well intervention pressure control

P & P OF INTERVENTION PRESSURE CONTROL

PRESSURE CONCEPTS Contd.

PORE PRESSURE Also called formation pressure, is the pressure exerted by fluid

trapped in pore spaces of a formation. Pore pressure can be divided in to following three categories depending upon the pore pressure

gradient value of a given formation:

• Normal Pore Pressure : If the pressure gradient value is between 0.433 & 0.465 psi/ft

• Abnormal Pore Pressure : If the pressure gradient value is more than 0.465 psi/ft. The upper limit of abnormal pressure gradient is

overburden gradient• Sub-normal Pore Pressure : If the pressure gradient value is less

than 0.433 psi/ft


HYDROSTATIC PRESSURE It is the pressure exerted by a static column of fluid by virtue of its

density. It depends on the Density & True Vertical Depth (TVD) of the fluid column. Its unit is psi.

Hydrostatic Pressure (psi) = Mud density (ppg) 0.052 TVD (feet)

Example:Calculate Hydrostatic Pressure exerted by 10 ppg fluid at a depth of 10000 ft (TVD).Solution :Hydrostatic Pressure = 10 0.052 10,000 = 5200 psi


PRESSURE GRADIENT It is the pressure exerted by a fluid of a given density measured over a given unit depth. Pressure Gradient is also referred as mud gradient.

Its unit is psi/ft.

Formula :Pressure Gradient (psi/ft) = Fluid Density(ppg) × 0.052

Pressure Gradient of Fresh Water = 0.052 × 8.33 = 0.433 psi / ft Pressure Gradient of Salt Water = 0.052 × 8.94 = 0.465 psi / ft

Example :Calculate pressure gradient of 11.5 ppg brine

Solution : Pressure Gradient = 0.052 × 11.5 = 0.598 psi / ft

BARRIER CONCEPTS

A BARRIER IS ANY DEVICE, FLUID OR SUBSTANCE THAT PREVENTS FLOW OF WELL BORE FLUIDS

FOR WELL INTERVENTION OPERATIONS A MINIMUM OF TWO TESTED & INDEPENDENT BARRIERS SHOULD BE AVAILABLE AT ALL TIMES

TYPES OF BARRIERS :

• MECHANICAL

• HYDROSTATIC (only if overbalance )

MECHANICAL BARRIERS

They can be either closed barriers e.g. wire line stuffing box, CT stripper etc. or closeable barriers which are normally open but can be closed whenever required e.g. BOPs , Xmas tree valves etc.

BARRIER CONCEPTS Contd..MECHANICAL BARRIERS

• CLOSED BARRIER

WIRE LINE STUFFING BOX

GREASE CONTROL HEAD

COIL TUBING STRIPPER

• CLOSEABLE BARRIER

BLOW OUT PREVENTER (BOP)

X-MAS TREE VALVES

SHEAR SEAL VALVES / BLOW OUT PREVENTER

ANNULAR PREVENTER

SUB SURFACE SAFETY VALVES (ONLY WHEN THEY ARE LEAK TIGHT)

Additional barriers such as wire line plugs, bridge plugs, ice plugs etc. can be installed down hole as back up to failed primary/secondary barriers

BARRIER CONCEPTS Contd.

HYDROSTATIC BARRIERS

A HYDROSTATIC BARRIER IS PROVIDED BY LIQUID COLUMN IF THE PRESSURE EXERTED BY IT IS MORE THEN THE PORE PRESSURE AND THE FLUID LEVEL & WEIGHT CAN BE MONITORED

VARIOUS HYDROSTATIC BARRIERS ARE :

• Drilling Mud

• Brine

• Fresh Water

• Sea Water

BARRIER CONCEPTS Contd.

CATEGORIES OF BARRIERS

• PRIMARY - first line of pressure control e.g. wire line stuffing box, grease control head, coil tubing stripper etc.

