on january 10, 1901, the lucas gusher blew in at spindletop, near beaumont, texas. the hamill...
TRANSCRIPT
• ON JANUARY 10, 1901, THE LUCAS GUSHER BLEW IN AT SPINDLETOP, NEAR BEAUMONT, TEXAS.
The Hamill Brothers Had Started The Hole 3 Months Earlier For Captain A. F. Lucas, And 6-inch Casing Had Been Set At 880 Feet After Minor Indications Of oil In The Next 7 Days, The Well Had Been Deepened By 140 Feet To , 1020 Feet, A Much Faster Rate Than Before. Running In A New Bit, The Crew Had 700 Feet Of 4-inch Drill Pipe In The Hole When The Well Started To Unload; That Is, Mud Started Flowing From The Casing. After Several Hard Kicks, Well Pressure Blew The Drill Pipe Out Of The Hole. Soon A Stream Of Oil And Gas Was Spraying More Than 100 Feet In To The Air, Producing By Some Estimates 75,000 To 100,000 Barrels Of Oil Per Day.Most Of The Signs Of A Developing Blowout Were Observable On The Lucas Well:
Shows Of Oil And Gas In The MudDrilling Break (Faster Drilling)Flow Of Mud From The WellPit Gain
Hydrostatic pressurehydrostatic pressure is defined as the
pressure exerted by a fluid column. The magnitude of the pressure depends only on the density of the fluid and the vertical height of the column. The size and shape of the fluid column do not affect the magnitude of this pressure
pressure = fluid density x vertical height of the fluid column
HP = C x MW x TVDwhere:HP = Hydrostatic Pressure (Ph)(psi or Pounds Per Square
Inch)MW = Fluid Density, or Mud Weight (1bs/gal or ppg or
Pounds Per Gallon)TVD = True Vertical Depth of the Fluid Column (Feet or
Ft)C = 0.052: Conversion factor used to convert density to
pressure gradient (psi /ft Per 1bs/gal) is derived as follow:
A cubic foot contains 7.48 US gallonsA fluid weighing 1 ppg is therefore equivalent to 7.48 lbs /cu.ftThe pressure exerted by one foot of the fluid over the base
would be :7.48 lbs / 144 sq.ins = 0.052 psi
Example: Calculating hydrostatic pressurethe hydrostatic pressure exerted by a 10-foot column of fluid
with a density of 10 ppg is:hydrostatic pressure = 0.052 x density (10 ppg) x height (10 ft)
= 5.2 psi
12”
12”
12”
PRESSURE GRADIENT Pressure gradient is defined as the pressure increment per foot of depth . Water, for example , will increase the hydrostatic pressure by 0.433 psi for every foot - of hole. PG = C x MW PG = Pressure Gradient psi / ft
MW = Fluid Density lbs/gal
C = 0.052 conversion constant psi /ft / lbs/gal
OVER BURDEN PRESSUREOverburden Pressure is the Result Of The Combined Weight
Of The Formation Matrix (Rock) And The Fluids (Water, Oil, And Gas) in the Pore Spaces Overlying The Formation Of Interest. The Average Value Of Overburden Pressure Gradient (OPG) is Often Assumed To be1.0 psi/ft .Actually, it me be as high as 1.35 psi/ft in some areas , and lower than 1.0 psi/ft in others.
PORE PRESSURE
The magnitude of the pressure in the pores of a formation , known as the formation pore pressure (or simply formation pressure ),
Formation Pressures Vary Greatly, And Depend Upon Reservoir Characteristics. They Can Be Divided In To Three Categories:
Normal Formation PressureSubnormal Formation PressureAbnormal Formation Pressure
NORMAL FORMATION PRESSURENormal Formation Pressure Is Equal To The Hydrostatic Pressure
Of Water Extending From The Surface To The Subsurface Formation Of Interest.this is because sedmentary beds were originally deposited in a water environment. Thus the normal pressure gradient in any area will be equal to the hydrostatic pressure gradiant of the water that occupies the pore space of the formations in that area.
HENCE, 0.433 PSI/FT < NORMAL FORMATION PRESSURE GRADIENT <
0.465 PSI / ft
ABNORMAL FORMATION PRESSUREABNORMAL FORMATION PRESSURE IS ANY FORMATION
PRESSURE GREATER THAN THE CORRESPONDING NORMAL FORMATION PRESSURE.
Formation pressure gradient > 0.052 x 8.90 psi / ft > 0.465 psi / ft
Causes of abnormally high formation pressure are:
Depositional causesDiagenesisPiezometric surfaceTectonic causesStructural causes
DEPOSITIONAL CAUSES.INSUFFICIENT COMPACTION - as sediments are
deposited, the pore pressure is normal as pore fluid is in contact with the overlaying seawater. as sedimentation continues, older sediments compact (due to increase in overburden pressure) and fluids are expelled from the older sediments. as long as equilibrium exists between rate of compaction and rate of fluid expulsion from sediments, and the expelled water can escape to surface or in other porous formation, pore pressure remains normal (hydrostatic). in some cases, rate of compaction is more than the rate of pore fluid expulsion.
