well control principles
DESCRIPTION
Well Control Principles. Well Control Principles. Primary Well Control Secondary Well Control Tertiary Well Control Hydrostatic Pressure Formation Pressure Porosity And Permeability Kill Mud Density Indications of Increasing Formation Pressure. Well Control Principles. - PowerPoint PPT PresentationTRANSCRIPT
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Well Control
Principles
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• Primary Well Control
• Secondary Well Control
• Tertiary Well Control
• Hydrostatic Pressure
• Formation Pressure
• Porosity And Permeability
• Kill Mud Density
• Indications of Increasing Formation Pressure
Well Control Principles
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The function of Well Control can be subdivided into 3 main categories:
• Primary Well Control: is the use of the fluid to prevent the influx of formation fluid into the well bore.
• Secondary Well Control: is the use of the BOP to control the well if Primary WC can not be maintained.
• Tertiary Well Control: squeeze back, cement ...
Well Control Principles
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when Hydrostatic Pressure = Formation PressureThe Well is Balanced:
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The Well is Under Balanced: when Hydrostatic Pressure < Formation Pressure
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The Well is Over Balanced:
when Hydrostatic Pressure > Formation Pressure
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Because the pressure is measured in psi and depth is measured in feet, it is convenient to convert Mud Weight
from ppg to a pressure gradient in psi/ft.
The conversion factor is 0.052
Fluid Density (ppg) x 0.052 = Pressure gradient (psi/ft)
Hydrostatic Pressure is the pressure exerted by a column of fluid at rest, and is calculated by multiplying the gradient of the fluid by the True Vertical Depth at which the pressure is
being measured:
Fluid gradient (psi/ft) x TVD = Hyd. Pressure(psi)
Hydrostatic Pressure
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You have to consider the vertical height or depth of the fluid column, the shape of the hole doesn’t matter.
T V D
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Normal formation pressure is equal to the hydrostatic pressure of the water occupying the pore spaces from the surface to the subsurface formation.
Native fluid is mainly dependent on its salinity and is often considered to be:
0.465 psi/ft
Normal Formation Pressure
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Abnormal formation pressures are any formation pressures that are greater than the hydrostatic pressure of the water occupying the pore spaces.
Commonly caused by the under-compaction of shale’s, clay-stone or faulting...
Abnormal Formation Pressure
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Subnormal Pressure: is defined as any formation pressure that is less than “normal” pressure.
It can be due to reservoir depletion,fault …
Transition Zone: is the formation in which the pressure gradient begins to change from a normal gradient to a subnormal gradient or, more usually, to an abnormal gradient.
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ENCLOSED SAND LENS WITH FORMATION FLUID
UNCONSOLIDATED
SHALE-DENSITY DECREASES WITH DEPTH-WATER ENCLOSED
SAND WITH COMMUNICATION TO SURFACE
SHALE-DENSITY INCREASES WITH DEPTH - WATER ESCAPES
UNDERCOMPACTED SHALES / SAND.
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GAS CAP
NORMAL FORMATIONPRESSURE ABOVE CAPROCK =0.465 PSI/FT
Pf
Pabnormal = Pf-Pg
Pg
GAS PRESSUREGRADIENT = 0.1 PSI/FT
COMMUNICATION BETWEEN FLUID AND GAS
Ph
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SURCHARGED FORMATIONS
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Pf
FAULT ZONE
NATURALLY SURCHARGED FORMATIONS
Pf
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POROUS SANDSTONEBELOW CAP ROCK
HYDROSTATICPRESSUREFROMFORMATIONWATERCOLUMN
LAKE
ARTESIAN WELL
NORMAL FORMATIONPRESSURE AT THE WELLUNTILL BELOW THE CAP
ROCK
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Pf
Pf
Pf
H1
H2
H3
SURFACE EROSIONENCLOSED FORMATION
LEVEL CHANGE
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The essential properties of reservoir rocks are: - Their porosity and permeability.
The porosity provides the storage space for fluids and gases and isthe ratio of the pore spaces in the rock to the bulk volume of the rock.This is expressed as a percentage. Reservoir rocks commonly haveporosity’s ranging from 5% to 30%.
Formation permeability is a measure of how easy the fluid will flowthrough the rock. Permeability is expressed in Darcys, from a fewmilliDarcys to several Darcys.
These properties will determine how much and how quick a kick will enter into the well. Kicks will enter a wellbore faster from rocks having high permeability.
Porosity & Permeability
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Tiny openings in rock are pores Porosity
Pores are connected for the Permeability
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When the well is shut in, Formation Pressure can be found with the following formula:
SIDPP + Hydrostatic pressure = Formation Pressure
SICP + Influx Hyd + Mud Hyd = Formation Pressure
Formation Pressure
Formation Pressure
SIDPP
+
Mud Hydrostatic
=
SICP
+
Mud Hydrostatic
+
Influx Hydrostatic
=
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KICK INDICATORS
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POSITIVE KICK SIGNS
Positive Indications of a kick:
- Flow from Well (pumps off)
- Increase in Flow from Well (pumps on)
- Pit Volume Gain
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KICKS WHILE TRIPPING
Incorrect Fill or Return Volumes
- Swabbing
- Surging
If any deviation, the FIRST action will be to install a fully open safety valve and make a Flow-Check.
Remember: It is possible that the well will not flow even if an influx has been swabbed in.
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KICKS WHILE DRILLING
Early Warning SignsThat the well MIGHT be going under-balanced
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Indications of Increasing Formation Pressure
• Increase in Drilling Rate
•Change in D - Exponent
• Change in Cutting size and shape
• Increase in Torque and Drag
•Chloride Trends
• Decrease in Shale Density
• Temperature Measurements
• Gas Cut Mud
• Connection Gas
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While drilling normally pressured shale and assuming a fairly constant bit weight, RPM, and hydraulic program, a
normal decrease in penetration rate can be expected. When abnormal pressure is encountered, differential pressure and shale density are decreased causing a
gradual increase in penetration rate.
ROP
Depth
Increase in Drilling Rate:
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Increase in torque and drag often occurs when drilling under balanced through some shale intervals.
There is a build up of cuttings in the annulus and this may be a sign that pore pressure is increasing.
Torque
Depth
Increase in Torque and Drag
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“d” is an indication of drill ability and ROP, RPM, WOB, bit size are used to calculate its value.
Trends of “d” normally increase with depth, but in transition zones, it may decrease with lower than expected
value.
“d”
Depth
Change in “d” Exponent:
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Normally pressured shale: cuttings are small with rounded edges, generally flat.
Abnormally pressured shale: cutting are long and splintery with angular edges.
As differential between the pore pressure and bottom pressure is reduced, the cuttings have a tendency to “explode” of bottom.
Change in cutting size and shape
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The chloride content of the mud filtrate can be monitored both going into and coming out of the hole.
A comparison of chloride trends can provide a warning or confirmation signal of increasing pore pressure.
Chloride
Depth
Chloride Trends:
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Shale density normally increases with depth but decreases as abnormal pressure zones are drilled.
When first deposited, shale has a high porosity. During normal compaction, a gradual reduction in porosity occurs
with an increase of the overlaying sediments.
Shale
Density
Depth
Decrease in Shale Density:
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The temperature gradient in abnormally pressured formations is generally higher than normal.
Temp.
Depth
Temperature Measurements:
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The presence of gas cut mud does not indicate that the well is kicking ( gas may have been entrained in the cutting ). However, the presence of gas cut
mud must be treated as an early warning sign of a potential kick.
- Gas cut mud only slightly reduces mud column pressure, when it is close to surface.
- Drilled cuttings from which the gas comes may compensate for the decrease.
Gas Cut Mud
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Connection gas are detected at the surface as a distinct increase above the background gas, as bottom up is circulated after a connection.