• SECONDARY - second line of pressure control e.g. blow out prevention equipment such as wire line/coil tubing BOP & annular preventer etc.

•TERTIARY - normally installed for high pressure wells & is used only when the secondary barriers can not contain the well pressure effectively. A tertiary barrier is either integral part of xmas tree e.g. wire line cutter actuator or are installed directly above the tree e.g. wire line/coil tubing shear-seal BOPs

WORK-OVER WELL KILL Contd..Some mechanical failures of production conduit (e.g. replacing

failed WRSV) can be repaired without killing by Live Well

Intervention techniques, however certain other failures given below

require to kill the well & pull completion string.

Failures that require to kill the well and pull out tubing :

TRSV Failure

Casing, tubing or packer leak

Cement failure*

Artificial lift system failure (e.g. Failed submersible pump)

Other common reasons for work-over which may require to kill the well are completing new reservoir, stimulating existing completion, reducing water coning etc.

WORK-OVER WELL KILL Contd..PRE RECORDED WELL INFORMATION

• Tubing length, ID/OD, burst, collapse, tensile strength etc

• Measured depth, deviation data, type & minimum ID of safety valve

• Top, bottom (both MD & TVD) & condition of perfs

• Tubing nipples & sliding sleeves; depths, types & IDs

• Side pocket gas mandrels, if any, depth & type, installed dummies/valves

• Type & depth of packer

• Type & density of completion fluid in annulus

• Formation pressure based on last BHP survey, fracture pressure etc.

• Well head pressure rating, maximum allowable casing pressure

METHODS OF KILLING A PRODUCING WELL

•REVERSE CIRCULATION

•BULL HEADING

•LUBRICATE AND BLEED

•FORWARD CIRULATION

GAS OIL PACKER

KILL

IN

OUT

STAGE -1INITIAL CONDITIONS

Connect the pump to the side outlet of tubing head spool and choke manifold to the production side outlet of Xmas tree.

Method requires a circulation path to be opened by operating a circulation device or punching hole (using

explosive tubing perforators or punch). THIS DEPTH IS USED FOR ALL VOLUME CALCULATIONSTHIS DEPTH IS USED FOR ALL VOLUME CALCULATIONS

+ve differential pressure may blow up wire line tool string

-ve makes shifting of sleeve or pulling gas lift dummy difficult

.

REVERSE CIRCULATION

Circulating device (closed)

STAGE -1INITIAL CONDITIONS

REVERSE CIRCULATION

GAS OIL PACKER

KILL

IN

OUT It is important to install a wire line set plug below

packer (e.g. packer tail pipe) to isolate formation from completion & kill fluid.

In case plug is not installed, maintain 200 psi extra pressure from surface through choke as per IWCF requirement (if mentioned).

Circulating device (open)

GAS OIL PACKER

KILL

IN

OUT

STAGE - 2GAS IS OUT, OIL AT SURFACE


Pump is started slowly to approx 2 BPM keeping tubing pressure constant (or increasing by 200 psi, if mentioned) with the help of choke.

As the kill fluid is pumped down the annulus, tubing pressure is reduced in accordance with Reverse Circulation graph to keep BHP constantBHP constant .

STAGE 2 - Total gas has been pumped out.

GAS OIL PACKER

KILL

IN

OUT

STAGE - 3OIL IS OUT, COMPLETION FLUID AT SURFACE


STAGE 3 - Completion fluid reached surface.

Tubing pressure becomes zero when completion fluid reaches surface.

Casing pressure value may or may not be zero depending on the weight of kill fluid compared to the weight of completion fluid*. (lower weight is required due to pressure regression).

GAS OIL PACKER

KILL

IN

OUT

STAGE - 4ANNULUS FULL OF KILL FLUID


STAGE 4 - Annulus is full of kill fluid.

Choke remains wide open as tubing pressure continues to be 0 while kill fluid is pumped down the annulus.