DIAGENESISdiagenesis is the process whereby the
chemical nature of the sediment is altered due to increasing pressure and temperature as the sediment is buried deeper.
gypsum converts to anhydrite plus free water. the volume of water released is approximately 40 % of the volume of gypsum. if the water cannot escape then overpressures will be generated.
PIEZOMETRIC SURFACE• A PIZOMETIC SURFACE IS AN IMAGINARY LEVEL TO WHICH THE
GROUND WATER WILL RISE IN A WELL. THE WATER TABLE IN AN AREA IS AN EXAMPLE OF A PIEZOMETRIC SURFACE. IF THE SURFACE ELEVATION IS HIGHER THAN PIEZOMETRIC SURFACE LEVEL, SUBNORMAL PORE PRESSURES ARE MOST OFTEN ENCOUNTERED (SEE FIGURE BELOW).
Structural causesAny structure such as an anticline or dome may
have abnormally high pressures above the oil- water or gas –water contact in the oil or gas zone because hydrocarbons are less dense than water. If the anticline or dome is large ,abnormal pressures may be quite high
TECTONIC CAUSES
TECTONIC FORCES MAY CAUSE ABNORMAL PRESSURES DUE TO
FOLDING AND FAULTING DUE TO SALT DIAPIRISM. DIAPIRISM IS THE UPWARD MOVEMENT OF LOW DENSITY PLASTIC FORMATIONS (SEE FIGURE BELOW).
Subnormal formation pressureSubnormal Formation Pressure Is Any Formation Pressure Less
Than the Corresponding Normal Pressure.
Formation PressureGradient < 0.052 X 8.33 ppg < 0.433 Psi / ft
Causes of subnormal formation pressure are:
Depleted ReservoirsPiezometric SurfaceTectonic Compression
DEPLETED RESERVOIRSProducing Large Volumes Of Reservoir
Fluids Causes A Decline In Pore Pressure As The Fluids In The Reservoir Expand To Fill The Void Spaces Created Because Of Production.
ExampleThe original reservoir formation pressure in
oil field “A” was 3250 psi at a depth of 7000 ft vertical depth. This equates to a formation pressure gradient of 0.465 psi , which is the normal hydrostatic gradient . After producing many years from the field , the reservoir formation pressure dropped to approximately 2525 psi .this gives a subnormal pressure gradient of 0.36 psi/ft .
PIEZOMETRIC SURFACE• A PIZOMETIC SURFACE IS AN IMAGINARY LEVEL TO WHICH THE
GROUND WATER WILL RISE IN A WELL. THE WATER TABLE IN AN AREA IS AN EXAMPLE OF A PIEZOMETRIC SURFACE. IF THE SURFACE ELEVATION IS HIGHER THAN PIEZOMETRIC SURFACE LEVEL, SUBNORMAL PORE PRESSURES ARE MOST OFTEN ENCOUNTERED (SEE FIGURE BELOW).
TECTONIC COMPRESSIONDuring A Lateral Compression Process Acting On
Sedimentary Beds, Up warping Of Upper Beds And Down warping Of Lower Beds May Occur. The Intermediate Beds Must Expand To Fill The Voids Left By This Process Causing Subnormal Pressures, Due To The Increase In Pore Volume (See Figure Below).
FRACTURE PRESSURE
Fracture Pressure is the amount of pressure it takes to permanently deform ( fail or split ) the rock structure of a formation . Overcoming formation pressure is usually not sufficient to cause fracturing .
AGHA JARI 0.433 0.450 0.680 MISHAN 0.465 0.479 0.700 GACH.M 7 0.465 0.500 0.780 GACH.M 6-1 0.8 – 1.0 0.85 – 1.10 1.10 ASMARI 0.24-0.49 0.43 – 0.56 0.74 PABDEH & GURPI
0.50-0.54 0.52 –0.56 0.81
ILAM & SV 0.54 0.56 0.74
FORMATIONPORE PRESSURE
MUD PRESSURE
FRACTURE PRESSURE
GRADIENT PSI/ft
leak-off test this test is usually made just after drilling 10 to 30 feet through a casing shoe . It measures the maximum mud weight or surface pressure the formation at the casing shoe will withstand before fluid is forced into it. The well is shut in by closing the blowout preventer. Pressure is increased by pumping slowly into the well. At a certain point pressure will being to drop off , indicating that the exposed formation is taking on significant amounts of mud . The fracture is the total of the surface pumping pressure and the hydrostaic pressure at the casing shoe
Leak-off test
Maximum Allowable Annulus Surface Pressure
this is the maximum pressure that can be tolerated in the annulus , without risking a possible formation rupture at or below the casing shoe . MAASP = Pressure required to fracture the formation mines hydrostatic pressure created by the column of mud in the annulus .
( Formation fracture gradient – MW gradient ) * Depth of CSG
Fracture gradient = 0.8 psi/ft
MW gradient = 0.52 psi/ft
Depth of CSG = 8200 ft
MAASP = ( 0.8 – 0.52 ) * 8200
MAASP = 2290 psi
well bore and the ‘U’ Tube
The U-Tube A U- tube is a combination of two vertical tubes, column A and B , connected at the bottom such that the pressure at the bottom of each tube is the same
A BPA = P B
U Tube in a wellbore
A well bore is similar to a U- tube . The fluid column inside the drill string can be considered column A, and the fluid column inside the drill annulus can be considered column B.