Connection gases may indicate a condition of near balance.
If connection gas is present, limiting its volume by controlling the drilling rate should be considered.
Connection Gas
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SYSTEM PRESSURE LOSSES
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Objectives
• Identify the different pressures losses in the system
• Identify which one influence bottom hole pressure
• Convert this pressure to an equivalent mud weight
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Mud System Pressure Losses
• Pumping through a pipe with a mud pump at 80 spm, with gauges mounted on the discharge of the pump and at the end of the pipe.
• The gauge on the pump reads 100 psi.
• The gauge on the end of the pipe reads 0 psi.
• It can be assumed from this information that the 100 psi drop in pressure through the pipe is the result of friction losses in the pipe as the fluid is pumped through it.
100 psi100 psi
100 psi100 psi
0 psi0 psi
80 SPM80 SPM
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500 psi500 psi
100 psi100 psi
400 psi400 psi
0 psi0 psi
400 psi400 psi
Mud System Pressure Losses
80 SPM80 SPM
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1000 psi1000 psi
100 psi100 psi
900 psi900 psi
500 psi500 psi400 psi400 psi
0 psi0 psi
500 psi500 psi
Mud System Pressure Losses
80 SPM80 SPM
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2300 psi2300 psi
100 psi100 psi
2200 psi2200 psi
1800 psi1800 psi400 psi400 psi
1300 psi1300 psi
500 psi500 psi
1300 psi1300 psi
Mud System Pressure Losses
0 psi0 psi
80 SPM80 SPM
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2600 psi2600 psi
100 psi100 psi
2500 psi2500 psi
2100 psi2100 psi400 p
si400 p
si
1600 psi1600 psi
500 psi
500 psi
1300 psi1300 psi
0 psi0 psi
300 psi300 psi
300
psi
300
psi
Mud System Pressure Losses
Annular
Pressure
Losses
80 SPM80 SPM
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APL EXAMPLE• A well has been drilled to
10,000 ft.
• The mud weight is 10 ppg.
• To find our Hydrostatic pressure we use the following formula;
• Mud Wt x 0.052 x TVD 10 x 0.052 x 10,000 = 5,200psi.
• The gauge on the drawing shows bottom hole hydrostatic pressure.
0 psi0 psi
0 psi0 psi0 psi0 psi
0 psi0 psi
0 psi0 psi
5200 psi5200 psi
10,000 ft TVD10,000 ft TVD
MUD WT = 10 ppgMUD WT = 10 ppg
Mud System Pressure Losses
0 SPM0 SPM
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APL EXAMPLE
• If we now start to circulate at 80 spm through our system with the same pressure losses as before.
• As you can see from this example the bottom hole pressure has increased by 300 psi.
• This increase is due to the Annular Pressure Losses (APL) acting down on the bottom of the well and is usually called “Bottom Hole Circulating Pressure” (BHCP)
2600 psi2600 psi
100 psi100 psi
2500 psi2500 psi
2100 psi2100 psi
400 psi400 psi
1600 psi1600 psi
500 psi500 psi
1300 psi1300 psi
0 psi0 psi
5500 psi5500 psi
300
psi
300
psi
10,000 ft TVD10,000 ft TVD
MUD WT = 10 ppgMUD WT = 10 ppg
Mud System Pressure Losses
80 SPM80 SPM
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Equivalent Circulating Density
The APL while circulating has the same effect on bottom hole pressure as increasing the mud
weight.
This theoretical increase in mud weight is called the Equivalent Circulating Density or Equivalent
Mud Weight.
It can be calculated by using the following formula:
_____APL(psi) __ + Original Mud Weight
TVD x 0.052
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•Annular Pressure Losses are the pressure losses caused by the flow of fluid up the annulus and are the only losses in the system that affect BHP.
•Equivalent Circulating Density is the effective density at any depth created by the sum of the total hydrostatic plus the APL.
Summary:
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300 psi300 psi
600 psi600 psi
800 psi800 psi
1200 psi1200 psi
450
psi
450
psi
MUD WT = 12 ppgMUD WT = 12 ppg
MD = 9,550 ftMD = 9,550 ft
TVD = 8,000 ftTVD = 8,000 ft
Exercise- Pressure Gradient?
- Hydrostatic Pressure?
- Pump Pressure @ 40 spm?
- A P L?
- ECD at 40 SPM?
40 SPM40 SPM
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EFFECTS ON PRESSURES
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MUD WEIGHT CHANGE
• A well is being drilled using 10 ppg mud. At 80 spm the total circulating system pressure losses are 2600 psi.
• It is decided to increase the mud weight to 11 ppg.
2600 psi2600 psi
Mud wt 10 ppg
80 spm
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It is a good drilling practice to calculate the new circulating pressure before changing the mud weight.
The way we calculate this change in pressure is to use the following formula;
New Mud ppg x Old psi.
Old Mud ppg
11 ppg x 2600 = 2860psi
10 ppg
The new pump pressure would be approximately 2860 psi.
2860 psi2860 psi
Mud wt 11 ppg
80 spm
MUD WEIGHT CHANGE
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Final Circulating Pressure
• The formula that was just used to calculate the pressure change due to a change in mud weight, is also the formula used to calculate the Final Circulating Pressure.
Kill Mud wt x Slow circulating rate press .
Old Mud wt
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PUMP STROKE CHANGE
• A well is being drilled using 10 ppg mud. At 80 spm the total circulating system pressure losses are 2600 psi.
• It is decided to increase the pump speed from 80 spm to 100 spm.
2600 psi2600 psi
Mud wt 10 ppg
80 spm
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• It is a good drilling practice to calculate the new circulating pressure before changing the pump speed.
• The way we calculate this change in pressure is to use the following formula;
• New SPM 2 Old psi x Old SPM
• 2600 x 100 spm 2 80 spm = 4063 psi
• The new pump pressure would be approximately 4063 psi.
4063 psi4063 psi
Mud wt 10 ppg
100 spm
PUMP STROKE CHANGE
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Preparation
and
Prevention
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• Barite and Mud chemical stocks
• Equipment line up for shut-in
• Slow circulating rates
• M A A S P
• Well Control Drills
• Flow Checks
• Safety Valves and Float Valves
Preparation and Prevention
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FLOWPATH
LINE UP FORHARD SHUT IN
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FLOWPATH
HARD SHUT INPick off bottom and position string
Stop pumps & Rotation
Close BOP (Ram or Annular)
Open hydraulic side outlet valve
Observe pressure 1
1
2
2
3
3
4
4
5
5
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LINE UP FORSOFT SHUT IN
FLOWPATH
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SOFT SHUT INPick off bottom and position string
Stop pumps & Rotation
Open hydraulic side outlet valve
Close BOP (Ram or Annular)
Close remote hydraulic choke
Observe pressure
1
1
2
2
3
3
4
4
5
5
6
6
FLOWPATH
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• A Slow Circulating Rate ( SCR) is the reduced circulating pump rate that is used when circulating out a kick.
• It is called Dynamic Pressure Losses ( PL ) on the kick sheet
Slow Circulating Rate
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Well Control Operations are conducted at reduced circulating rates in order to:
• Minimise Excess of annulus pressure• Allows for more controlled choke adjustments• Allows for the weighting up and degassing of
the mud and disposal of the influx• Reduce the chance of choke erosion• Reduce risk of over pressuring system if
plugging occurs
Slow Circulating Rate
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SCR’s pressure for each pump will be taken:
• If practical, at the beginning of every tour• Any time the mud properties are changed• When a bit nozzle is changed.• When the BHA is changed.• As soon as possible after bottoms-up from
any trip• At least every 1000 feet (305m) of new hole
Slow Circulating Rate
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• A minimum of 2 (two) circulating rates should be obtained for all pumps.