GAS OIL PACKER

KILL

IN

OUT

STAGE - 5KILL FLUID AT SURFACE


STAGE 5 - Kill fluid has reached the surface.

When kill fluid reaches surface well is completely killed.

INITIAL STAGE GAS OUT OIL OUT ANN FULL OF KILL FL KILL FL AT SURFACE

GAS OIL PACKER

KILL

REVERSE CIRCULATIONDIFFERENT STAGES

REVERSE CIRCULATION

ADVANTAGES It utilises natural U tubing effect resulting in lower circulating pressures#.

Lesser chances of mixing as gas & oil are lighter and remain above the completion fluid while reverse circulation.

More predictable as every thing comes out in order. Hence strokes for different points can be calculated.

Little risk of accidentally fracturing formation like in Bullheading.

Little or no damage to formation by contaminants from tubing or annulus.It is therefore the most preferred method & forward circulation is least preferred. If not mentioned, it must be presumed that killing method is reverse circulation.

DISADVANTAGES Slower than Bullheading

Find SITHP and SICP at different stages of reverse circulation. Find SITHP and SICP at different stages of reverse circulation. Draw Tubing and Casing pressure graphs.Draw Tubing and Casing pressure graphs.Tubing Capacity = 0.01458 bbl/ft Annulus Capacity = 0.0252 bbl/ft

Gas = 2000 ft, 0.04 psi/ft Oil = 4000 ft, 0.38 psi/ft

SSD = 6000 ft Pump output = 0.0157 bbl/stroke

Packer fluid = 0.6 psi/ft Kill fluid = 0.5 psi/ft

REVERSE CIRCULATION EXERCISE

INITIAL STAGE GAS OUT OIL OUT ANN FULL OF KILL FLUID STAGE-1 STAGE-4 STAGE-3 STAGE-2

SSD 6000 ft

Packer fluid 0.6 psi/ft

Gas 2000 ft, 0.04 psi/ft

Oil 4000 ft, 0.38 psi/ft

Kill fluid 0.5 psi/ft

GAS OIL PACKER

KILL

IN

OUT (Assuming Formation is initially balanced by Brine)(Assuming Formation is initially balanced by Brine)

Formation Pressure Formation Pressure = BHP = BHP

= 6000x0.6 = = 6000x0.6 =

3600 psi3600 psi

Initial Tubing PressureInitial Tubing Pressure

= Formation Pressure – = Formation Pressure –

Tubing Hyd Pr = 6000x.6 – Tubing Hyd Pr = 6000x.6 –

(2000x.04 + 4000x.38) (2000x.04 + 4000x.38)

= 3600 – (80 + 1520) = 3600 – (80 + 1520)

= 2000 psi= 2000 psi

Initial Casing Initial Casing

PressurePressure = 0 = 0

psipsi

STAGE-1INITIAL STAGE

REVERSE CIRCULATION EXERCISEREVERSE CIRCULATION EXERCISE

GAS OIL PACKER

KILL

IN

OUT

STAGE-2GAS OUT

•Tubing Pressure when gas is outTubing Pressure when gas is out = Formation Pr – Tubing Hyd. Pr = 6000x.6 – (4000x.38 + 2000x.6)

= 880 psi= 880 psi

• Kill fluid Vol Pumped in = GAS Vol outKill fluid Vol Pumped in = GAS Vol out = 2000x.01458

= 29.16 Bbls= 29.16 Bbls

•Kill fluid height = Kill fluid vol / Ann volKill fluid height = Kill fluid vol / Ann vol = 29.16 / .0252 = 1157 ft

•Completion fluid htCompletion fluid ht = 6000 – 1157 = 4843 ft

•Casing PressureCasing Pressure when gas is outwhen gas is out = Formation Pr – Casing Hyd. Pr = 3600 – (1157x.5 + 4843x.6)

