03_pressure school

04/10/23 Formation Pressure Evaluation School

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Day ThreeObjectives :• Fracture Pressure• Leak Off Tests• Kick Tolerance• Casing Shoe Selection• Well Control

• Hole Problems• Lost Circulation• Kicks• Killing the Well

Formation Pressure


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FRACTURE PRESSURE

Formation Pressure


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Why Fracture Pressure Evaluation?

Formation Pressure

• The determination of fracture pressure is an integral tool in well planning.

• Knowledge of fracture pressures in a well assists in

– locating protective casing

– developing the mud program

– influencing the well control program

Fracture Gradient

PorePressure Gradient

MudWeight


4

Downhole Stress & Fracture Pressure

Formation Pressure

• Three principle downhole stresses are recognized

– a major stress (1)

– an intermediate stress (2)

– a minor stress (3)

• Fracture pressure is defined as the applied pressure which, when equal to or exceeding the formation’s minor horizontal matrix stress and its pore pressure, produces a fracture.

1

32


5

Downhole Stress & Fracture Pressure

Formation Pressure

• Fracturing will occur perpendicular to the plane of least stress.

3

Below a certain depth, overburden will exceed horizontal stress and vertical fracturing will occur.

Near surface, horizontal fracturing may occur due to the low overburden.


6

Determining Fracture Pressure

Formation Pressure

• In oilfield operations two fracture pressures should be considered

– Fracture Initiation Pressure

• the pressure needed to open a new fracture.

100

200 400

500

300Pressure

Time

Initiation Pressure > Pore Pressure + Matrix Strength + Least Horizontal Stress

3


7


Formation Pressure

Pressure

Time

• In oilfield operations two fracture pressures should be considered

– Fracture Initiation Pressure

• the pressure needed to open a new fracture.

– Fracture Injection Pressure

• the pressure needed to hold open and extend a pre-existing fracture.

• Initiation pressure may be 10-50% higher than injection pressure.

100

200 400

500

300

3

Injection Pressure > Pore Pressure + Least Horizontal Stress


8

Formation Pressure

Estimated Fracture Pressure at Any Depth

Maximum Dynamic Mud Pressure &

Maximum Shut-in Casing Pressure

LEAK OFFTEST

Kick Tolerance

“S”(from 1)

“P”(from 2)

Rock CuttingsPoisson’s

Ratio “”

Tectonicstress

ThePlan

(3)FracturePressure


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Formation Pressure

• To calculate fracture pressure we need to know

– overburden pressure


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Formation Pressure


– overburden pressure– pore pressure


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Formation Pressure


– overburden pressure– pore pressure– how the rock behaves

• Rocks can be considered to be – elastic: deform under stress

& return to their original shape once the stress is removed.

Stress Released

Elastic


12


Formation Pressure


– overburden pressure– pore pressure– how the rock behaves

• Rocks can be considered to be – elastic: deform under stress

& return to their original shape once the stress is removed.

– plastic: deform but do not return to their original shape once the stress is removed.

Stress Released

Plastic


13


Formation Pressure

• Fracture pressure calculations generally consider rocks to be elastic, and a Poisson’s ratio is included in the calculation.

• Poisson’s ratio is the ratio of change in length and diameter of a cylinder of rock under stress.

• Poisson’s ratio is not applicable to formations that plastically deform.

• Poisson’s ratio = ( d/d ) / (l/l )

where: = Poisson’s ratio d = change in diameter• d = original diameter l = change in length• l = original length

l

d

l

d


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LEAK OFF TESTS

Formation Pressure


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Leak Off Tests

Formation Pressure

• A Leak Off Test is used to determine the maximum pressure that can be applied to the formation while drilling the next hole section.

• Generally LOT’s are performed after cementing casing.

• This zone is considered to be the weakest part of the formation for the next hole section.

• There are distinct types of pressure test:

• FIT - Formation Integrity TestThis tests to a predetermined pressure, which is designed to be below the probable fracture pressure.

• LOT - Leak Off TestDetermines the yield point of the weakest formation.

• Formation BreakdownThis fractures the formation and injects fluid.


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Leak Off Tests

Formation Pressure

• Equipment required for the monitoring of mud volume, surface pressure and pump rate need to be tested prior to the LOT. Usually the rig equipment is not accurate enough to measure the small volumes required and so service company equipment is utilised:

• Most cementing companies have 10 barrel tanks and these need to be calibrated in 0.25bbl increments.