• The pressure must be recorded using the gauges that will be used during well kill operations
• The SCR pressure will be recorded on the IADC report
Slow Circulating Rate
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Formation Strength Test or LOT
A leak off test (LOT) determines the pressure at which the formation begins to take fluid.
This test is conducted after drilling out about 10 to 15 ft of new hole below the shoe.
Such a test will establish the strength of the formation and the integrity of the cement job at the shoe.
The test pressure should not exceed 70% of the minimum yield of the weakest casing.
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Use a high pressure, low volume pump (0.25 - 0.5 bbl/min.) such as a cement pump or a test pump using intermittent or continuous method of pumping. Rig pumps are not suitable to perform leak off tests.
The objective of the above test is not to fracture the formation, but rather to identify the “formation intake pressure”.This “intake pressure” is identified as that point where a deviation occurs between the trends of the final pump pressure curve and the static pressure curve. Once the formation intake pressure has been reached, further pumping should be avoided.
L O T
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65
+ Hydrostatic Pressure
=
Pressure at Shoe
Surface Casing
Pressure
The total pressure applied at the shoe is the sum of the surface pressure from the pump and the hydrostatic
pressure for the shoe depth.
This total pressure is applied to the formation.
L O T
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3,000’
720 psi
9.6 ppg
+
1498 psi
2218 psi
720 psi
This total pressure is applied to the formation.
L O T
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The Maximum Available Fluid Density (MAMW).
This is the total pressure, represented as fluid density,
above which leak off or formation damage may occurs with no pressure on surface.
2218 psi
0 psi
3,000’
MAMW= 2218
3000 x 0.052
MAMW = 14.2 ppg
M A M W
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68
2218 psi
0 psi
3,000’
The fracture gradient of the formation will be:
Fracture gradient = MAMW x 0.052
Fracture Gradient = 14.2 x 0.052
= 0.7384 psi/ft
therefore:
MAMW = Fracture Gradient / 0.052
Fracture Gradient
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MAASP is defined as the surface pressure which, when added to the hydrostatic pressure of the existing mud column, results in formation breakdown at the weakest point in the well.
This value is based on the Leak Off Test data.
Maximum Allowable Annular Surface pressure
M A A S P
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On Kill Sheet
Calculate current MAASP and insert here
Write mud weight used for the test
Calculate maximum allow mudweight and Insert here
Write leak off test pressure here
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71
Drills
• Pit drill
• Trip drill
• Abandonement drill
• Strip drill
![Page 72: Well Control Principles](https://reader038.vdocument.in/reader038/viewer/2022102419/56814bed550346895db8cfac/html5/thumbnails/72.jpg)
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Actions
Upon
Taking a Kick
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• Causes for the Loss of Primary Well Control
• Kick Size and Severity
• Kick Detection
• Recording Pressures
• Drilling With Oil Base Mud
• Hard Shut-in
• Soft Shut-in
• Height and Gradient of a Kick
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Causes for the loss of Primary Well Control
• Failure to Fill The Hole Properly While Tripping
• Swabbing / Surging
•High pulling speed
•Mud properties
•Tight annulus clearance
•Well Geometry
•Formation Properties
• Lost Circulation
• Insufficient Drilling Fluid Density
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Kick Size and SeverityMinimizing kick size is fundamental for the safety of a Well Control operation.Smaller Kicks: Provide lower choke or annulus pressure both upon initial closure and later when the kick is circulated to the choke.
Controllable Parameters: You can influence on:
• Degree of underbalance Mud Weight
• Length of reservoir exposed ROP + Kick detection time
• Time well remains underbalanced Kick detection + shut-in time
• Wellbore diameter Hole size
Non-controllable Parameters
• Formation permeability and type of influx
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While Drilling:
• Drilling breaks: They will be flow checked. Circulating B/up is advisable if F/C is negative. Tool pusher must be informed for all.
• Increase in flow rate: First positive indicator.
• Increase in pit volume: Positive indicator. Anyone influencing the active system must communicate with the Driller.
• Variation in Pump speed and Pressure: (“U-tube”)
• Well flowing during a Connection: ECD to ESD
• Change of drilling fluid properties: Gas cut or fluid contaminated.
While Tripping:
• Improper fill-up: swabbing or surging
Kick Detection
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• Stop rotation
• Pick up the drill string to shut-in position (subsea to hang off position)
• Stop the pump
• Flow check
If the well flows• Close BOP
• Open remote control choke line valve
• Notify Tool Pusher and OIM
• Record time, SIDPP, SICP and pit gain
Shut- in Procedure: HARD SHUT-IN
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•Stop rotation
• Pick up the drill string to shut-in position (Subsea to hang off position)
•Stop the pump
• Flow check
If the well flows• Open remote control choke line valve
• Close BOP
• Close choke
• Notify Tool Pusher
• Record time, SIDPP, SICP and pit gain
Shut- in Procedure: SOFT SHUT-IN
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Close-in Methods specified byAmerican Petroleum Institute
• Soft close-in procedure• For a soft close-in, a choke is left open
at all times other than during a well control operation. The choke line valves are aligned such that a flow path is open through the choking system, with the exception of one choke line valve located near the blow out preventer. When the soft close-in procedure is selected for closing in a well the:
• 1 choke line valve is opened.• 2 Blow out preventer is closed.• 3 Choke is closed.• This procedure allows the choke to be
closed in such a manner to permit sensitive control and monitoring of casing pressure buildup during closure.
• Hard close-in procedure• For a hard close-in, the chokes remain
closed at all times other than during a well control operation. The choke line valves are aligned such that a flow path is open through the choking system with the exemption of the choke(s) itself and one choke line valve located near the blow out preventer stack. When the hard close-in procedure is selected for closing in a well, the blow out preventer is closed. If the casing pressure cannot be measured at the well head, the choke line valve is opened with the choke or adjacent high pressure valve remaining closed so that pressure can be measured at the choke manifold. This procedure allows the well to be closed in the shortest possible time, thereby minimising the amount of additional influx of kicking fluid to enter the well bore.
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Surface Pressure After Shut-in
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OIL BASE MUD
![Page 82: Well Control Principles](https://reader038.vdocument.in/reader038/viewer/2022102419/56814bed550346895db8cfac/html5/thumbnails/82.jpg)
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Drilling with OBM
![Page 83: Well Control Principles](https://reader038.vdocument.in/reader038/viewer/2022102419/56814bed550346895db8cfac/html5/thumbnails/83.jpg)
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Gas Influx in WBM or in OBM
Water Base Mud
• Easier to detect
• Higher migration rate
• Gas stay as a separate phase
• On bottom bigger kick size
• Higher casing pressure
• Expansion:
- Slow first then Fast
Oil Base Mud
• More difficult to detect
• Lower migration rate
• Gas go into solution
• On bottom smaller kick size
• Smaller casing pressure
• Expansion:
- none first then very fast at the bubble point
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Height and Gradient of a Kick
![Page 85: Well Control Principles](https://reader038.vdocument.in/reader038/viewer/2022102419/56814bed550346895db8cfac/html5/thumbnails/85.jpg)
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Well Kill
Techniques
![Page 86: Well Control Principles](https://reader038.vdocument.in/reader038/viewer/2022102419/56814bed550346895db8cfac/html5/thumbnails/86.jpg)
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• Driller’s Method
• Wait and Weight Method
•Volumetric Method
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Well Kill Techniques
![Page 88: Well Control Principles](https://reader038.vdocument.in/reader038/viewer/2022102419/56814bed550346895db8cfac/html5/thumbnails/88.jpg)
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Driller’s Method : 1 st Circulation
The original mud weight is used to circulate the influx
- Reset the stroke counter.