A BPA = P B
pump
choke
home work
What will be the gain in the pits , and how far will the slug fall if the mud weight is 10 ppg ,the pipe’s capacity is 0.0178 bbl/ft ?
The volume of the slug is 30 bbls and weighs 11 ppg .
x
FLOW LINE
Drill string
Annulus
BHP= Hydrostatic pressure of drilling fluid column inside drill string
Fluid column A :
Density 11 ppg
Fluid column B :
Density 11.5 ppg
1500 ft
2500 ft
FLOW LINEFLOW LINE
Drill string
Annulus
BHP= Hydrostatic pressure of drilling fluid column inside drill string
BHP= Hydrostatic pressure of drilling fluid column inside Annulus
Static well bore with External Pressure
In shut in well conditions , the BHP can be calculated using the following equations
BHP = HPd + SIDPP
BHP = HPa + SICP
CHOKE
Drill string
Annulus
BHP= Hydrostatic pressure inside drillstring +SIDPP
BHP= Hydrostatic pressure inside Annulus +SICPFORMATION
ORESSURE
Mud Pump
SIDPP
SICP
Mud Pump
CHOKESICP
SIDPP
FORMATION ORESSURE
CHOKE BHP= Hydrostatic pressure inside drillstring +pump pressure – pressure loss inside drilling and bit
FORMATION ORESSURE
Mud Pump
Pump pressure
Friction pressure loss in the drillstring acting against pump pressure
The well bore in dynamic condition – drill string side
BHP= Hydrostatic pressure inside Annulus +surface casing pressure +pressure loss inside annulus
Mud Pump
CHOKESICPsurface casing pressure
Pump pressre
FORMATION ORESSURE
Friction pressure loss in the annulus acting downwards
The well bore in dynamic condition – annulus side
SICP
H
h
SIDPP + HPdp = SICP + ( MG ×H ) + ( IG ×h )
SIDPP
=
H
h
SIDPP + ( MG × H ) + ( MG × h ) =SICP + ( MG×H ) + ( IG × h ) ( MG × H ) + ( MG × h ) - ( MG×H ) - ( IG × h ) = SICP-SIDPP IG =MG -
GAS = TO 0.15
OIL&GAS = F/ 0.15 to/ 0.4
WATER & SALT WATER ABOVE 0.4
h
SIDPP - SICP
Influx Gradient Evaluation
Kick
A kick is the undesired entry of formation fluids into the well bore
Blowout
A blowout is the uncontrolled flow of gas , oil , or other formation fluids
Sometimes ,formation fluids from a reservoir formation at high pressure can flow into another underground formation that is at a lower pressure and different depth . This kind of uncontrolled flow is an underground blowout and can be very difficult to control.
Kick causes
1. Not keeping the hole full
2. Swabbing
3. Overpressure ( abnormal pressure ) formations
4. Lost circulation
5. Gas/oil/water cut mud
1- Not keeping the hole full during tripping
As the drill string comes out of the well the level of drilling fluid in the annulus drops by a volume equal to the volume of drill string removed. If the fluid level is allowed to drop too far , the hydrostatic pressure on the formation is reduced below formation pressure , which allows formation fluids to enter the well bore.
Note that the majority of all kicks worldwide occur during tripping operation
Casing capacity = 0.0729 bls/ft
Metal displacement = 0.0075 bls/ft
Annular volume 0.0476 bls/ft
Pipe capacity = 0.0178 bls /ft
Mud gradient = 0.572 psi / ft
1 stand = 94 ft
Bottom hole pressure (BHP) will be reduced by pulling wet pipe and NOT filling the hole this allows the mud level to drop therefore reducing the hydrostatic pressure
How many stands would have to be pulled wet to remove a 50 psi overbalance and allow the well to flow ?
2- swabbingSwabbing occur when the drill string is pulled from the well , producing a temporary bottom hole pressure reduction . This can lead to an under balanced condition , allowing formation fluids to enter the well bore below the drill string
Balled-up bottom hole assembly
Pulling pipe too fast
Poor drilling fluid properties
Large OD tools
3- Abnormal pressure reservoir
4- Lost circulation
Causes of lost circulation
High density of drilling fluid
Going into hole too fast (surging)
Pressure due to annular circulation friction
5- cutting of drilling fluid with oil , gas , or water
When the bit penetrates a porous formation the fluids contained in the formation (gas, oil , or water ) escape and mix with the drilling fluid ,
Cutting drilling fluid (contaminating with the low-density formation fluid ) reduce the density of the fluid in the annulus and causes a subsequent loss of hydrostatic pressure.
