:
t = t0+ (K ×y)to the power n
–Where
–t is the measured shear stress in lb/100 ft2
–t0is the fluid's yield stress (shear stress at zero shear 0 rate) in lb/100 ft2
–K is the fluid's consistency index in cPor lb/100 ft2secn
–n is the fluid's flow index
–y is the shear rate in sec-1
•K and n values in the YPL model are calculated differently than their counterparts in the power law model.
•The YPL model reduces to the Bingham model when n = 1 and it reduces to the power law model when t0= 0.
•An obvious advantage the YPL model has over the power law model is that, from a set of data input, only one value for n and K are calculated.
–Note: The YPL model requires:
•A computer algorithm to obtain solutions.
•A minimum of three shear-stress/shear-rate measurements for solution. Model accuracy is improved with additional data input.

Pressure Control –Well Control Procedures cont

Well Control Procedures2

•The Wait-and-Weight Method
–After the well is shut in, the rig crew “waits”while the drilling fluid in the pits is “weighted”up to the kill-mud weight.
–In order to use this method successfully, sufficient weight material must be on location and the mixing capacity must be sufficient to maintain the kill-mud weight while circulating at the slow pump rate.
–This procedure is more complicated than the Driller’s Method.
–In the Driller’s Method, weighted mud is not pumped into the well until the kick has been circulated out of the well.
–The gas expansion is compensated for by maintaining a constant drill pipe pressure while circulating the kick out.
–When weighted mud is pumped into the well, the casing pressure is held constant until the weighted mud reaches the bit.
–This compensates for the changing hydrostatic pressure in the drill pipe.
•The Wait-and-Weight Method
–In the Wait-and-Weight Method, gas is expanding in the annulus while the hydrostatic pressure is increasing in the drill pipe.
–This requires that the pump pressure needed for maintaining a constant bottom-hole pressure must change as the fluid is circulated.
–A chart of the scheduled pump or drill pipe pressure changes simplifies the kill procedure and reduces the chance of error.
–The pressure schedule or graph determines the pump pressure while the kill mud is being pumped down the drill pipe.
–As the hydrostatic pressure in the drill pipe increases, the pump pressure necessary to maintain the correct bottom-hole pressure is reduced.
–Well-control worksheets for the Wait-and-Weight Method contain a pressure schedule graph.
–The schedule is drawn on standard rectangular coordinates.
–The vertical axis is for the pump pressure and the horizontal axis is for the pump strokes.
–At zero (0) pump strokes, plot the ICP on the pressure scale.
–Plot the surface-to-bit strokes and plot the FCP on the graph.
–Draw a straight line between the two points.
–It is not practical to try to maintain too fine a control on the drill pipe pressure while killing the well.
–Instead, make a chart that shows the pump pressure from the schedule at a selected stroke interval (i.e. 100, 150, 200 etc.).
–The pump pressure is maintained according to this pressure until the selected number of strokes is pumped.
–The pump pressure is then reduced to the next pressure until the stroke interval is pumped.
–This stair step fashion is continued until the kill mud reaches the bit.
–At that time, the pump pressure is held constant until the kill mud is observed at the surface.
•NOTE: The pump pressure will decrease on its own as the kill-mud weight is pumped down the drill pipe.
•This is due to the increase in hydrostatic pressure in the drill pipe.
•As a result, few, if any, choke adjustments are required while pumping kill mud down the drill pipe.
•Some adjustments will be required to account for the changing hydrostatic pressure in the annulus due to the intruding fluid moving up the annulus.
•The Wait-and-Weight Method–Once the kill-weight mud reaches the bit, the pump pressure is held constant at the Final Circulating Pressure (FCP) until the kill mud reaches the surface. –This FCP is calculated with the following equation.
FCP =( RCP x kill-mud weight)/(original mud weight)
–This equation calculates the reduced circulating pressure using the kill-mud weight as the circulating fluid.
–The calculations for pressures through these two sections of the circulating system are based on turbulent pressure losses and energy changes.
–Since the only significant change to the drilling fluid properties used to calculate these pressure losses is the mud density, the circulating pressure is increased by the ratio of the kill-mud weight to the original mud weight.
–The Initial Circulating Pressure (ICP) is calculated the same way as in the Driller’s Method:
ICP = RCP + SIDPP
–The pressure schedule is drawn using the ICP, FCP and the surface to-bit strokes.
–Shut the well in and record the pertinent kick information.
–Calculate the kill-weight mud.
–Begin increasing the mud weight in the surface pits to the kill-weight mud.
–Calculate the ICP.
–Calculate the FCP.
–Calculate the surface-to-bit strokes.
–Construct a pressure schedule.