- Bring the pump up to kill speed while holding the casing pressure constant.
- Maintain DP pressure constant until the influx is circulated out from the well
BHP
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Driller’s Method : 1 st Circulation
The maximum shoe pressure is when the top of the influx reaches the shoe
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Driller’s Method : 1 st Circulation
When the influx is passing the casing shoe, the shoe pressure will decrease.
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Driller’s Method : 1 st Circulation
When the influx is above the casing shoe, the shoe pressure will remain constant.
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Driller’s Method : 1 st Circulation
- Surface casing pressure is increasing as the influx is circulated up the well.
- Pit volume is raising.
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Driller’s Method : 1 st Circulation
- The maximum surface casing pressure is reached when the top of the influx is at surface.
- It will be the maximum increase in pit level.
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Driller’s Method : 1 st Circulation
- As the influx is passing through the choke, the surface casing pressure will decrease.
- The pit volume will decrease.
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Driller’s Method : 1 st Circulation
If all the influx is successfully circulated from the well and the pump is stopped,
SIDPP = SICP
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Driller’s Method : 2 nd Circulation
- Line up the kill mud.
- Reset the stroke counter.
- Bring the pump up to kill speed while holding the casing pressure constant.
- Reset the stroke counter after pumping the surface line volume.
- Keep the casing pressure constant until KMW reach the bit.
( Or follow the calculated DP pressure drop schedule from ICP to FCP.)
Pit volume has increased due to the weighting material added in the system.
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Driller’s Method : 2 nd Circulation
When kill mud enters the annulus, maintain FCP constant until kill mud is at surface.
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Driller’s
Method
Driller’s
Method
Drill Pipe
Casing
First Circulation
![Page 99: Well Control Principles](https://reader038.vdocument.in/reader038/viewer/2022102419/56814bed550346895db8cfac/html5/thumbnails/99.jpg)
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Driller’s
Method
Driller’s
Method
Drill Pipe
Casing
Second Circulation
![Page 100: Well Control Principles](https://reader038.vdocument.in/reader038/viewer/2022102419/56814bed550346895db8cfac/html5/thumbnails/100.jpg)
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Driller’s MethodAdvantages:
- Can start circulating right away
- Able to remove influx even if not enough barite on board
- Less chance of gas migration
- Less calculation
Disadvantages:
- Higher surface pressure
- In certain situation, higher shoe pressure
- Two circulation, more time through the choke
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Wait and Weight-The kill mud weight is used to circulate the influx
-Reset the stroke counter
- Bring the pump up to kill speed while Holding the casing pressure constant.
- Reset the stroke counter after pumping the surface line volume.
-Pump kill mud from surface to bit while following a calculated DP pressure drop schedule.
BHP
![Page 102: Well Control Principles](https://reader038.vdocument.in/reader038/viewer/2022102419/56814bed550346895db8cfac/html5/thumbnails/102.jpg)
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When kill mud enters the annulus, maintain FCP constant until kill mud is at surface.
Wait and Weight
![Page 103: Well Control Principles](https://reader038.vdocument.in/reader038/viewer/2022102419/56814bed550346895db8cfac/html5/thumbnails/103.jpg)
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Drill Pipe
Casing
Wait&
Weight
Wait&
Weight
One Circulation Only
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Wait & Weight MethodAdvantages:
- Can generate lower pressure on formation near the casing shoe
- In most situation generate less pressure on surface equipment
- With a long open hole, less chance to induce losses
- One circulation, less time spent circulating through the choke
Disadvantages:
- Longer waiting time prior to circulate the influx
- Cutting could settle down and plug the annulus
- Gas migration might become a problem
- Need to have enough barite to increase the mud weight
- More Calculations
![Page 105: Well Control Principles](https://reader038.vdocument.in/reader038/viewer/2022102419/56814bed550346895db8cfac/html5/thumbnails/105.jpg)
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Drillers MethodGas at Casing Shoe
h'i
hm
W & W MethodGas at Casing Shoe,kill mud in drill string
h'i
hm
Differences between W&W and Driller’s methods
![Page 106: Well Control Principles](https://reader038.vdocument.in/reader038/viewer/2022102419/56814bed550346895db8cfac/html5/thumbnails/106.jpg)
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Drillers MethodGas at Casing Shoe
h'i
hm
W & W Method Gas at Casing Shoe,Kill mud in annulus
h''i
hm
hkm
Differences between W&W and Driller’s methods
![Page 107: Well Control Principles](https://reader038.vdocument.in/reader038/viewer/2022102419/56814bed550346895db8cfac/html5/thumbnails/107.jpg)
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• Free gas expansion
• No gas expansion
• Volume to bleed off to maintain BHP constant
Gas Behavior
![Page 108: Well Control Principles](https://reader038.vdocument.in/reader038/viewer/2022102419/56814bed550346895db8cfac/html5/thumbnails/108.jpg)
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Gas may be swabbed into a well and remain at TD. The influx will expand as it moves up the annulus when circulation is started. The amount of expansion can easily be calculated. If undetected, free gas expansion can cause a serious well
control problem.
Free Gas Expansion
![Page 109: Well Control Principles](https://reader038.vdocument.in/reader038/viewer/2022102419/56814bed550346895db8cfac/html5/thumbnails/109.jpg)
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DPVg
D=
10,0
00ft
CST
10,0005,000
15,000
Gm = 0.5 psi/ft
A column of 10,000ft of mud, Gm=0.5psi/ft compresses one barrel of gas at TD.
The pressure in the gas is;10,000 x 0.5 = 5,000 psi
Multiply P x Vg to find the constant.
Gas
Free Gas Expansion
![Page 110: Well Control Principles](https://reader038.vdocument.in/reader038/viewer/2022102419/56814bed550346895db8cfac/html5/thumbnails/110.jpg)
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D
PVg
D=
5,00
0ft
PVg
10,0005,000
15,000
Gm = 0.5 psi/ft
The gas has risen so that the top of the bubble is at 5,000ft from the surface.
The pressure in the gas is;5,000 x 0.5 = 2,500 psi
Using the constant, the volume of gas is found: 5,000 / 2,500 = 2 barrels
5,0002,500
25,000
Free Gas Expansion
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DPVg
PVg
10,0005,000
15,000
The top of the bubble is at 2,500ft from the surface.
The pressure in the gas is;2,500 x 0.5 = 1,250 psi
The volume of gas is found: 5,000 / 1,250 = 4 barrels
5,0002,500
25,000
2,5001,250
45,000
D=
2,50
0ft
Free Gas Expansion
Gm = 0.5 psi/ft
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At 1,250ft from the surface.