• An accurate gauge or pressure recorder is required to measure pressure in 20psi increments.

• Pump rates need to be 1/8 bbl/min and so the pumps need to be checked to see if they can operate at this required level.

• Pre-test calculations need to be done to determine:• anticipated LOT pressure• annulus, drillstring and open hole volumes• anticipated slope (minimum volume line) of the LOT• frictional pressure loss to initiate circulation.

Pre-Test Procedures


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Leak Off Tests

Formation Pressure

Step 1 - Drill out the liner hanger / float collar and test.

Step 2 - Drill out the shoe-track and test.

Step 3 - Drill out the shoe and test.

Step 4 - Drill 2-3m (5-10ft) of new formation.

Step 5 - Circulate to ensure that the hole is clean of cuttings and monitor the mud density, to ensure that the mud is the same density throughout the hole and that the density is known.

Step 6 - Pull the bit inside the casing and either close the BOPs or the packer.

Step 7 - Rig up the cementing unit to either pump down the annulus or the drillstring and test.

Leak Off Test Procedures (1)


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Leak Off Tests

Formation Pressure

Step 8 - Slowly pump at 0.25bbl/min until bleed off or until the fracture pressure is reached. NEVER EXCEED 80% OF THE MINIMUM YIELD OF THE WEAKEST EXPOSED CASING OR THE PRE-TEST FRACTURE PRESSURE.

Step 9 - Record the mud volume pumped versus pressure, monitoring every 0.25 bbl pumped.

Step 10- During the test, draw up a plot of the pressure versus the mud volume.

Step 11- When the maximum pressure is reached, shutdown the pumps and record the pressure every 2 minutes for twenty minutes.

Step 12- Release the pressure by either opening the BOP’s or the

packer and record the mud volume returned.

Leak Off Test Procedures (2)


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Leak Off Tests

Formation Pressure

Formation Integrity Test

• This test does not fracture the formation but merely tests the formations integrity to a pre-determined test pressure.

• Typically the anticipated slope shows a linear relationship between the volume pumped and the pressure


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Leak Off Tests

Formation Pressure

Leak-Off Test

• Initially the LOT follows the same linear pattern on the anticipated slope as the FIT.

• At the point of divergence leak-off is achieved and the trend becomes non-linear.


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Leak Off Tests

Formation Pressure

Formation Breakdown Test

• Again the anticipated slope is linear prior to achieving breakdown of the formation.


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Leak Off Tests

Formation Pressure

Extended LOT

Gau

ge P

ress

ure

(p

si)

Vol. (bbl) Time (mins)

ab

c

a = Leak-off Pressureb = Initiation Pressurec = Injection Pressure

pump stopped

bleed off

LOT Example Calculation

Depth of test = 9050 ftMud Weight = 9.5 ppgGauge Press = 850 psi

Fp = (9050 * 9.5 * 0.0519) + 850

Fp = 5312.1 psi

Fg = 5312.1 / (9050 * 0.0519)

F. Gradient = 11.28 ppg EQMD


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FRACTURE PRESSURE ESTIMATION

Formation Pressure


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Fracture Pressure Estimation

Formation Pressure

• Fracture pressure theory has been marked by confusion:

• By applying results and conclusions obtained in sandstones to shales.

• And by using methods outside the region of study.

• The more well known theories include :• Hubbert and Willis (1957)

• Matthews and Kelly (1967)

• Eaton (1968)

• Cesaroni, Giacca, Schenato & Thieree (1981)

• Daines (1982)

Fracture Gradient


MudWeight


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Formation Pressure

Hubbert & Willis (1957)

• They examined pressures related to the hydraulic fracturing of sandstones, superposed stresses caused by the borehole and the reduction of stress caused by pre-existing fractures.

• They said that the pressure to open a pre-existing fracture was only slightly greater than the minimum horizontal stress.

• Fracturing would occur when the minimum horizontal stress was equal to 1/3 to 1/2 of the vertical effective stress.

F = (S + 2P) / 3

F = Fracture PressureS = Overburden Pressure

P = Pore Pressure

Fracture Gradient


MudWeight


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Formation Pressure

Matthews & Kelly (1967)

• They derived a “matrix stress coefficient” working with data collected from Gulf Coast sandstones.

• The constant - “k” - varies from 0.33 to 1.0 with depth.

