on january 10, 1901, the lucas gusher blew in at spindletop, near beaumont, texas. the hamill...

• 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 .

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


BHP = 7200 PSI

2000 + 5200 = 7200 PSI

2200 PSISTAGE TWO

5200 PSI SHOE

W/H PRESS = GAS PRESS = 5200


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


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


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



Hard Shut –in: Close Annular BOP

Choke Line HCR Valve closed

Annular BOPClose

ANNULAR

PIPE RAM

BLIND RAM

PIPE RAM

ChokeClose


Overboard



Overboard

ChokeClosed

Drill string



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


Overboard



Overboard

ChokeClose

Drill string



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


Overboard



Overboard

ChokeClose

Drill string



Soft shut-in :open choke line HCR valve

open Choke Line HCR Valve

Annular BOPClose

ANNULAR

PIPE RAM

BLIND RAM

PIPE RAM

Chokeopen


Overboard



Overboard

ChokeClosed

Drill string



soft Shut –in: Close Annular BOP

Choke Line HCR Valve Opened

close Annular BOP

ANNULAR

PIPE RAM

BLIND RAM

PIPE RAM

Closechoke


Overboard



Overboard

ChokeClosed

Drill string



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

on january 10, 1901, the lucas gusher blew in at spindletop, near beaumont, texas. the hamill...

Documents

pressure pressure

formation pore pressure

pressure increment

high formation pressure

formation pressure greater

hydrostatic pressure

normal pressure gradient

hydrostatic pressure