Pressure;1,250 x 0.5 = 625 psi
Volume of gas; 5,000 / 625 = 8 barrels
D=
1,25
0ft
DPVg
PVg
10,0005,000
15,000
5,0002,500
25,000
2,5001,250
45,000
1,250625
85,000
Free Gas Expansion
Gm = 0.5 psi/ft
![Page 113: Well Control Principles](https://reader038.vdocument.in/reader038/viewer/2022102419/56814bed550346895db8cfac/html5/thumbnails/113.jpg)
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DPVg
PVg
10,0005,000
15,000
5,0002,500
25,000
2,5001,250
45,000
1,250625
85,000
014.7341
5,000
Free Gas Expansion
Gm = 0.5 psi/ft
![Page 114: Well Control Principles](https://reader038.vdocument.in/reader038/viewer/2022102419/56814bed550346895db8cfac/html5/thumbnails/114.jpg)
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0 ft
2,500 ft
5,000 ft
7,500 ft
10,000 ft
0 psi
5,200 psi
1 bbls
1 bbl gain
Gm = 0.52 psi/ft
No Gas Expansion
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0 ft
2,500 ft
5,000 ft
7,500 ft
10,000 ft
0 psi 1,300 psi
6,500 psi5,200 psi
1 bbls
1 bbls
1 bbl gain 1 bbl gain
Gm = 0.52 psi/ft
No Gas Expansion
![Page 116: Well Control Principles](https://reader038.vdocument.in/reader038/viewer/2022102419/56814bed550346895db8cfac/html5/thumbnails/116.jpg)
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0 ft
2,500 ft
5,000 ft
7,500 ft
10,000 ft
0 psi 1,300 psi 2,600 psi
7,800 psi6,500 psi5,200 psi
1 bbls
1 bbls
1 bbls
1 bbl gain 1 bbl gain 1 bbl gain
Gm = 0.52 psi/ft
No Gas Expansion
![Page 117: Well Control Principles](https://reader038.vdocument.in/reader038/viewer/2022102419/56814bed550346895db8cfac/html5/thumbnails/117.jpg)
117
0 ft
2,500 ft
5,000 ft
7,500 ft
10,000 ft
0 psi 1,300 psi 2,600 psi 3,900 psi
7,800 psi 9,100 psi6,500 psi5,200 psi
1 bbls
1 bbls
1 bbls
1 bbls
1 bbl gain 1 bbl gain 1 bbl gain 1 bbl gain
Gm = 0.52 psi/ft
No Gas Expansion
![Page 118: Well Control Principles](https://reader038.vdocument.in/reader038/viewer/2022102419/56814bed550346895db8cfac/html5/thumbnails/118.jpg)
118
0 ft
2,500 ft
5,000 ft
7,500 ft
10,000 ft
0 psi 1,300 psi 2,600 psi 3,900 psi 5,200 psi
7,800 psi 9,100 psi 10,400 psi6,500 psi5,200 psi
1 bbls
1 bbls
1 bbls
1 bbls
1 bbls
1 bbl gain 1 bbl gain 1 bbl gain 1 bbl gain 1 bbl gain
Gm = 0.52 psi/ft
No Gas Expansion
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0 ft
2,500 ft
5,000 ft
7,500 ft
10,000 ft
500 psi 1800 psi 500 psi
5,700 psi7000 psi5,700 psi
1 bbls
1bbls1.3bbls
1 bbl gain 1 bbl gain 1.3 bbl gain
Volume to bleed off to keep BHP constant
2500 x .52 = 1300 psi
5700 psi 4400 psi
P1V1 = P2V2
V2 = 5700 x 1 / 4400
V2 = 1.29 bbls
Gm = 0.52 psi/ft
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0 ft
2,500 ft
5,000 ft
7,500 ft
10,000 ft
500 psi 1800 psi 500 psi
5,700 psi7,000 psi5,700 psi
1.3 bbls
1.3bbls
1.84bbls
1.3 bbl gain 1.3 bbl gain 1.84 bbl gain
5000 x .52 = 2600 psi
4400 psi
3100 psi
P1V1 = P3V3
V3 = 5700 x 1 / 3100
V3 = 1.84 bbls
Gm = 0.52 psi/ft
Volume to bleed off to keep BHP constant
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0 ft
2,500 ft
5,000 ft
7,500 ft
10,000 ft
500 psi 1800 psi 500 psi
5,700 psi7,000 psi5,700 psi
1.8 bbls
1.8bbls 3.16bbls
1.84 bbl gain 1.84 bbl gain 3.16 bbl gain
7500 x .52 = 3900 psi
3100 psi 1800 psi
P1V1 = P4V4
V4 = 5700 x 1 / 1800
V4 = 3.16 bbls
Gm = 0.52 psi/ft
Volume to bleed off to keep BHP constant
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0 ft
2,500 ft
5,000 ft
7,500 ft
10,000 ft
500 psi 1800 psi 500 psi
5,700 psi7,000 psi5,700 psi
3.16 bbls
3.16 bbls 11.4bbls
3.16 bbl gain 3.16 bbl gain 11.4 bbl gain
10000 x .52 = 5200 psi
1800 psi 500 psi
P1V1 = P5V5
V5 = 5700 x 1 / 500
V5 = 11.4 bbls
Gm = 0.52 psi/ft
Volume to bleed off to keep BHP constant
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123
WELL # 1HOLE SIZEHOLE DEPTH TVD/MDCASING 9-5/8” TVD/MDDRILL PIPE CAP.HEAVY WALL DRILL PIPECAPACITYDRILL COLLARS 6-1/4”CAPACITYDRILLING FLUID DENSITYCAPACITY OPEN HOLE/COLLARSCAPACITY OPEN HOLE/DRILL PIPE-HWDPCAPACITY CASING/DRILL PIPEFRACTURE FLUID DENSITYSIDPPSICPPUMP DISPLACEMENTRRCP 30 SPMPIT GAIN
8-1/2 INCH11536 FEET9875 FEET0.01741 BBL/FEET600 FEET0.00874 BBL/FEET880 FEET0.00492 BBL/FEET14.0 PPG0.03221 BBL/FEET0.04470 BBL/FEET0.04891 BBL/FEET16.9 PPG530 PSI700 PSI0.1019 BBL/STRK650 PSI10.0 BBL
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124
DRILLERS METHOD1st CIRCULATION
0
O C
Ph= 8398 psi
Pf= 8928 psi
530 700
1489MAASP
7189
0
7889
SHUTTINGSHUTTINGININ
WELLWELL
DP CSG
![Page 125: Well Control Principles](https://reader038.vdocument.in/reader038/viewer/2022102419/56814bed550346895db8cfac/html5/thumbnails/125.jpg)
125
DRILLERS METHOD1st CIRCULATION
O C
Pf= 8928 psi
1489MAASP
7889
700
30
22
1180REACHINGREACHING
ICPICP
KEEP CONSTANTCASING PRESSURE
WHILE BRINGINGPUMPS UP
PUMPS UP ANDPRESSURE STABILISED
KEEP CONSTANTDRILL PIPE PRESSURE
DP CSG
BHP= 8928 PSI
![Page 126: Well Control Principles](https://reader038.vdocument.in/reader038/viewer/2022102419/56814bed550346895db8cfac/html5/thumbnails/126.jpg)
126
DRILLERS METHOD1st CIRCULATION
O C
30
1180
Pf= 8928 psi
1489310
740
MAASP
7929
DP CSG
GAS IN OPEN HOLEGAS IN OPEN HOLE
CONSTANTDRILL PIPE PRESSURE