• Two curves were produced, one for offshore Texas and one for offshore Louisiana. (The difference is due to higher clay content in the offshore Texas formations.)

F = k + P

F = Fracture Pressurek = Matrix Stress Coefficient = Vertical Stress (overburden)

P = Pore Pressure

Fracture Gradient


MudWeight


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Formation Pressure

Eaton (1968)

• Eaton recognised that the overburden gradient should be a variable.

• Eaton’s Poissons Ratio comes from fracture tests in sandstones, and the method continues to be valid for sandstones but not for shales.

F = (S - P) * ( / ( 1 - ) ) + P

F = Fracture PressureS = Overburden PressureP = Pore Pressure = Poisson’s Ratio

Fracture Gradient


MudWeight


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Formation Pressure

Cesaroni, Giacca, Schenato & Thieree (1981)

• They recognised the difference in elastic and plastic rocks.

• There are three conditions :1) Elastic rocks with non penetrating mud :

F = [(S - P) * (2 / (1 - ))] + P

2) Elastic rocks with a penetrating mud :

F = [(S - P) * 2 ] + P

3) Plastic rocks :

F = S

= 0.25 for clean sands & carbonates at shallow depths = 0.28 for shaley sands & carbonates at greater depths

Fracture Gradient


MudWeight


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Formation Pressure

Daines (1982)

This requires good leak-off test data :

Step 1) At the shoe … calculate superposed tectonic stresst = F - [ (S - P) * ( /( 1- )) ] - P… calculate stress ratio = t / (S - P)

Step 2) At any subsequent depth … calculate superposed tectonic stress t = (S - P) * … calculate fracture pressure F = t + [ (S - P) * ( / (1 - )) ] + P

Where:F = Fracture Press. from LOTS = Overburden Pressure P = Pore Pressure t = Superposed Tectonic Stress = Effective Stress RatioLithology specific Poisson’s


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Formation Pressure

Daines (1982)

• Daines uses a table of lithology specific Poisson’s ratios.

• His method attempts to take into account local tectonic stress.

• The method hinges on a reliable leak-off test being performed and the correct Poisson’s ratio being used.


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Fracture Pressure - Conclusion

Formation Pressure

• The calculation of fracture pressure is critical for successful well planning.

• Leak off tests and fracture tests will give good offset data if their limitations are recognized.

• Fracture pressure estimation while drilling however, has to be interpreted with care.

• Many methods are based on regional data sets which should not be used globally.


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Formation PressureFormation Pressure Worksheet Agip Fracture Pressure Calculations

Air Gap 95.1 feet 29.0 metres

Water Depth 728.4 feet 222.0 metres 0.250

Normal PP 8.7 ppg 1.04 sg 0.280

TVD (ft) TVD (m) OBG (sg) Pore Pr dt Sandst (ppg) (sg)

984.3 300.0 1.08 1.03 50.00 9.0 1.071148.3 350.0 1.21 1.02 50.00 9.7 1.171312.3 400.0 1.30 0.91 50.00 10.2 1.221476.4 450.0 1.38 0.89 50.00 10.6 1.271640.4 500.0 1.45 0.94 50.00 11.2 1.341804.5 550.0 1.50 0.97 50.00 11.6 1.391968.5 600.0 1.55 0.95 50.00 11.8 1.422132.5 650.0 1.60 0.94 50.00 12.1 1.452296.6 700.0 1.64 0.91 50.00 12.3 1.482460.6 750.0 1.67 0.87 50.00 12.5 1.492624.7 800.0 1.71 0.90 50.00 12.7 1.532788.7 850.0 1.74 0.84 50.00 12.8 1.542952.7 900.0 1.76 0.80 50.00 12.9 1.553116.8 950.0 1.79 0.77 50.00 13.0 1.563280.8 1000.0 1.81 0.83 50.00 13.3 1.603444.9 1050.0 1.84 0.74 50.00 13.3 1.593608.9 1100.0 1.86 0.81 50.00 13.6 1.633772.9 1150.0 1.88 0.69 50.00 13.5 1.623937.0 1200.0 1.90 0.73 50.00 13.7 1.644101.0 1250.0 1.92 1.05 50.00 14.4 1.734265.1 1300.0 1.94 1.16 50.00 14.7 1.764429.1 1350.0 1.96 1.03 50.00 14.6 1.754593.1 1400.0 1.97 1.14 50.00 14.9 1.794757.2 1450.0 1.99 1.20 50.00 15.1 1.81

Using the AGIP method, the

shales can be assumed to

have Frac.Pr. = to OBG.