–Open the adjustable choke and start pumping at the pre-selected slow pump rate.
–Adjust the choke to obtain a pump pressure equal to the ICP.
–Circulate out the kick following the pressure schedule using the adjustable choke.
–Maintain a constant pump rate throughout the
–circulating process.
–Maintain the mud weight in the surface system at the kill-mud weight.
–Once the kill mud reaches the bit, maintain the FCP until the kill mud is observed at the surface.
–Stop pumping and shut the well in to check for pressures.
–If shut-in pressures exist, additional mud weight and circulation will be required.
–If no shut-in pressures exist, the well is under control.
–At this time, one or two circulations can be made to condition the mud and increase the mud weight to provide a trip margin.
•The Circulate-and-Weight Method
–The Circulate-and-Weight (Concurrent) Method is used to circulate the kick out of the hole while increasing the density of the drilling fluid gradually to the kill-mud weight.
–The well is shut in only long enough to obtain the pertinent information about the kick situation.
–The calculations and techniques used in the Wait-and-Weight Method are used in the Circulate-and-Weight (Concurrent) Method.
–Start circulating with the initial circulating pressure and begin adding barite to the system until you reach the kill-weight mud.
–This method uses a gradual increase in mud weight as the kick is circulated out.
–The Circulate-and-Weight (Concurrent) Method is more complex than either the Driller’s Method or the Wait-and-Weight Method due to the various densities of drilling fluid in the drill pipe.
–The number of different densities and the volumes of each depends upon the mixing capability and circulating rate of the drilling rig used.
–A complicated pressure schedule is necessary, as is a precise knowledge of when a mud density was achieved and pumped down the drill pipe.
–Excellent communications between the choke operator and the mud pits is required.
–A pressure schedule similar to that of the Wait-and-Weight Method must be developed.
–The difference between the schedules is that the circulating pressure will be plotted vs. the mud weight.
–Use the Y-axis for the pressure and the X-axis for the mud weight.
–Three calculations will be required to complete the schedule:
•Kill-mud weight, ICP and FCP.
–The equations for these are the same as for the Wait-and-Weight Method.
–To construct the schedule, plot the ICP at the original mud weight.
–Then, plot the FCP at the kill-mud weight.
–Use a straight edge to connect the two points.
–Start circulating at the reduced circulating rate.
–Adjust the choke to reach the ICP.
–While circulating, begin increasing the density of the mud in the pits.
–When an increase of 0.1 lb/gal is achieved in the pits, determine the time it will take to reach the bit.
–When this density reaches the bit, decrease the circulating pressure to the value associated with the density on the pressure schedule.
–Maintain this pressure until a new density reaches the bit.
–At this time, reduce the pressure according to the pressure schedule.
–Continue this process until the mud weight at the bit has been increased to the kill-mud weight.
–Maintain the FCP until the kill-mud weight has been observed at the surface.
•The methods outlined in this topic have advantages and disadvantages.
•Knowing the specifics about the well will determine the appropriate method to be successful in circulating the intruding fluid out of the well and circulating the kill-mud into it.
•A brief list of advantages and disadvantages for each method is listed below.
•Wait-and-Weight Method
–Advantages
•Kills the well in one circulation.
•Subjects the casing shoe to the minimum amount of pressure due to additional hydrostatic pressure from the mud weight increase.
–Disadvantages
•The well is shut in for a long period of time with no circulation.
–A gas kick will migrate up the hole, increasing the pressure, unless pressures are monitored constantly.
–Fluids such as saltwater will contaminate the fluid, causing increases in fluid loss. This, in turn, increases the possibility of sticking the drillstring.
–A gas kick in oil-or synthetic-base fluid can strip the barite from the fluid due to the solubility of gas in the base fluid.
–Gas changes phases and acts as a liquid when it solubilizesin the oil-base mud.
–This dilutes the fluid and may reduce the viscosity enough to allow weight material to settle and plug the annulus.
•Requires more calculations than the Driller’s Method.
•Requires sufficient supplies of weight material and a good mixing system to maintain the density as the fluid is circulated.
•Concurrent Method
–Advantages
•Removes the intruding fluid in a minimum amount of time.
•Subjects the casing shoe to a reduced pressure due to increasing hydrostatic pressure.
•Weight-up can be adjusted as weight material supplies allow.
•Concurrent Method
–Advantages
•Removes the intruding fluid in a minimum amount of time.
•Subjects the casing shoe to a reduced pressure due to increasing hydrostatic pressure.
•Weight-up can be adjusted as weight material supplies allow.