GAS EXPANDING
CASING PRESSUREINCREASE
SHOE PRESSUREINCREASE
MAASP CONSTANTBHP= 8928 PSI
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127
DRILLERS METHOD1st CIRCULATION
O C
1180
30
MAASP
1489470
Pf= 8928 psi
BHP= 8928 PSI
775
7964
GAS REACH SHOEGAS REACH SHOE
CONSTANTDRILL PIPE PRESSURE
GAS EXPANDING
CASING PRESSUREINCREASE
SHOE PRESSUREINCREASE TO MAX
MAASP CONSTANT
DP CSG
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128
DRILLERS METHOD1st CIRCULATION
O C
1180
30
BHP= 8928 PSI
Pf= 8928 psi
MAASP620
785
7718
1685GAS MOVES INSIDEGAS MOVES INSIDECASINGCASING
CONSTANTDRILL PIPE PRESSURE
GAS EXPANDING
CASING PRESSUREINCREASE
SHOE PRESSUREDECREASE
MAASP INCREASING
DP CSG
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129
DRILLERS METHOD1st CIRCULATION
O C
1180
30
2300
Pf= 8928 psi
BHP= 8928 PSI
1120
7718
2020MAASP
GAS MOVING INSIDEGAS MOVING INSIDECASINGCASING
CONSTANTDRILL PIPE PRESSURE
GAS EXPANDING
CASING PRESSUREINCREASE
SHOE PRESSURECONSTANT
MAASP INCREASING
DP CSG
![Page 130: Well Control Principles](https://reader038.vdocument.in/reader038/viewer/2022102419/56814bed550346895db8cfac/html5/thumbnails/130.jpg)
130
DRILLERS METHOD1st CIRCULATION
O C
1180
30
4800
BHP= 8928 PSI
Pf= 8928 psi
MAASP
1580
7718
2480GAS REACH CHOKEGAS REACH CHOKE
CONSTANTDRILL PIPE PRESSURE
GAS EXPANDING
CASING PRESSUREINCREASE TO MAX
SHOE PRESSURECONSTANT
MAASPINCREASE TO MAX
DP CSG
![Page 131: Well Control Principles](https://reader038.vdocument.in/reader038/viewer/2022102419/56814bed550346895db8cfac/html5/thumbnails/131.jpg)
131
DRILLERS METHOD1st CIRCULATION
O C
1180
30
5400
BHP= 8928 PSI
Pf= 8928 psi
530
7718
1489GAS OUT OF WELLGAS OUT OF WELL
CONSTANTDRILL PIPE PRESSURE
CASING PRESSUREDECREASING TO SIDPP
SHOE PRESSURECONSTANT
MAASP DECREASINGTO ORIGINAL VALUE
MAASP
DP CSG
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132
DRILLERS METHOD2nd CIRCULATION
O C
30
1180
5400
530
1489
7718
BHP= 8928 PSI
Pf= 8928 psi
START PUMPINGSTART PUMPINGKILL MUD 14.9 PPGKILL MUD 14.9 PPG
CASING PRESSURECONSTANT
SHOE PRESSURECONSTANT
MAASP CONSTANT
MAASP
DP CSG
![Page 133: Well Control Principles](https://reader038.vdocument.in/reader038/viewer/2022102419/56814bed550346895db8cfac/html5/thumbnails/133.jpg)
133
DRILLERS METHOD2nd CIRCULATION
O C
530
1489
7718
BHP= 8928 PSI
Pf= 8928 psi
30
6306
936
KILL FLUID INSIDEKILL FLUID INSIDEDRILL PIPEDRILL PIPE
CASING PRESSURECONSTANT
DRILL PIPE PRESSUREDECREASING
SHOE PRESSURECONSTANT
MAASP CONSTANT
MAASP
DP CSG
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134
DRILLERS METHOD2nd CIRCULATION
O C
BHP= 8928 PSI
Pf= 8928 psi
1489
7718
530
30
7212
692
KILL MUD REACHKILL MUD REACHBITBIT
CONSTANT CASINGPRESSURE
DRILL PIPE PRESSUREDECREASING TO FCP
SHOE PRESSURECONSTANT
MAASP CONSTANT
MAASP
DP CSG
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135
DRILLERS METHOD2nd CIRCULATION
O C
BHP= 8928 PSI
Pf= 8928 psi
692
30
78321489
469
7657
MAASPKILL MUD REACHKILL MUD REACH
SHOESHOE
DRILL PIPE PRESSURECONSTANT
CASING PRESSUREDECREASING
SHOE PRESSUREDECREASING
MAASP CONSTANT
DP CSG
![Page 136: Well Control Principles](https://reader038.vdocument.in/reader038/viewer/2022102419/56814bed550346895db8cfac/html5/thumbnails/136.jpg)
136
DRILLERS METHOD2nd CIRCULATION
O C
MAASP
DP CSG
692
30
10202
BHP= 8928 PSI
Pf= 8928 psi
KILL MUD INSIDEKILL MUD INSIDECASINGCASING
DRILL PIPE PRESSURECONSTANT
CASING PRESSUREDECREASING
SHOE PRESSURECONSTANT
MAASP DECREASING
233
7657
1253
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137
DRILLERS METHOD2nd CIRCULATION
O C
MAASP
DP CSG
692
30
12600
BHP= 8928 PSI
Pf= 8928 psi
0
7657
1020KILL MUD ATKILL MUD ATSURFACESURFACE
DRILL PIPE PRESSURECONSTANT
CASING PRESSUREDECREASING TO ZERO
SHOE PRESSURECONSTANT
MAASP DECREASINGTO NEW MAASP w/KMW
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138
WELL # 1
HOLE SIZEHOLE DEPTH TVD/MDCASING 9-5/8” TVD/MDDRILL PIPE CAP.HEAVY WALL DRILL PIPECAPACITYDRILL COLLARS 6-1/4”CAPACITYDRILLING FLUID DENSITYCAPACITY OPEN HOLE/COLLARSCAPACITY OPEN HOLE/DRILL PIPE-HWDPCAPACITY CASING/DRILL PIPEFRACTURE FLUID DENSITYSIDPPSICPPUMP DISPLACEMENTRRCP 30 SPMPIT GAIN
8-1/2 INCH11536 FEET9875 FEET0.01741 BBL/FEET600 FEET0.00874 BBL/FEET880 FEET0.00492 BBL/FEET14.0 PPG0.03221 BBL/FEET0.04470 BBL/FEET0.04891 BBL/FEET16.9 PPG530 PSI700 PSI0.1019 BBL/STRK650 PSI10.0 BBL
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139
WAIT & WEIGHT METHOD
0
O C
Ph= 8398 psi
Pf= 8928 psi
530 700
1489MAASP
7189
0
7889
SHUTTINGSHUTTINGININ
WELLWELL
MIXING KILL MUD14.9 PPG
DP CSG
![Page 140: Well Control Principles](https://reader038.vdocument.in/reader038/viewer/2022102419/56814bed550346895db8cfac/html5/thumbnails/140.jpg)
140
O C
Pf= 8928 psi
1489MAASP
7889
700
30
22
1180
REACHINGREACHINGICPICP
KEEP CONSTANTCASING PRESSURE
WHILE BRINGINGPUMPS UP
PUMPS UP ANDPRESSURE STABILISED
KEEP DRILL PIPEPRESSURE ON
SCHEDULE
DP CSG
BHP= 8928 PSI
WAIT & WEIGHT METHOD
![Page 141: Well Control Principles](https://reader038.vdocument.in/reader038/viewer/2022102419/56814bed550346895db8cfac/html5/thumbnails/141.jpg)
141
O C