Poisson - Dirty Sst

AGIP Fracture Pr.

Well - Bideford - 31/7 : Grossenschmuck : Celtic Petroleum

Fracture Pressure Data

Poisson - Clean Sst

300.0

450.0

600.0

750.0

900.0

1050.0

1200.0

1350.0

1500.0

1650.0

1800.0

1950.0

2100.0

2250.0

2400.0

2550.0

2700.0

2850.0

3000.0

3150.0

0.00 0.25 0.50 0.75 1.00 1.25 1.50 1.75 2.00 2.25 2.50

Pore - Fracture - OBG

dep

th m


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Formation PressureFormation Pressure Worksheet Agip Fracture Pressure Calculations

Air Gap 95.1 feet 29.0 metres Conglom 0.20 Siltst 0.08

Water Depth 728.4 feet 222.0 metres Wet Clay 0.50 Crse Sst 0.05 Avg Lst 0.28

Normal PP 8.7 ppg 1.04 sg Clay 0.17 Med Sst 0.06 Shly Lst 0.17

Silty Shale 0.17 Fine Sst 0.04 Foss Lst 0.09

Sndy Shale 0.12 Cly Sst 0.24 Dolomite 0.21

TVD (ft) TVD (m) OBG (sg) Pore Pr Poisson Stress (sg) Depth (ppg) (sg) Pois Stress Beta

984.3 300.0 1.08 1.03 1148.3 350.0 1.21 1.02 1312.3 400.0 1.30 0.91 0.50 400 12.9 1.55 0.50 139 0.621476.4 450.0 1.38 0.89 0.50 1640.4 500.0 1.45 0.94 0.06 1804.5 550.0 1.50 0.97 0.12 1968.5 600.0 1.55 0.95 0.12 2132.5 650.0 1.60 0.94 0.06 2296.6 700.0 1.64 0.91 0.12 2460.6 750.0 1.67 0.87 0.17 2624.7 800.0 1.71 0.90 0.17 2788.7 850.0 1.74 0.84 0.17 2952.7 900.0 1.76 0.80 0.17 3116.8 950.0 1.79 0.77 0.17 3280.8 1000.0 1.81 0.83 0.17 3444.9 1050.0 1.84 0.74 0.17 3608.9 1100.0 1.86 0.81 0.17 3772.9 1150.0 1.88 0.69 0.10 3937.0 1200.0 1.90 0.73 0.17 4101.0 1250.0 1.92 1.05 0.12 4265.1 1300.0 1.94 1.16 0.08 4429.1 1350.0 1.96 1.03 0.08 4593.1 1400.0 1.97 1.14 0.17 1278 1.95 1400 16.3 1.95 0.17 1278 0.774757.2 1450.0 1.99 1.20 0.17 1254 1.97

Daines Fracture Pr. LOT Data (Tectonic Stress Calc.)

Well - Bideford - 31/7 : Grossenschmuck : Celtic Petroleum

Daines Poissons Ratios


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Formation Pressure300.0

450.0

600.0

750.0

900.0

1050.0

1200.0

1350.0

1500.0

1650.0

1800.0

1950.0

2100.0

2250.0

2400.0

2550.0

2700.0

2850.0

3000.0

3150.0

0.00 0.25 0.50 0.75 1.00 1.25 1.50 1.75 2.00 2.25 2.50

Pore - Fracture - OBG

dep

th m

Pore Pr

OBG (sg)

AGIP Fracture Pr.

Daines Fracture Pr.


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KICK TOLERANCE

Formation Pressure


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Kick Tolerance Definition

Formation Pressure

• Kick Tolerance is defined as the maximum formation balance gradient that may be encountered if a kick is taken at the current depth, with the current mud density and the well shut-in, without downhole fracturing occurring.

• The limit of this pressure is usually set by the minimum fracture pressure in the open hole.

• It is of great importance that the estimated kick tolerance is not exceeded because if a kick is taken whilst drilling, there is an increased risk that an underground blowout will result when the well is shut in.