Kick Indicators
1.Primary kick Indicators
2.Secondary kick Indicators
Primary Kick Indicators
1. Increase in return flow rate
2. Increase in pit volume
3. Insufficient hole fill during tripping
4. Positive flow check
secondary Kick Indicators
1. Drilling break
2. Decrease in circulating pressure with a corresponding increase in circulating rate
3. Increase in gas cutting, oil cutting , or chlorides
Early warning signs( home work)
Increase in background, connection, and trip gas
Increase in the chlorides content of the mud
Changes in the size and shape of cuttings
Unaccounted –for fluid loss while tripping
Increasing fill on bottom after a trip
Increase in flow line temperature
Increase in rotary torque
Increase tight hole on connection
Decrease in D-exponent
Most of these signs are related to the indication of a transition zone prior to drilling into an abnormal pressure formation
0 0
2600
5200
10PPG
10PPG
BALANCED STATIC CONDITION
Figure shows a balanced U-tube situation with fluid of the same density in the annulus and drill pipe sides.
Depth = 10000 ft
Shoe depth = 5000 ft
Mud wt = 10 ppg
2600 0
2730
5460
10PPG
10PPG
STANDARD CIRCULATION SITUATION
Depth = 10000 ft
Shoe depth = 5000 ft
Mud wt = 10 ppg
Circulating pressure 2600 psi
APL = 260 PSI
520 1820
4420
5720 PSI5720
PSI
5PPG
10PPG10PPG
SHUT-IN KICK PRESSURES
3120 1820
4550
5980
10PPG10PPG
5PPG
گل وزن كه حالتي بررسيليز دا
ها لوله درون گل وزن ازكمـــتر
با گل گردش و اسـتزمان سرعت
فشار پس با همراه حفارير برقرا
است .
SIDPP= 520PSI SPL= 2600 PSI APL= 260 PSI FP = 5720 PSI BHP= 5980 PSI
1220 1820
4485
5850
10PPG10PPG
5PPG
گل وزن كه حالتي بررسيليز دا
ها لوله درون گل وزن ازكمـــتر
با گل گردش و استآرام سرعت
برقرا فشار پس با همراهراست .
SIDPP= 520PSI SPL= 700 PSI APL= 130 PSI FP = 5720 PSI BHP= 5850 PSI
SCR Measurements
When a well control situation arises , the pressure inside the wellbore prohibits the use of normal circulation rates used during drilling because :
It might lead to high pressure inside the annulus , causing lost circulation
It might cause higher pressure at surface than the working pressure rating of the surface pump and high pressure lines
It might be difficult to safely control the well and monitor the process at high pumping rate
SCR Measurements (cont.)
therefore in most cases control of the well is gained while circulating at low flow rate , called slow circulation rate (SCR)
A drilling crew determines accurate circulation pressure at specified slow circulation rate every tour or every significant change in drilling fluid density and properties or after drilling every 500 feet , whichever comes first.
GAS MIGRATION
When a well is shut-in on a gas kick because of its low density , gas tends to migrate , or move upward , in a well. If the gas volume remains the same ,the pressure also will remain the same based on the gas compressibility equation, but the casing pressure will increase as the hydrostatic pressure decreases due to the upward movement of the gas. If the gas is allowed to expand , the pressure in the gas kick will decrease. Gas expansion is controlling the backpressure with a choke while circulating
MUD GRAD = 0.5 PSI / FT
SHOE DEPTH = 6000 FT
HYD PRESS @ SHOE = 3000 PSI
TVD = 10000 FT
BHP = 5000 PSI
5000 PSI
EXAMPLE
3000 PSISHOE
W/H PRESS = 5200 – (10000 * 0.5 ) = 200
HYD PRESS @ SHOE = 3200 PS
5200 PSI
200 PSISTAGE ONE
200 + 3000 = 3200 PSI SHOE5200-(4000* 0.5) = 3200
200 + (6000 * 0.5 ) = 3200
BHP = GAS PRESS = 5200 PSI
W/H PRESS = 2200 PSI
HYD PRESS @ SHOE = 5200 PSI
BHP = 7200 PSI
2000 + 5200 = 7200 PSI
2200 PSISTAGE TWO
5200 PSI SHOE
W/H PRESS = GAS PRESS = 5200
HYD PRESS @ SHOE = 8200 PSI
BHP = 10200 PSI
5200 + 5000 = 10200 PSI
5200 PSISTAGE THREE
5200 + 3000 = 8200 PSISHOE
STAGE ONE
SHOE
HGAS = 200 FTHMUD= 8300 FTSHOE @ 4000 FTGG = 0.1 PSI / FT MG = 0.5 PSI / FT 2330FP = 4500 PSI PSI
P@SHOE=4500-((200*0.1)+(4300*0.5))
SICP = 4500-((200*0.1)+(8300*0.5))
4500 PSI
330 PSI
STAGE TWO
SHOE
HGAS = 400 FTHMUD= 8100 FTSHOE @ 4000 FTGG = 0.1 PSI / FT MG = 0.5 PSI / FT 2410FP = 4500 PSI PSI
P@SHOE=4500-((400*0.1)+(4100*0.5))
SICP = 4500-((400*0.1)+(8100*0.5))
4500 PSI
410 PSI
STAGE THREE
SHOE
HGAS = 600 FTHMUD= 7900FTSHOE @ 4000 FTGG = 0.1 PSI / FT MG = 0.5 PSI / FT 2490FP = 4500 PSI PSI
P@SHOE=4500-((600*0.1)+(3900*0.5))
SICP = 4500-((600*0.1)+(7900*0.5))
4500 PSI
490 PSI
STAGE FOUR
SHOE