= 115.7 psi= 115.7 psi


GAS OIL PACKER

KILL

IN

OUT

STAGE-3OIL OUT

•Tubing Pr when brine at surfaceTubing Pr when brine at surface = Formation Pr – Tubing Hyd. Pr = 6000x.6 – 6000x.6

= 0 psi= 0 psi

•Kill fluid Vol Pumped in = Tubing vol Kill fluid Vol Pumped in = Tubing vol = 6000x.01458

= 87.48 Bbls= 87.48 Bbls

•Kill fluid height = Kill fluid height = Kill fluid vol / Ann volKill fluid vol / Ann vol = 87.48 / .0252 = 3471 ft

•Completion fluid htCompletion fluid ht = 6000 – 3471 = 2529 ft

•Casing PrCasing Pr when brine at surfacewhen brine at surface

= Formation Pr – Casing Hyd. Pr = 3600 – (3471x.5 +

2529x.6) = 347 = 347 psipsi


GAS OIL PACKER

KILL

IN

OUT

STAGE-4ANN FULL OF KILL FLUID

•Tubing Pr when kill fluid enters tubingTubing Pr when kill fluid enters tubing = Formation Pr – Tubing Hyd. Pr = 6000x.6 – 6000x.6

= 0 psi= 0 psi

•Kill Fluid Vol Pumped in = Annulus Vol Kill Fluid Vol Pumped in = Annulus Vol = 6000x.0252

= 151.2 Bbls= 151.2 Bbls

•Casing PrCasing Pr when kill fluid enters tubingwhen kill fluid enters tubing = Formation Pr – Casing Hyd. Pr = 3600 – 6000x.5

= 600 psi= 600 psi


VOLUME PUMPED

PRESSURE

Gas is out

Oil is out

INITIAL STAGE GAS OUT OIL OUT ANN FULL OF KILL FLUID

GAS OIL PACKER

KILL

29.16 Bbls Gas Volume

87.48 Bbls Tubing Volume

151.2 Bbls Annulus Volume

(1) (4)(3)(2)

TUBING PRESSURETUBING PRESSURE

CASING PRESSURECASING PRESSURE

2000 psi

880 psi 600 psi

Kill fluid is lighter than packer fluidKill fluid is lighter than packer fluid


EXERCISE

INITIAL STAGE GAS OUT OIL OUT(A) (C)(B)

VOLUME PUMPED

PRESSURE

Gas is out

Oil is out

29.16 Bbls Gas Volume

87.28 Bbls Tubing Volume

(A)

(B)

2000 psi

880 psi

(C)

TUBING PRESSURE GRAPHTUBING PRESSURE GRAPH(REVERSE CIRCULATION)

Using reverse circulation well kill exercise, complete attached step down chart for every 6 bbls pumped during the phase when the gas is going out (A-B).

•Tubing Pressure (Initially) = 2000 psi •Tubing Pressure (After gas is out) = 880 psi

•Pressure DropPressure Drop (while gas goes out) = 2000 - 880 = = 1120 psi 1120 psi

•Volume PumpedVolume Pumped (while gas goes out) = 2000 x .01458 = = 29.16 Bbls 29.16 Bbls

•Tubing Pressure Drop in 29.16 BblsTubing Pressure Drop in 29.16 Bbls = 1120 psi

•Tubing Pressure Drop per 6 BblsTubing Pressure Drop per 6 Bbls = 1120 x 6 / 29.16

= 230 = 230

psi per 6 Bblspsi per 6 Bbls

STEP-DOWN CHART (WHEN GAS IS GOING OUT)

EXERCISE CONTD.

Volume PumpedVolume Pumped

(bbls)(bbls)THPTHP(psi)(psi)

00 20002000

66 2000 - 230 = 17702000 - 230 = 1770

1212 1770 - 230 = 15401770 - 230 = 1540

1818 1540 - 230 = 13101540 - 230 = 1310

2424 1310 - 230 = 10801310 - 230 = 1080

29.1629.16 880880

STEP DOWN CHART(FOR REVERSE KILL EXERCISE – STAGE A to B)(FOR REVERSE KILL EXERCISE – STAGE A to B)

EXERCISE CONTD.