Fracture Gradient


MudWeight


37

Kick Tolerance Calculation

Formation Pressure

• Kick tolerance can be constantly calculated while drilling:

KT = (TVDwf/TVDb) * (FPmin - MW) + MW

Where:

FPmin = Fracture Pressure at weakest formation( ppg ) MW = Mud weight (ppg) TVDwf = True vertical depth of weakest formation (ft)TVDb = True vertical depth of bit (ft)

• This is the Kick Tolerance value that should be reported by INTEQ pressure engineers.

Fracture Gradient


MudWeight


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Kick Tolerance Definition

Formation Pressure

• If fluids enter the well bore the mud density will drop and the pore pressure that can be tolerated will be less

• A “minimum” kick tolerance allowing for influx can be calculated using :

Ktmin = [(TVDwf/TVD) * (Pfmin - MW)] - [(Lk/TVD) * (MW - Wk)] + MW

Where:

Ktmin = Minimum Kick Tolerance (lb/gal)Wk = Density of kick fluids (lb/gal)Lk = Length of kick (ft)

Lk = (1029 / Hole Dia.^2 - Pipe Dia.^2) x Bbls. Influx

Fracture Gradient


MudWeight


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CASING SEAT SELECTION

Formation Pressure


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Casing Seat Selection

Formation Pressure

• During well planning, correct determination of pore and fracture pressure are important for selecting the depths for casing seats.

• The selection process starts at the base of the hole. • Once the depths have been selected it is important

to check whether the formation is suitable for setting a casing seat.

• For near surface casing strings local legislation usually determines the maximum and minimum depths for drive pipe and surface casing.

• Once the number of casing strings have been determined then the casing sizes can be selected.

• The more casing strings needed, the more costly the well.


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Formation Pressure


42


Formation Pressure

• This graph is drawn from the data on the previous slide.

• Casing selection starts at the bottom, drawing a line vertically from the final mud weight up to the fracture pressure curve - ( 1 to 2 )

• This is where the casing shoe should be placed.

• The process continues on up the well bore.

• Accurate fracture pressures important!


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Formation Pressure

Fracture Gradient Fracture Gradient

FormationPressure Gradient

FormationPressure Gradient

MudGradient

High Mud Density

Low Mud Density

Note that if an excessively high mud weight is used then more casing seats are required.


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BASIC WELL CONTROL

Formation Pressure


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Basic Well Control

Formation Pressure

• There are two conditions :

• Overbalanced Conditions• Formation/shoe fracture• Lost Circulation• Stuck pipe problems• Increased costs

• Underbalanced Conditions• Kicks• Stuck pipe problems• Borehole stability problems• Increased costs


46

Lost Circulation

Formation Pressure

• The partial or complete loss of whole drilling fluid to a formation.

• May be due to ...

• Poor cement jobs.• Permeable, unconsolidated,

cavernous, vuggy or naturally fractured formations.

• Mechanically induced fractures • Too quick a start of pumps when

breaking circulation.• Too high mudweight / viscosity.• Too quick tripping velocity.• Too high pump rates / pressure

pulses.


47

Recognising Lost Circulation

Formation Pressure

• Drilling break - often the first indication

• Pit volumes decrease• Return flow diminishes or stops• Pump pressure decreases

• Loss into Natural Fractures = Loss occurs during or after a formation change or after rough drilling

• Loss into Induced Fractures = Loss occurs while tripping, breaking circulation or raising the mud weight

• Loss into Porous/Permeable Formations = Loss occurs gradually and increases with penetration rate


48

Lost Circulation

Formation Pressure

Problems

• Expensive– Cost of materials– Cost of rig time

• Higher circulation pressures required to pump LCM

• Possibility of plugging– Bit– Motors– MWD tools

• Lowered hydrostatic pressure of mud column

– Kicks

Prevention

• Know the Geology– Types of formations– Tectonic history

• Monitor Formation Pressures– Fracture pressure– Mud weight / ECD

• Monitor Tripping and Casing Runs– Calculate surge pressure– Monitor pressure to break

circulation– Monitor pit levels and return

flow


49

Well Kicks

Formation Pressure

• For a kick to occur:• Pore pressure > hydrostatic of the

mud column• Formation must be porous and

permeable

• Most common causes of kicks are:• Failure to keep the hole full• Result of lost circulation• Swabbing of light formation fluids• Insufficient mud density• Abnormal formation pressure


50

Kicks - Drilling & Tripping

Formation Pressure

• Drilling:• Kicks and blowouts generally occur

because of an increase in formation pressure.