MAASP
DP CSG
WAIT & WEIGHT METHOD
BHP= 8928 PSI
Pf= 8928 psi
30
310
1097 740
7929
1489GAS IN OPEN HOLEGAS IN OPEN HOLE
DRILL PIPE PRESSUREDECREASING
CASING PRESSUREINCREASING
GAS EXPANDING
SHOE PRESSUREINCREASING
MAASP CONSTANT
![Page 142: Well Control Principles](https://reader038.vdocument.in/reader038/viewer/2022102419/56814bed550346895db8cfac/html5/thumbnails/142.jpg)
142
O C
MAASP
DP CSG
WAIT & WEIGHT METHOD
30
BHP= 8928 PSI
Pf= 8928 psi
470
1053 775
7964
1489GAS REACH SHOEGAS REACH SHOE
DRILL PIPE PRESSUREDECREASING
CASING PRESSUREINCREASING
GAS EXPANDING
SHOE PRESSUREINCREASE TO MAX
MAASP CONSTANT
![Page 143: Well Control Principles](https://reader038.vdocument.in/reader038/viewer/2022102419/56814bed550346895db8cfac/html5/thumbnails/143.jpg)
143
O C
MAASP
DP CSG
WAIT & WEIGHT METHOD
30
BHP= 8928 PSI
Pf= 8928 psi
620
1013 785
7718
1685GAS MOVES INSIDEGAS MOVES INSIDECASINGCASING
DRILL PIPE PRESSUREDECREASING
CASING PRESSUREINCREASING
GAS EXPANDING
SHOE PRESSUREDECREASING
MAASP INCREASING
![Page 144: Well Control Principles](https://reader038.vdocument.in/reader038/viewer/2022102419/56814bed550346895db8cfac/html5/thumbnails/144.jpg)
144
O C
MAASP
DP CSG
WAIT & WEIGHT METHOD
30
BHP= 8928 PSI
Pf= 8928 psi
1812
692 1050
7718
1950KILL MUD AT BITKILL MUD AT BITGAS INSIDE CASINGGAS INSIDE CASING
DRILL PIPE PRESSUREDECREASE TO FCP
CASING PRESSUREINCREASING
GAS EXPANDING
SHOE PRESSURECONSTANT
MAASP INCREASING
![Page 145: Well Control Principles](https://reader038.vdocument.in/reader038/viewer/2022102419/56814bed550346895db8cfac/html5/thumbnails/145.jpg)
145
O C
MAASP
DP CSG
WAIT & WEIGHT METHOD
BHP= 8928 PSI
Pf= 8928 psi
30
2432
692 1080
7641
1980KILL MUD AT SHOEKILL MUD AT SHOEGAS INSIDE CASINGGAS INSIDE CASING
DRILL PIPE PRESSURECONSTANT
CASING PRESSUREINCREASING
GAS EXPANDING
SHOE PRESSUREDECREASING
MAASP INCREASING
![Page 146: Well Control Principles](https://reader038.vdocument.in/reader038/viewer/2022102419/56814bed550346895db8cfac/html5/thumbnails/146.jpg)
146
O C
MAASP
DP CSG
WAIT & WEIGHT METHOD
30
4800
BHP= 8928 PSI
Pf= 8928 psi
692 1278
7641
2178KILL MUD INSIDEKILL MUD INSIDECASINGCASING
GAS REACH CHOKEGAS REACH CHOKE
DRILL PIPE PRESSURECONSTANT
CASING PRESSUREINCREASING
GAS EXPANDING
SHOE PRESSURECONSTANT
MAASP INCREASING
![Page 147: Well Control Principles](https://reader038.vdocument.in/reader038/viewer/2022102419/56814bed550346895db8cfac/html5/thumbnails/147.jpg)
147
O C
MAASP
DP CSG
WAIT & WEIGHT METHOD
BHP= 8928 PSI
Pf= 8928 psi
30
5360
692 180
7641
1204KILL MUD INSIDEKILL MUD INSIDECASINGCASING
GAS OUT OF WELLGAS OUT OF WELL
DRILL PIPE PRESSURECONSTANT
CASING PRESSUREDECREASING
SHOE PRESSURECONSTANT
MAASP DECREASING
![Page 148: Well Control Principles](https://reader038.vdocument.in/reader038/viewer/2022102419/56814bed550346895db8cfac/html5/thumbnails/148.jpg)
148
O C
MAASP
DP CSG
WAIT & WEIGHT METHOD
30
7200
BHP= 8928 PSI
Pf= 8928 psi
692 0
7641
1027KILL MUD ATKILL MUD ATSURFACESURFACE
DRILL PIPE PRESSURECONSTANT
CASING PRESSUREDECREASING TO ZERO
SHOE PRESSURECONSTANT
MAASP DECREASINGTO NEW MMASP w/KMW
![Page 149: Well Control Principles](https://reader038.vdocument.in/reader038/viewer/2022102419/56814bed550346895db8cfac/html5/thumbnails/149.jpg)
149
WELL # 1
HOLE SIZEHOLE DEPTH TVD/MDCASING 9-5/8” TVD/MDDRILL PIPE CAP.HEAVY WALL DRILL PIPECAPACITYDRILL COLLARS 6-1/4”CAPACITYDRILLING FLUID DENSITYCAPACITY OPEN HOLE/COLLARSCAPACITY OPEN HOLE/DRILL PIPE-HWDPCAPACITY CASING/DRILL PIPEFRACTURE FLUID DENSITYSIDPPSICPPUMP DISPLACEMENTRRCP 30 SPMPIT GAIN
8-1/2 INCH11536 FEET9875 FEET0.01741 BBL/FEET600 FEET0.00874 BBL/FEET880 FEET0.00492 BBL/FEET14.0 PPG0.03221 BBL/FEET0.04470 BBL/FEET0.04891 BBL/FEET16.9 PPG530 PSI700 PSI0.1019 BBL/STRK650 PSI10.0 BBL
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150
VOLUMETRIC METHODVOLUMETRIC METHOD
MIGRATION DISTANCEMIGRATION DISTANCE
GMD = -------------------------GMD = -------------------------
MIGRATION DISTANCEMIGRATION DISTANCE
GMD = -------------------------GMD = -------------------------P2 - P1
MUD GRADIENT
MIGRATION RATE/HRSMIGRATION RATE/HRS
GMR = -------------------------GMR = -------------------------
MIGRATION RATE/HRSMIGRATION RATE/HRS
GMR = -------------------------GMR = -------------------------GMD x 60
T2 - T1
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151
VOLUMETRIC METHODVOLUMETRIC METHOD
KEY POINT:
EVERY BARREL OF MUD IN THE WELLBORE REPRESENT A CERTAIN AMOUNT OF HYDROSTATIC PRESSURE
Ph Ph
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152
VOLUMETRIC METHODVOLUMETRIC METHOD
CHOKE PRESSURECHOKE PRESSURE
SICP + SAFETY FACTOR + WORKING RANGESICP + SAFETY FACTOR + WORKING RANGE
PRESSURE/BARRELPRESSURE/BARREL
PSI/BBL = ----------------------------PSI/BBL = ----------------------------
14.88 = ----------------------------14.88 = ----------------------------
MUD GRADIENT
CAPACITY
14 x 0.052
0.04891
WORKING RANGEWORKING RANGE50 PSI50 PSI
VOLUME TO BLEED =--------------------VOLUME TO BLEED =--------------------
3.36 BBL =-----------------------------3.36 BBL =-----------------------------
W.R.