HGAS = 1000 FTHMUD= 7500 FTSHOE @ 4000 FTGG = 0.1 PSI / FT MG = 0.5 PSI / FT 2250FP = 4500 PSI PSI
P@SHOE=4500-(4500*0.5)
SICP = 4500-((1000*0.1)+(7500*0.5))
4500 PSI
650 PSI
shut-in methods
There are two types of shut-in methods in the oil industry
Hard shut-in
Soft shut-in
hard shut-in procedure
In the hard shut-in method, the hydraulic valve on the choke line (HCR VALVE )and the choke itself are kept closed during normal operations. after kick indicators are observed and a kick is confirmed ,following procedure is used
ANNULAR
PIPE RAM
BLIND RAM
PIPE RAM
ChokeClosed
To Mud gas Seperator, Mud
tanks, Flare
Bleed –off line to Flare
To Mud gas Seperator, Mud tanks, Flare
ChokeClosed
Drill string
Kill LineValve Closed
` Valve or BOP Open Valve or BOP Close
Hard Shut –in: initial line up of choke line and choke manifold
Choke line HCR valve closed
ANNULAR
PIPE RAM
BLIND RAM
PIPE RAM
ChokeClose
To Mud gas Seperator, Mud tanks, Flare or
Overboard
Bleed –off line to Flare or Overboard
To Mud gas Seperator, Mud tands, Flare or
Overboard
ChokeClosed
Drill string
Kill LineValve Closed
` Valve or BOP Open Valve or BOP Close
Hard Shut –in: Close Annular BOP
Choke Line HCR Valve closed
Annular BOPClose
ANNULAR
PIPE RAM
BLIND RAM
PIPE RAM
ChokeClose
To Mud gas Seperator, Mud tanks, Flare or
Overboard
Bleed –off line to Flare or Overboard
To Mud gas Seperator, Mud tands, Flare or
Overboard
ChokeClosed
Drill string
Kill LineValve Closed
` Valve or BOP Open Valve or BOP Close
Hard Shut –in: open HCR valve
Choke Line HCR Valve closed
Annular BOPClose
The primary advantage of a hard shut-in is that the kick influx is held to a small volume because the well is closed in more quickly . One disadvantage is that with some hard shut-in procedures , casing pressure cannot be observed ,since the choke-line valves are closed thus MAASP could be exceeded , which could cause formation fracture and lost circulation
soft shut-in procedure
In the soft shut-in method , the HCR valve is closed and the choke is open during normal operations . When primary indicators of kick are experienced , following procedure is used
ANNULAR
PIPE RAM
BLIND RAM
PIPE RAM
Chokeopen
To Mud gas Seperator, Mud tanks, Flare or
Overboard
Bleed –off line to Flare or Overboard
To Mud gas Seperator, Mud tands, Flare or
Overboard
ChokeClose
Drill string
Kill LineValve Closed
` Valve or BOP Open Valve or BOP Close
soft Shut –in: initial line up of choke line and choke manifold
Choke line HCR valve closed
ANNULAR
PIPE RAM
BLIND RAM
PIPE RAM
Chokeopen
To Mud gas Seperator, Mud tanks, Flare or
Overboard
Bleed –off line to Flare or Overboard
To Mud gas Seperator, Mud tands, Flare or
Overboard
ChokeClose
Drill string
Kill LineValve Closed
` Valve or BOP Open Valve or BOP Close
Soft shut-in :open choke line HCR valve
open Choke Line HCR Valve
Annular BOPClose
ANNULAR
PIPE RAM
BLIND RAM
PIPE RAM
Chokeopen
To Mud gas Seperator, Mud tanks, Flare or
Overboard
Bleed –off line to Flare or Overboard
To Mud gas Seperator, Mud tands, Flare or
Overboard
ChokeClosed
Drill string
Kill LineValve Closed
` Valve or BOP Open Valve or BOP Close
soft Shut –in: Close Annular BOP
Choke Line HCR Valve Opened
close Annular BOP
ANNULAR
PIPE RAM
BLIND RAM
PIPE RAM
Closechoke
To Mud gas Seperator, Mud tanks, Flare or
Overboard
Bleed –off line to Flare or Overboard
To Mud gas Seperator, Mud tands, Flare or
Overboard
ChokeClosed
Drill string
Kill LineValve Closed
` Valve or BOP Open Valve or BOP Close
Soft shot-in : Close choke
Choke Line HCR Valve Opened
Annular BOPClose
The primary disadvantage of a soft shut-in is that it requires more steps and time than a hard shut-in . The result can be a large influx of kick fluids .
When a kick is taken while drilling , the following well shut-in procedure should be used:
Stop pipe rotation
Pick the drill string up off-bottom to space out correctly ( ensure that a tool joint is not across a BOP pipe ram )
Stop pumping - shut off the mud pumps .
Check the well for flow and confirm kick .
Shut in the well with the annular BOP , using either a hard or soft shut-in method
Verify that the well is shut in and that there are no leaks in the system .
Read and record SIDPP and SICP
Shut-in procedure while drilling
When a kick is suspected during tripping , the following well shut-in procedure should be used:
Check the well for flow and confirm kick .