In a planned well kill operation, which is the most In a planned well kill operation, which is the most appropriate kill mehtod?appropriate kill mehtod?

a. Concurrent

b. Reverse circulation

c. Wait and Weight

d. Forward circulation

e. Volumetric

QUESTIONS…

Which of the following are the main advantage of a reverse circulation kill? (4 answers)

a. Surface pressures remain lower*

b. Less risk of formation damage

c. It is slow

d. Wire line work is involved

e. Debris can plug the formation

f. The tubing and annulus end up with clean kill fluid

g. All wells can normally be killed with this method

QUESTIONS…

A live production well has a lot of sand and scale in the casing below the perforations. There are several hundred feet of perforations having different pressure zones. A workstring is to be run through the completion to clean the well to TD.

Which of the following statements are true? (2 Answers)

a. The thief zone(s) may stop proper circulation back to surface

b. Reverse circulation is best when there is a thief zone*

c. A high pump rate will be required to overcome losses into thief zones

d. It may be necessary to use a fluid containing LCM (lost circulation

material), such as sized salt particles, to stop the losses into thief zone

e. The circulation system will have to permit pumping down the workstring/completion annulus and the completion/casing annulus at the

same time to have enough flow rate to overcome any losses into the thief

zone(s)

QUESTIONS…

A producing oil well has been shut in and the SSD is to be opened A producing oil well has been shut in and the SSD is to be opened before killing the well. Calculate the differential pressure that exists before killing the well. Calculate the differential pressure that exists across the sleeve before it is opened.across the sleeve before it is opened.

Tubing shoe 11350 ft. MD 8750 ft. TVDPacker depth 11000 ft. MD 8600 ft. TVDSSD depth 10950 ft. MD 8550 ft. TVDCompletion fluid density 9.0 ppgOil density 6.8 ppgSIWHP 1000 psi

a. The tubing and annulus are in balanceb. There is 22 psi more in tubing than the annulusc. There is 22 psi more in annulus than the tubingd. There is 300 psi more in tubing than the annuluse. There is 300 psi more in annulus than the tubing

Annulus Hydrostatic pressure = .052 x 8550 x 9 = 4001.4 psi

Tubing Hydrostatic pressure =.052 x 8550 x 6.8 + 1000 = 4023.28psi

Differential pressure = 4023.28- 4001.4 =

21.88 psi (22 psi more in tubing)

QUESTIONS…

Given the following data, calculate the time required to Given the following data, calculate the time required to pump bottoms up, for reverse circulation.pump bottoms up, for reverse circulation.

DATA:

Tubing depth - 9,250 ft MD, 8,600 ft TVD.Tubing capacity - 0.0025 bbl/ftAnnular capacity - 0.0052 bbl/ftPump rate - 0.75 bpm

a. 29 min b. 31 min c. 60 min d. 64 min e. 88 min f. 95 min

QUESTIONS…

Volume = Tubing volume Volume = Tubing volume

= 9250 x 0.0025= 9250 x 0.0025 = 23.12 bbls = 23.12 bbls

Time Time = Volume / Pump rate= Volume / Pump rate

= 23.12 / 0.75= 23.12 / 0.75 = 31 minutes= 31 minutes

The well in the schematic is vertical and has a constant ID/OD. Friction pressure losses and any fluid losses to the formation are ignored. An overbalance of 200 psi is held over formation pressure at all times during the well kill.Using the following data and reverse circulation kill graph, answer the questions below.