PSI/BBL
50
14.88
![Page 153: Well Control Principles](https://reader038.vdocument.in/reader038/viewer/2022102419/56814bed550346895db8cfac/html5/thumbnails/153.jpg)
153
PA
10000 ft
12.5 ppg
300 psi
6500 psi
GAS
GMD = --------------------------
GMR = --------------------------
Where: GMD = Gas migration distanceMWG = Mud gradientP1 = Surface pressure at time T1
P2 = Surface pressure at time T2 GMR = Gas migration rate ( feet per hour)T1 = Time 1 (hour)T2 = Time 2 (hour)
P2 - P1
MWG
GMD
T2 - T1
VOLUMETRIC METHODVOLUMETRIC METHOD
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154
PA
10000 ft
12.5 ppg
300 psi
6500 psi
GAS
GMD = --------------------------
GMR = --------------------------
Where: GMD = Gas migration distanceMWG = Mud gradientP1 = Surface pressure at time T1
P2 = Surface pressure at time T2 GMR = Gas migration rate ( feet per hour)T1 = Time 1 (hour)T2 = Time 2 (hour)
P2 - P1
MWG
GMD
T2 - T1
VOLUMETRIC METHODVOLUMETRIC METHOD
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155
HALLIBURTON
BOP
PA
KILL LINE
GAS
PUMP
1
2
3
4
5
VOLUMETRIC METHODVOLUMETRIC METHOD
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156
HALLIBURTON
BOP
PA
KILL LINE
GAS
SICP
P1
P1
P3
P3
P3
P3
P3
Vm
Vm
Vm
Vm
BLEED OFF LUBRICATE
GAS
GAS
GAS
GAS
GAS
1
2
3
4
5
6
1
2
3 4
5
6
BHP
Pa
VOLUMETRIC METHODVOLUMETRIC METHOD
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157
VOLUMETRIC METHODVOLUMETRIC METHOD
BLEED OFF LUBRICATE
Gas bubble pressure
Bottom hole pressure
Annular pressure
Drill pipe pressure
TIME
PRESSURE
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158
Bull heading
• Involves forcing formation fluids back into the formation using surface hydraulics
• Usually considered if: 1 Formation fluid cannot be safely handled on surface (eg with H2S)
2 If anticipated formation pressures exceed what can be safely handled
• Method usually employed as a last resort
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159
Tertiary well control Methods
• Cement Plug
• Barite plug
• Gunk plug
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160
Evaluation & Planning
•Drill a pilot hole
• Heavy mud in ready(1-2 ppg higher)
•Controlled ROP
•Use of Viscous pills instead of weighted pills
•High circulation rates
•Float in string
Shallow Gas
![Page 161: Well Control Principles](https://reader038.vdocument.in/reader038/viewer/2022102419/56814bed550346895db8cfac/html5/thumbnails/161.jpg)
161
Diverting Shallow Gas
• Open vent line
• Close Diverter
• Switch suctions to heavy mud
• Increase pump speed to maximum
• Circulate heavy mud round
• Flow check• If still positive continue pumping.( if mud finished
continue with water)
INTERLOCKED
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162
Well Control
Complications
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Well Control Complications
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WELL CONTROL COMPLICATIONS
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Lost Circulation
• Formation breakdown
• Fractures and Fissures
• Bad cement
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166
Loss Circulation
Categories:• Seepage losses (<2bbl/Hr)
• Partial losses (5-50 bbl/Hr)
• Severe losses (>50bbl/Hr)
• Complete losses (unable to maintain fluid level at surface with desired mud weight)
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Hydrates
Hydrates
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What are hydrates?
• Hydrates are a solid mixture of water and natural gas (commonly methane).
• Once formed, hydrates are similar to dirty ice .
Hydrates
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169
Why are they important?
• Hydrates can cause severe problems by forming a plug in Well Control equipment, and may completely blocking flow path.
• One cubic foot of hydrate can contain as much as 170 cubic feet of gas.
• Hydrates could also form on the outside of the BOP stack in deepwater.
Hydrates
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Where do they form?
• In deepwater Drilling
• High Wellhead Pressure
• Low Wellhead temperature
Hydrates
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How to prevent hydrates?
• Good primary well control = no gas in well bore
• Composition of Drilling Fluid by using OBM or Chloride (Salt) in WBM.
• Well bore temperature as high as possible
• Select proper Mud Weight to minimize wellhead pressure.
• injecting methanol or glycol at a rate of 0.5 - 1 gal per minutes on the upstream side of a choke
Hydrates
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Hydrates
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Wet And Dry Tripping
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When a length of pipe is pulled from the hole, the
mud level will fall.
Tripping Dry
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The volume of fall is equal to the volume of steel pulled from the hole.
The trip tank is then used to fill up the hole.
If 1 barrel of steel is removed from the hole,
then using the trip tank, we have to add 1 barrel of
mud.
Tripping Dry
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1- Calculate the volume of steel pulled:
Length x Metal Displacement
Example:
DP Metal Disp = 0.00764 bbls/ft
Length Pulled 93 feet
Volume Of Steel Pulled:
93 x 0.00764 = 0.711 bbls
Tripping Dry
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2- Fill up the hole:
You must pump 0.711 barrel of mud from the trip tank.
You must investigate ( flow check) if more mud or less mud
is needed.
Tripping Dry
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3- NO FILL UP:
If you fail to fill up the hole, the mud level will drop by the
volume of steel pulled.
It will drop inside the pipe and in the annulus.
Tripping Dry
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3- NO FILL UP:
Example:
Volume Of Steel Pulled:
93 x 0.00764 = 0.711 bbls
DP Capacity: 0.01776 bbl/ft
Annular Capacity: 0.0504 bbl/ft
The mud will drop inside the pipe and the annular:
0.01776 + 0.0504 = 0.06816 bbl/ft
Tripping Dry
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3- NO FILL UP:
Example Cont’d:
The volume of drop is 0.711 bbls and will drop in a volume of
0.06816 bbl / ft,
then the length of drop will be:
0.711 / 0.06816 = 10.4 feet.
If 93 feet (1 stand) are pulled with no fill up, the mud level will drop by 10.4 feet.
Tripping Dry
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When a length of pipe is pulled from the hole, the
mud level will fall.
Tripping Wet
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The volume of fall is equal to the volume of steel
pulled from the hole plus the volume of mud inside
this pipe.
The trip tank is then used to fill up the hole.
If 3 barrels of steel and mud are removed from the
hole, then using the trip tank, we have to add 3
barrels of mud.
Tripping Wet
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1- Calculate the volume of steel pulled:
Length x Metal Displacement
Example:
DP Metal Disp = 0.00764 bbls/ft
Length Pulled 93 feet
Volume Of Steel Pulled:
93 x 0.00764 = 0.711 bbls
Tripping Wet
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2- Calculate the volume of mud pulled:
Length x DP Capacity
Example:
DP Capacity = 0.01776 bbls/ft
Length Pulled 93 feet
Volume Of Mud Pulled:
93 x 0.01776 = 1.65 bbls
Tripping Wet
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3- Calculate the total volume of steel and mud pulled:
1.65 + 0.711 = 2.36 barrels
Tripping Wet
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4- Fill up the hole:
You must pump 2.36 barrels of mud from the trip tank.
You must investigate ( flow check) if more mud or less mud
is needed.
Tripping Wet
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5- NO FILL UP:
If you fail to fill up the hole, the mud level will drop by the
volume of steel and mud pulled.
It will drop inside the annulus.
Tripping Wet
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5- NO FILL UP:
Example:
Volume Of Steel and Mud Pulled:
93 x (0.00764+0.01776) = 2.36 bbls
Annular Capacity: 0.0504 bbl/ft
The mud will drop inside the annular by:
2.36 / 0.0504 = 46.9 feet
Tripping Wet
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It is usefull to pump a slug before tripping.
The slug weight being heavier than the mud, a length of pipe will be empty.
Pumping a Slug
The HP is not reduced because the heavier mud will compensate for the empty pipe.
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The total HP is the same on both sides of the pipe.
Pumping a Slug
HP mudHP kmw
HP mud
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Example:
If 20 bbls of 12 ppg slug are pumped in a 10,000 ft hole containing 10 ppg mud, what will be the height of empty pipe?
DP capacity = 0.01776 bbl/ft
Pumping a Slug
1- Calculate the height of the slug:
20 / 0.01776 = 1126 ft
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Pumping a Slug2- Calculate the HP of the slug:
1126 x 12 x 0.052 = 702.6 psi
702.6 psi
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Pumping a Slug2- Calculate the HP of the mud in the annulus:
10,000 x 10 x 0.052 = 5,200 psi
702.6 psi 5,200 psi
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Pumping a Slug3- The total hydrostatic beeing the same on both sides, calculate the HP of the mud below the slug:
5,200 - 702.6 = 4497.4 psi
702.6 psi 5,200 psi
4497.4 psi
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Pumping a Slug4- Calculate the height of mud needed to give 4497.4 psi as a HP:
TVD = 4497.4 / ( 10 x 0.052 ) = 8648.8 feet
1,126 ft 10,000 ft
8648.8 ft
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Pumping a Slug4- Calculate the height of empty pipe
10,000 - 8648.8 - 1,126 = 225.2 ft
1,126 ft 10,000 ft
8648.8 ft
225.2 ft