Space out the drill string correctly , with a drill pipe tool joint close to the rotary table and no tool joints placed across a BOP pipe ram . Set the drill string in slips in the rotary table
Install a fully opened drill string safety valve
Close the drill string safety valve
Shut in the well with the annular BOP using either a hard or soft shut-in method
Shut-in procedure while tripping
All well kill methods use a common principle :
Maintain a minimum constant bottom hole pressure equal to or greater than the formation pressure while circulating out the formation influx to regain control of the well
Killing a well
Minimum constant bottom hole pressure ≥ formation pore pressure
≥ shut-in drill pipe pressure+
hydrostatic pressure of the
original drilling fluid column in
the drill string
Minimum constant bottom hole pressure ≥ formation pore pressure + safety margin (0-200 psi)
After well shut-in
After a kick has been taken and the well is shut in adequate preparation is required before starting a well kill operation . These preparations include :
preparation a kick sheet
Determining kill fluid density and mixing kill fluid
Performing calculations to obtain the data required for well kill
Preparing a pump pressure schedule
Prepare kick sheet
The general well data , drill string / annulus contents , circulating times , and the mud pump data (SCR ) is recorded routinely and kept available at all times at the rig floor through a kick sheet .
The shut-in drill pipe pressure , shut-in casing pressure , and pit gain is also recorded on the kick sheet after the well has been shut in.
Some additional information is also added to kick sheet , such as kill fluid density , initial circulating pressure final circulating pressure / pump pressure schedule , time to kill the well , etcetera.
Mix kill fluid
The well will be considered killed only when the hydrostatic pressure of the drilling fluid column in the well is higher than the formation pressure and primary control of the well has been regained . The required density of the kill fluid is calculated using following equation :
(a)Calculate kill fluid density
SIDPP
MW k = + MWo
0.052 ×TVD
Mix kill fluid ( b ) calculate the required quantity of weighting material
Normally , barite is used as weighting material to raise the density of the drilling fluid . The required quantity of barite to raise the original drilling fluid density to kill fluid density can be calculated using following equation:
Barite required (lbs) = MWk -MWo
1472× Total active drilling fluid volume (bbl) ×
35 – MWk
MWo = original drilling fluid density , or original Mud Weight (ppg )
MWk = kill fluid density , or kill mud weight (ppg)
example :
Original density = 10 ppg
TVD = 6000 ft
SIDPP = 150
Safety margin = 50 psi
Drill string volume = 150 bbl
Annulus volume = 500 bbl
Active surface volume = 300
Calculate weighting material requirement
Perform calculations for well killing procedure
(a) Initial circulating pressure ( ICP )
ICP = SIDPP + P scr
ICP = initial circulating pressure
SIDPP = shut-in drill pipe pressure
Pscr = pump pressure at kill flow rate ( slow circulation rate)
Perform calculations for well killing procedure (cont.)
(b ) Displacement times and corresponding pump strokes
Calculate displacement times and pump strokes using the volume and the slow circulation rate for well kill operation .normally , the displacement time and corresponding pump strokes are calculated for three milestones, these are:
Kill fluid at the bit
Influx circulated out of the well
Kill fluid returning to surface
(c ) Final circulating pressure (FCP )
FCP is the circulation pressure on the drill pipe pressure gauge when the kill fluid exits the bit. FCP can be calculated using the following equation:
Pscr × MWk
FCP =
MWo
FCP = final circulating pressure
MWk = kill fluid density or Kill Mud Weight (ppg)
Pscr = pump pressure at kill flow rate (slow circulation rate)
MWo = original drilling fluid density , or original Mud Weight(ppg)
Driller’s Method
1. Start pumping
2. Hold casing pressure constant by manipulating the choke.
3. Bring pumps up to kill speed.
4. Adjust pressure to ICP.
5. Casing pressure will increase this due to gas expansion in the well bore
6. Hold ICP constant until influx is out
7. Shut down pumps holding casing pressure constant
8. Check that drill pipe pressure and casing pressure is equal
DP
300CP
500
10000 * 10 * .052 =5200 psi
5200+300 = 5500 psiBHP
Mud weight = 10 ppg
300 500
TVD = 10000
close open
DP
1300CP
500
ICP = 1000+300 =1300 psi
5500 psiBHP
KRP@40spm = 1000 psi
1300 500
TVD = 10000
close open
Casing pressure is held constant as pumps are brought up to speed by opening the choke
If the casing pressure is held constant when starting then BHP is constant
DP
1300CP
520
5500 psiBHP
1300 520
close open
Till the gas influx gets further up the hole there is little expansion and the casing pressure will rise slowly as mud (hydrostatic) is pushed out of the hole.
DP
1300CP
650
5500 psiBHP
1300 650
close open
As the bubble begins to expand it pushes mud out of the hole causing a loss of hydrostatic.
To keep BHP constant, drill pipe pressure must be kept constant.