Tubing Data : Size 3 ½” inWeight 10.3 lbs/ft.Capacity = 0.0083 bbl/ft

Casing Data: Size 7 inWeight 29 lbs/ftAnnulus Capacity = 0.0252 bbl/ft

GradientsBrine in annulus = 0.49 psi/ft Kill fluid = 0.52 psi/ft Gas in tubing = 0.12 psi/ftOil in tubing/casing = 0.35 psi/ftFormation Gradient = 0.48 psi/ft

Pump out put = 0.0899 bbl/strokeSITHP = 1965 psi SICHP = 0 psiTransition from gas to oil = 4000 ft Packer depth = 7500 ftSliding Side Door depth = 7450 ft Top of perforation = 7700 ft

GAS OIL BRINE

KILL

IN

THP = 1965 psi

CHP = 0 psi

SSD @ 7450 ft

Gas/Oil Contact @ 4000 ft

DHSV @ 1800 ft

Top of Perf @ 7700 ft

PACKER @ 7500 ft

BRINE = 0.49 psi/ft

Form Grad = 0.48 psi/ft

OIL = 0.35 psi/ft

GAS = 0.12 psi/ft

KILL = 0.52 psi/ft

QUESTIONS….

FIGURE (A) FIGURE (D)FIGURE (B) FIGURE (E)FIGURE (C) INITIAL STAGE GAS OUT OIL OUT KILL FLUID HEAVIER ANNULUS

FULL THAN BRINE BY 200 psi OF KILL FLUID (Casing pr down from 200 to 0)

GAS OIL BRINE

KILL

IN

THP = 1965 psi

CHP = 0

SSD @ 7450 ft

Gas/Oil Contact @ 4000 ft

DHSV @ 1800 ft

Top of Perf @ 7700 ft

PACKER @ 7500 ft

BRINE = 0.49 psi/ft

Form Grad = 0.48 psi/ft

OIL = 0.35 psi/ft

GAS = 0.12 psi/ft

KILL = 0.52 psi/ft

REVERSE CIRCULATION – DIFFERENT STAGESREVERSE CIRCULATION – DIFFERENT STAGES

200 psi overbalance is held200 psi overbalance is held

Kill fluid is heavier than Kill fluid is heavier than brinebrine

PositionPosition AA BB CC DD EE FFVolume pumped (bbls) 00 3333 6262 170170 188188 250250

THP (psi) 21652165 685685 200200 200200 200200 00

CHP (psi) 200200 162162 128128 00 00 00

TOTAL VOLUME PUMPED (Bbls)

PRESSURE

Gas is out

Oil is out

(A)

(D)(C)

(B)

TUBING PRESSURETUBING PRESSURE

CASING PRESSURECASING PRESSURE

2165 psi

(E)

(F)(psi)

Annulus full of kill fluid

Kill fluid heavier than brine by 200 psi

6.(a) How much kill fluid must be pumped into annulus to circulate all gas out from the well?

6.(b) What is the Bottom Hole Pressure at annulus side of SSD before start of the kill operation? ?

6.(c) If the THP were kept at 100 psi instead of 200 psi from point C to point E which of the following is true ?

a. The well is still overbalanced, but the overbalance is smaller than before.b. The well is now in balance.c. The well is now underbalanced.d. The well is still overbalanced, but the overbalance is greater than before.

6.(d) After pumping 62 bbls, the THP stabilizes at 200 psi (point C). This pressure remains constant until point E. What is the reason for this?a. The fluid level in the tubing has fallen.b. The choke size remains unchanged while the oil is exiting the well.c. Tubing stays filled with brine and there is no change in hydrostatic pressure in tubing.d. The gas is exiting the well and has stopped expanding further.

6.(e) What is the annulus volume between surface and sliding side door?

6.(f) Find pressure at annulus side of SSD at point B during the kill operation ?

QUESTIONS….