Pressure Control –Well Control Procedures

this will be into 2 topics
Well Control Procedures 1

•Kick Detection
–Early detection of a kick is important.
–It can reduce the size of the kick, lower the quantity of pressure exerted on the casing shoe and simplify regaining control of the well.
•Indications that a kick has entered the well are:
–Increases in flow at the flow line.
–Increases in pit volume.
–Flow with the pump off.
–Hole taking insufficient mud volume on trip.
•Shut in the well
–When the warning signs of a kick are recognized, steps should be taken immediately to determine if the well is flowing and to shut the well in as quickly and safely as possible, to prevent any further influx into the wellbore.
–Reducing the size of the influx is a high-priority objective.
–A kick can occur while drilling or while tripping.
•Well Control Methods
–Once the well has been shut in, steps should be taken to circulate the intruding fluid out of the well.
–Also, the density of the drilling fluid should be increased to provide sufficient hydrostatic pressure to control the formation pressure.
–Over the years, several methods have been developed to circulate the kick out and weight up the drilling fluid.
–All recognized well-control methods use a constant, but slow, pump rate when circulating a kick out of the hole and replacing the light mud with kill mud.
–Additional formation fluids must be kept from entering the wellbore while the kick is being circulated out of the well and the weighted kill mud is being circulated.
–If the kick has not been allowed to flow back through the drill pipe and the bit is on bottom, the shut-in drill pipe pressure plus the hydrostatic pressure (PHYD) of the mud in the drill pipe is equal to the formation pressure.
–The information that should be recorded after taking a kick are:
•Measured depth.
•Total vertical depth.
•Mud weight.
•Shut-In Drill Pipe Pressure (SIDPP).
•Shut-In Casing Pressure (SICP).
•Kick volume.
•Fractured gradient.
•Casing TVD.
•Reduced Circulating Pressure (RCP).
•Reduced Circulating Rate (RCR).
•Reduced Pump Output (RPO).
–If off-bottom:
•Measured depth of bit.
•TVD of bit
–The first 6 items are taken at the time the kick is taken and the well is shut in.
–The next five items should be known or measured prior to taking a kick.
–They must be used to make the necessary calculations to circulate the kick out of the hole and to kill the well.
–The last 2 items apply if the kick occurs while tripping.
•The Driller’s Method
–The simplest of the approved well-control methods.
–It was developed to circulate the kick out of the well and circulate the kill mud into the well (in two circulations) with a minimum number of calculations.
–The method’s original purpose was to control wells with minimal supervision, poor mixing capabilities or insufficient weighting material on location.
•The Driller’s Method Procedure
–Shut the well in and record the pertinent kick information.
–Calculate the Initial Circulation Pressure (ICP):
ICP = RCP + SIDPP
–Open the adjustable choke and start pumping at the pre-selected slow pump rate.
–Adjust the choke to obtain a pump pressure equal to the ICP.
–Circulate the kick out by maintaining the ICP using the adjustable choke.
–Maintain a constant pump rate throughout the circulating process.
–Once the kick has been circulated out of the well, the well can be shut in.
–The SIDPP and the SICP should be equal, since the intruding fluid has been circulated out of the well.
–Calculate the kill-mud weight and weight up the fluid in the surface system.
–Open the adjustable choke and start pumping at the pre-selected slow pump rate.
–Adjust the choke to maintain the casing pressure at the SICP.
–Maintain the mud weight in the surface system at the kill-mud weight.
–Once the kill mud reaches the bit, record the pump pressure.
–Maintain this pump pressure by adjusting the choke until the kill mud is observed at the surface.
–Stop pumping and shut the well in to check for pressures.
–If shut in pressure exists, additional mud weight and circulation will be required.
–If no shut-in pressures exists, the well is under control.
–At this time, one or two circulations may be made to condition the mud and increase the mud weight to provide a trip margin.
•Driller’s Method
–Advantages
•Involves a minimal number of calculations (3).
•A simple procedure that can be understood by most rig crews.
•Removes the intruding fluid from the well in a minimum amount of time.
–Disadvantages
•Requires two circulations to kill the well.
•Subjects the casing shoe to the maximum amount of pressure due to no additional hydrostatic pressure from additional mud weight.