DP
1300CP
800
5500 psiBHP
1300 800
close open
DP
1300CP
1000
5500 psiBHP
1300 1000
close open
DP
1300CP
1250
5500 psiBHP
1300 1250
close open
DP
1300CP
1400
5500 psiBHP
1300 1400
close open
DP
1300CP
1600
5500 psiBHP
1300 1600
close open
DP
1300CP
1750
5500 psiBHP
1300 1750
close open
DP
1300CP
1000
5500 psiBHP
1300 1000
close open
DP
1300CP
400
5500 psiBHP
1300 400
close open
DP
300CP
300
5500 psiBHP
300 300
close open
Once the influx is circulated out , the well should be shut –in
Compare the drill pipe and casing pressure gauges and confirm that they are equal .if casing pressure is greater than drill pipe pressure then you may not have all the influx out of the well.
Once you are confident that the annulus is clean line up the pumps on kill weight fluid
DP
1300CP
300
5500 psiBHP
1300 300
close open
Hold casing pressure constant as you bring the pumps up to 40 spm .
Continue to hold casing pressure constant as you displace the drillsting .
Drillpipe pressure should drop as hydrostatic in the drillpipe increases.
KRP @40 spm = 1000 psi
ICP= 1000+300 = 1300 psi on DP
DP
1250CP
300
5500 psiBHP
1250 300
close open
DP
1200CP
300
5500 psiBHP
1200 300
close open
DP
1150CP
300
5500 psiBHP
1150 300
close open
DP
1100CP
300
5500 psiBHP
1100 300
close open
DP
1060CP
300
5500 psiBHP
1060 300
close open
Once the drillpipe is full of kill weight fluid the hydrostatic will remain
Continue circulating holding drillpipe pressure constant at FCP .
Casing pressure should drop as kill weight fluid displaces the annulus .
DP
1060CP
250
5500 psiBHP
1060 250
close open
First circulation
Sta
ndpip
e p
ress
ure
Second circulation
Pc1
Pdp Pc2
Time
Pann Pdp
Time
Phase 4
(Fill annulus with heavy mud)
Phase 3 Phase2 Phase1
(discharge influx)
(Lift influx to surface) (Fill drill pipe with
heavy mud)
Ch
oke
pre
ssu
re
Wait-and-Weight MethodThis is a one-circulation well control method. It is sometimes referred to as the Engineer’s method . In the wait-and-weight method, the influx is circulated out and primary control of the well is regained in one circulation. In this method, the drilling fluid is first weighted up to the kill fluid density, then the kill fluid is pumped in the well, displacing both the formation fluid influx and the original drilling fluid.Following are the steps of the wait-and-weight well control method:1. Mix the kill fluid.2. Bring the pump up to speed for the circulation at slow rate. Slowly open the remotely operated choke while the pump is slowly brought up to speed. Maintain choke pressure equal to the shut-in casing pressure prior to the start of the circulation.3. Once the pump is up to speed, record the initial circulating pressure on the drill pipe pressure gauge.maintain drill pipe pressure as per the drill pipe pressure schedule. Ensure that the pump rate is kept constant during circulation.4. Pump kill fluid into the well through the drill string. As the drill string isdisplaced with kill fluid, the drill pipe pressure will reduce as thehydrostatic pressure of the drilling fluid column inside the drill stringincreases. Once the fluid inside the drill string has been displaced by killfluid, the drill pipe pressure should equal the FCP. Maintain this drill pipepressure for further circulation.
ANALYSIS OF ICP & FCP
3000
2000
1000
I
C
P
C
P
F
2500 2380 2260 214 0 2020 1900 1780 1660 1540 1420 1300
0 100 200 300 4 00 500 600 700 800 900 1000
0 4 8 12 16 20 24 28 32 36 40
Heavy mud fills pipe
Pc1
Pdp
STAND PIPE
PRESSURE Pc2
CHOCK PRESSURE Pann
Phase 1 Phase2 Phase3 Phase4
Heavy mud fills annulus
Influence of gas
Result of P choke
Influence of heavy mud
Phase 2 Phase 1 Pann
Annulus of choke pressures versus time
GAS BUBBLE COLLAPSE
HGAS = 200 FT HMUD = 6000 FT GG = 0.1 PSI / FT MG = 1.0 PSI / FT
GAS BUBBLE COLLAPSE
HGAS = 50 FT HMUD = 6150 FT GG = 0.1 PSI / FT MG = 1.0 PSI / FT
Other well control methods
Volumetric
Lubricate and bleed
bullheading
Volumetric methodThe volumetric method is a non-circulating well kill method and
can be used only if the influx can migrate up , such as a gas kick where the free gas is able to migrate up in the well . Generally , the volumetric method is used in following situations
During any shut in period after the well has kicked and the gas is migrating up
If the pumps are inoperable.
If there is a washout in the drill string that prevents displacement of the kick through conventional circulation methods .
If the pipe is a considerable distance off bottom, out of the hole or stuck / parted off bottom.
If the drill string is plugged
Record the shut-in casing pressure
Monitor the shut-in pressure and if they are found to be increasing with time , this confirms gas migration. Commence with the volumetric method to allow controlled expansion of gas.
Select an overbalance margin and operating range for casing pressure. Recommended overbalance margin , 100 psi
Note : the overbalance margin in the casing pressure ensures that the overbalance inside the well bore is maintained as mud is bled from the well
Calculate hydrostatic pressure (HP) per bbl fluid in the upper annulus.