= Gas volume = 4000 x 0.0083 = 33.2 bbl (Volume at B)= Gas volume = 4000 x 0.0083 = 33.2 bbl (Volume at B)

= Annulus volume = 7450 x 0.0252 = 187.7 bbl (Volume at E)= Annulus volume = 7450 x 0.0252 = 187.7 bbl (Volume at E)

= BHP before start of well killing + overbalance = 3650.5 + 200 = 3850.5 psi = BHP before start of well killing + overbalance = 3650.5 + 200 = 3850.5 psi (This BHP is kept constant during the well killing operation.)(This BHP is kept constant during the well killing operation.)

= Hydrostatic pressure of brine = 0.49 x 7450 = 3650.5 psi= Hydrostatic pressure of brine = 0.49 x 7450 = 3650.5 psi

Figure below shows a reverse circulation kill graph that has been Figure below shows a reverse circulation kill graph that has been

generated for a constant ID/OD tubing containing gas and oil with a generated for a constant ID/OD tubing containing gas and oil with a

heavy completion fluidheavy completion fluid in the annulus. The kill fluid is lighter density in the annulus. The kill fluid is lighter density

than the fluid installed in the annulus on than the fluid installed in the annulus on completion.completion.

VOLUME PUMPED (bbls)

PRESSURE

Annulus full of Kill fluid

Oil is out

Tubing pressure Casing pressure

284 500

(B)

(D)

(A)

(E)

(F)(C)

2367

0

571 psi

700389 1200

800 psi

(psi)

QUESTIONS…QUESTIONS…

INITIAL GAS GOING OUT OIL OUT KILL ENTERS TBG KILL AT SURFACE

GAS OIL PACKER

KILL

((Completion fluid is heavierCompletion fluid is heavier))

(A) (F) (D) (B) (E)


PRESSURE


Oil is out

Tubing pressure

Casing pressure

284 500

(B)

(D)

(A)

(E)

(F)(C)

2367

0

571 psi

700389 1200

(psi)

Casing Pressure is maximum as annulus is

lightest at this point800 psi

1.(a) What is the annulus volume?

1.(b) What would the annulus pressure after pumping 700 bbls of kill fluid?

1.(c) At what point does the hydrostatic pressure of the fluid in the tubing equal formation pore pressure?

a. A b. B c. C b. D e. E f. F

1.(d) At what point annulus is full of kill brine & tubing full of completion brine?a. A b. B c. C

d. D e. E f. F

Q. NO. - 1Q. NO. - 1

= Volume at E (when annulus is full of kill fluid) = 700 bbls= Volume at E (when annulus is full of kill fluid) = 700 bbls


PRESSURE


Oil is out

Tubing pressure Casing pressure

284 389 700

(B) (D)

(A)

(E) (F)(C)

Casing Pressure is maximum now as annulus

is lightest at this point

500 1200

(psi)

2367 psi

571 psi

800 psi

= 800 psi= 800 psi

At B (when tubing pressure =0 At B (when tubing pressure =0 psi)psi)

At E (when casing pressure is max)At E (when casing pressure is max)

BULLHEADING

GAS OIL PACKER

KILL

IN Method involves pumping kill fluid

directly into tubing to force tubing contents back into formation.

BULL HEADINGBULL HEADING

GAS OIL PACKER

KILL

IN

OIL PUMPED BACK INTO FORMATION

Preferred when reverse circulation is not possible.

Used only if it does not causes any appreciable damage to formation.

Cannot be used if there is blockage or tight formation preventing bull heading.


GAS OIL PACKER

KILL

IN

ALL TUBING FLUID PUMPED BACK INTO FORMATION

Calculation must be made for Max allowable surface pressure and tubing burst pressure.

Pump rates must be restricted to keep pressure below fracture point.


BULLHEADINGBULLHEADING

ADVANTAGES Quick and easy method especially in smaller tubing sizes.

No hydrocarbons brought to surface which avoids segregation & handling.

DISADVANTAGES Scales or contaminants in the tubing are pumped in the formations.

Low formation fracture pressures may be exceeded causing accidental fractures.