Geological Indicators of Increasing Pressure

Geological Indicators of Increasing Pressure

•Size and shape of cuttings cont
–These cuttings should not be confused with even larger, block shaped cuttings, which are rectangular.
–These block-shaped cuttings do not originate from the bottom of the well.
–They are formed by improper drillstring and bottom-hole assembly mechanics or existing fracturing.
•Sloughing shale and abnormal hole fill-up
–Sloughing shale and abnormal hole fill-up are indications of increasing formation pressure.
–As the transition zone is penetrated, the pore pressure within the shale will increase.
–Shales have relatively low permeability, but in a transition zone, shale porosity will increase.
•Sloughing shale and abnormal hole fill-up Cont.
–If this overpressure in the shale is not offset by increasing the hydrostatic pressure of the mud, the shale will collapse or slough into the annulus.
–This can cause enlarged holes through transition zones and fill on bottom during connections and trips.
•Bulk Density
–During normal shale compaction, water is squeezed out of the shale as the overburden pressure increases.
–Shale porosity decreases and density increases with depth.
–If normal compaction is interrupted by the formation of a seal, the formation water cannot be squeezed out of the shale.
•Bulk Density Cont.
–When this occurs, the fluid supports part of the overburden load and will have higher-than-normal pressure.
–Since fluids remain in the shale, the shales have a higher-than-normal porosity and lower-than-normal density.
•Bulk Density Cont.
–If shale densities are checked and plotted at regular intervals during drilling, a normal compaction trend is established for the predominant formation being drilled.
–When a seal is penetrated, the formation density will increase rapidly, followed by decreased density as the over compacted pressure seal and transition zone are drilled.
•Gas
–Gas is an indication of underbalanced formation pressure.
–When drilling is underway, most well-logging companies measure and record the gases entrained in the circulating fluid. It is helpful to classify this gas into one of three different categories:
•Background Gas
•Connection Gas
•Trip Gas
•Background gas
–This is the total gas entrained in the mud.
–The background gas which comes from the cuttings as the hole is being drilled is not an indication of increasing pressure and should not be compensated for with higher mud weight.
–Background gas from cuttings should always be circulated bottoms-up.
•Background gas cont
–A continued increase in background gas indicates a higher formation porosity and/or a higher hydrocarbon saturation in the available pore space.
–If lithology and ROP are given due consideration, an increase in background gas would indicate drilling into a transition zone.
•Connection gas
–the amount of gas in excess of the background gas.
–This is the increase in gas readings caused by the swabbing action of drillstring movement while a pipe connection is made.
–Pulling of the drillstring causes the effective bottom-hole pressure to be less than the hydrostatic pressure of the mud column.
–Such a reduction in hydrostatic pressure could lead to formation fluids feeding into the hole.
–A small but constant amount of connection gas is an indicator that the formation pressure is slightly less than the hydrostatic pressure, whereas a continuous increase of gas at each connection would indicate an increase in formation pressure.
–This is an excellent tool for detection of abnormal pressures when used in conjunction with background gas.
•Trip gas.
–This is the increase in gas associated with pulling the drillstring out of the hole.
–Trip gas is recorded when bottoms-up is being circulated out after a trip.
–The time period during which trip gas is being recorded gives some idea about the amount and the migration of gases in the
–annulus.
–This parameter is used in the same manner as connection gas, but is not as useful due to the long interval between trips.
–In some instances, a short trip will be made (10 to 20 stands) for the purpose of determining changes in pore pressure and changes in bottom-hole conditions.
•Gas-cut mud
–Gas-cut mud is the reduction in mud weight due to gas entrainment.
–Gas-cut mud is checked at the flow line, where the fluid will contain the maximum amount of gas.
–The use of gas-removal equipment, as well as surface retention time, will normally remove most or all of the gas from the mud.
–A continued reduction in mud weight due to gas is an indication of increasing gas content in the formations and the potential of increasing pore pressures
•Chloride ion
–Dissolved solids in the formation water are often correlated to total chloride concentration —or salinity, as it is commonly called.
–The salinity of water found in shale is known to increase with depth in a normally compacted sedimentary basin, but shows a decrease in a transition zone.
–In normally compacted formations, the salinity of water found in sandstone is known to follow the same trend, but at much higher concentrations than those found in shale.
–In a transition zone, the salinity of water in sands approaches that of water in the shales.
–The change in the salinity of the mud filtrate is not used for detecting abnormal pressures because it is affected by numerous variables and could give an erroneous indication of a transition zone.
•Flow-line temperature
–Increasing flow-line temperature is an excellent indicator of a transition zone.
–Since certain other variables affect flowlinetemperature, it is necessary to usean end-to-end plot.
•An end-to-end plot is constructed by identifying changes in flow-line temperature caused by a change in the variables, rather than a change in formation pressure

Flow-line temperature cont.–A normal trend can be established and departures from the normal trend can be readily recognized.–An end-to-end plot will produce a curve as shown in the Figure
–At about 150 to 300 ft above the seal, a marked decrease in flow-line temperature will be noted (Point A in the Figure).
–Usually, this decrease is 18 to 20°.
–After the seal is drilled, a very rapid increase in temperature will occur —to perhaps as much as 30 to 35°from the time the seal is drilled until a porous zone is encountered.
–Changes in flow-line temperature cannot be used to estimate formation pressures directly, due to flow-line temperature variables and because each geographic area has a different temperature gradient.
–Changes in flow-line temperature are a qualitative indication that a change in pressure may be occurring.