HP per bbl ( psi/bbl ) = fluid gradient (psi/ft) ÷ annular capacity factor (bbl /ft)
Calculate volume to bleed each cycle.
Volume to bleed (bbl/cycle ) = range (psi) ÷ HP per bbl (psi/bbl)
Construct casing pressure vs. volume to bleed schedule.
Allow SICP to increase by over balance margin.
Allow SICP to increase by operating range.
While maintaining the SICP constant at the new value , bleed small volumes of mud into a calibrated tank until the calculated volume in step 3 is bled
Repeat steps 6 and 7 until gas is at surface
Safety margin = 100 psi
Range = 100 psi
Fluid grad. = 0.546 psi /ft
Capacity factor = 0.04425 bbl /ft (9 5/8” * 5” )
Hp per bbl = 0.546 ÷ .04425 bbl / ft = 12.34 psi/bbl
Volume to bleed = 100 ÷ 12.34 = 8 bbls
Casing pressure 1 = 400 + 100 +100 = 600 psi
Casing pressure 2= 600 + 100 = 700 psi
Casing pressure 3 = 700 + 100 = 800 psi
0
200
400
800
600
1000
1200
1400
1600
8 16 24 32 40 48 56 Volume bled (bbls)
Example SICP = 400 psi ; range &SM = 100 psi ; volume bleed =8 bblsC
asin
g pr
essu
re (
psi
)
Gas migrating to surface
Bleeding while holding constant casing pressure
range
Range : 100 psi
Safety margin : 100 psi
Lubricate and bleed procedure
In this procedure, the gas and the associated casing pressure is bled off and replaced with fluid keeping the bottom hole pressure constant. The following procedure is used for lubricate and bleed
mix kill fluid
Pump through kill line into closed –in well to increase casing pressure by desired range . Recommended range = 100 psi
Allow time for fluid to “ fall “ through the gas (usually 10- 15 minute ).
Calculate bleed down pressure . The shut-in casing pressures during the lubricate and bleed procedure are related as the following equation
P3= (P1)² ÷P2
Where , P1 = SICP before pumping P2 = stabilized SICP after pumping
P3 = the pressure to bleed down to
Bleed dry gas from choke to reduce casing pressure to P3
Repeat step 1 through 4 until gas is removed
1000 psi 1100 psi 909 psi
909 psi 1009 psi 819 psi
(P1 )² ÷ P2 = P3
P1 =1000 psi P2 =1100 psi
Bullheading
In this well kill method , the formation influx is pumped back (bullheaded ) into the reservoir . It is a common well kill method is also used when
The influx is very large and circulating out the influx will either exert very high pressure on the surface equipment or will result in very high volume of gas at the surface .
The influx contains hydrogen sulfide (H2S) and it is not desired to circulate out the kick to the surface due to personal safety reasons
When an influx is taken with no pipe in the hole
PROCEDURE FOR BULLHEADING
1- calculate the surface pressure that well cause formation fracturing during the bullheading operation.
2- calculate the tubing (or drillpipe) burst pressure as well as casing burst (to cover the possibility of tubing failure during the operation)
3- calculate static tubing head (or drillpipe) pressure during bullheading.
4- slowly pump fluid down the tubing. Monitor pump and casing pressure during the operation.
Example:Depth of formation/perforations at 10,171 feet TVDFormation pressure = 4654 psi = 8.8 ppgFormation fracture pressure = 7299 psi = 13.8 ppgTubing 4-1/2“ N 80 Internal capacity = 0.0152 bbl/ft
Internal yield = 8,430 psiShut-in tubing head pressure = 3,650 psiGas density = 0.1 psi/ftTotal internal volume of tubing = 10,171 ft x 0.0152 bbl/ft = 155 bbl
-Maximum allowable pressure at pump start up. = (13.8 ppg x 10,171 ft x 0.052) - (0.1 psi/ft x 10,171 ft) = 6,281 psi
-Maximum allowable pressure when the tubing has been displaced to brine at 1.06 sg (8.8 ppg). = (13.8 ppg – 8.8 ppg) x 10,171 ft x .052 = 2,644 psiTubing head pressure at initial shut – in. = 3,650 psi
-Tubing head pressure when tubing has been displaced to brine. = 0 psi (i.e. the tubing should be dead) The above values can be represented graphically (as shown in the figure v.1 below). This plot can be used as a guide during the bullheading operation.
900080007000600050004000300020001000
0
50 100 150
Su
rfa
ce p
ress
ure
(p
si)
Volume of tubing displaced (bbl)
Static tubing pressure that would fracture formation
Include psi safety factor (to avoid fracturing formation)
tubing pressure toBalance formation pressure
Tubing burst pressure
ترين بحراني چاه كشتن هنگام دراست زماني لحظه
ميرسد . كفشك به گاز سر كه؟ چـــــرا
باز چاه در را انبساط بيشترين گاز زمان اين در زيرا
اززير هايدرواستاتيك فشار لحظه اين در و كرده پيدااست رسيده مقدار كمترين به چاه ته تا كفشك
بنابراين در كفشك زير به فشار بيشترين كه است طبيعي
ايـــن. شود وارد هنگام