• Tripping:• Kicks and blowouts generally occur

because of a decrease in mud hydrostatic.

• It should be impossible for a blowout to occur without warning.

• The well and mud system are a closed system.

• Any influx will show itself as a change of flow rate or pit volume.


51

Kicks - Indications

Formation Pressure

• Drill break - increase in penetration rate due to pressure differential

• Increased flow out and a gain in the mud pits

• Increase in hookload - buoyancy of mud reduced

• Decrease in standpipe pressure and increase in pump rate

• Increase in flowline temperature• Increase in salinity from cuttings

fluids or salt water seeps• Gas cut mud - when associated with

higher connection gases


52

Kicks - Sequence of Events

Formation Pressure

• While Drilling :(1) Drill break (2) Increase in flow (3) Pit volume increase (4) Pump pressure drops

• While Tripping Out :(1) Hole stays full (2) Flow from flowline (3) Pit volume increase

• While Tripping In :(1) Hole does not stop flowing

between stands (2) Pit volume increase


53

Kicks and Blowouts

Formation Pressure

• A blowout is:• An uncontrolled flow of formation

fluids into and then from the wellbore.

• Kicks become blowouts because:• Lack of early detection• Failure to take proper initial action• Lack of adequate casing or

cement job• Lack of adequate surface control

equipment• Malfunction of control equipment


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Kicks - Control Techniques

Formation Pressure

• Primary:• Proper use of drilling fluid and

hydrostatic pressure• Secondary:

• Use of the BOP system• Correct use of kill methods

• Drillers method• Engineers method• Concurrent method

• Tertiary:• Call blowout specialists• Drill relief wells


55

Killing The Well

Formation Pressure

Pre-Recorded Information & Calculations

• Volume Calculations• Surface pipe• Drill pipe• Annular capacities

• Time/Strokes• Surface to bit• Bit to surface

• Kill Rates/Pressures• SCR’s for each pump

• Shut In Pressures– Drillpipe (SIDPP)– Casing (SICP)

• Kill Mud Weight• Circulating Pressures

– Initial– Final

• Maximum Allowable Shut In Pressure


56

Killing The Well

Formation Pressure

Slow Circulation Rates

• Provides Predetermined Kill Rates• Why Use SCR’s

• Mud weight increase easier• Choke reaction time• Minimize pressures• Lessen problems with gas at surface

• SCP + SIDPP = ICP • (ICP= Initial Circulating Pressure)

• SCP * KMW / OMW = FCP• (FCP= Final Circulating Pressure)

• When Taken?

– Changing mud properties

– Changing bit/bha

– Every 500 feet

– Each tour

– After pump repairs


57

Killing The Well

Formation Pressure

Shut In Drillpipe Pressure

• Used to calculate the kill mud weight.• Kill mud weight

• OMW + (SIDPP / (0.052 * TVD))• Important to be accurate.• Not always lower than the casing

pressure.• Record every minute until stable.

• After 30 minutes, any rise may be

due to gas.

Shut In Casing Pressure

• Indicates type of influx.

• Critical to prevention of

– Lost circulation

– Underground blowouts

– Casing burst

– BOP stack limits

– Formation damage


58

Killing The Well

Formation Pressure

Maximum Allowable Surface Casing Pressure

• This is the maximum pressure for complete safety• It may be based on

• Maximum fracture pressure at the shoe - (LOT’s)• Maximum pressure for casing - (casing burst specs)• Maximum pressure for the wellhead assembly -

(equip. specs)

• Normally the MASCP is based on the leak-off test.


59

Killing The Well

Formation Pressure

Rising Pressures After Shutting In

• Rising pressures after shutting in may be due to• Percolation of gas up through the mud• Low permeability in kicking formation

• It will be impossible to tell the difference until the gas has been circulated out.

• Gas out and stable drill pipe pressure = Gas percolation

• Gas out and unstable drill pipe pressure = Low permeability

• Initially always assume the worst case scenario and assume there is percolating gas.


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Killing The Well

Formation Pressure

Indications of Possible Mechanical Problems While Killing the Well.

Drillpipe Casing Hookload Pit Pump

Pressure Pressure Level SPM

Loss of Circulation

Choke Line Plugs

Bit Nozzle Plugs

Bit Nozzle Washout

Pump Volume Drops

Washout in Drillstring

Gas Feeding In

Choke Washes Out

Gas Reaches Surface

MechanicalProblems

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