Gas may slip up the tubing if the pump rate is not sufficient.

VOLUME TO BE PUMPEDVOLUME TO BE PUMPED

On wells susceptible to formation damage by kill fluid, only tubing volume (plus rat hole to perfs) should be pumped.

Tubing may not be completely dead due to some gas still remaining due to channeling but pressure are greatly reduced and subsequent circulation is simplified.*

On other wells, tubing may be over displaced to achieve more certain kill (especially if zone is being abandoned)

BULLHEADINGBULLHEADING

BULLHEADING

KILL GRAPH

INFORMATION REQUIREDINFORMATION REQUIRED1. Maximum Allowable INITIAL Tubing pressure* (At pump startup)

2. Maximum Allowable FINAL Tubing pressure (At end of Bull head)

3. Minimum Initial tubing pressure (to balance formation pressure)

4. Minimum Final tubing pressure (to balance formation pressure)

5. Tubing volume required to bullhead

BULL HEADING KILL GRAPHBULL HEADING KILL GRAPH

= Fracture pressure – Initial Tubing hydrostatic pressure

= Fracture pressure – Final Tubing hydrostatic pressure

= SITHP

= 0 psi

VOLUME PUMPED (Bbls)

(psi)

Minimum Allowable Minimum Allowable Tubing Tubing

Pressure Pressure (to (to avoid influx)avoid influx) GAS

OIL PACKER

KILL

Tubing Volume

(A) (A)

(A)

IN IN

Maximum Allowable Maximum Allowable Tubing PressureTubing Pressure**

(to avoid fracture) (to avoid fracture)

(B)

(A)

(B)

(B)

Tubing Burst LimitTubing Burst Limit

BULLHEADING KILL GRAPH

Tubing Surface

Pressure

LUBRICATE & BLEED

LUBRICATE & BLEEDLUBRICATE & BLEED

GAS OIL PACKER

KILL


ALTERNATE CYCLINGALTERNATE CYCLING KILL FLUID PUMPED IN KILL FLUID PUMPED IN

GAS BLED OUT GAS BLED OUT Lubrication & Bleeding involves pumping kill fluid into tubing, allowing it to lubricate* lubricate* down and bleeding gas out through choke. Used when it is not possible to conduct both methods - Reverse Circ & Bullheading (e.g. due to obstruction in tubing, wire line cannot be lowered to open communication and there is blockage/ tight formation preventing bullheading).

GAS OIL PACKER

KILL

ALTERNATE CYCLING IN AND OUT



It is important to install a wire line set plug below packer to isolate formation from completion & kill fluid.

If plug is not installIf plug is not install, care must be taken not to cross MASP and Min allowable surface pressure line on kill graph.

The process is repeated several times till gas is out and tubing pressure becomes 0

VOLUME PUMPED

Tubing Surface

PressureMinimum Minimum Surface PressureSurface Pressure

(to prevent influx)

GAS OIL PACKER

KILL

(A)

IN IN

MASPMASP

(B)


Reduction in THP & MASP Reduction in THP & MASP (each bbl pumped)(each bbl pumped)

= .052 x Kill Fluid Wt / Tubing Capacity= .052 x Kill Fluid Wt / Tubing Capacity

(Plug not install(Plug not install)

SITHP

During an intervention operation it becomes necessary to During an intervention operation it becomes necessary to kill the well. Which is the most appropriate kill method?kill the well. Which is the most appropriate kill method?

a. Volumetric

b. Forward circulation

c. Wait and Weight

d. Bull heading

e. Concurrent

QUESTIONS..QUESTIONS..

Which of the following determine whether it is Which of the following determine whether it is possible to bullhead? possible to bullhead?

(2 Answers)

a. Rated working pressure of the surface equipment

b. Completion tubing collapse pressure

c. Blind ram position

d. Formation permeability

e. Type of tool string in use


Which of the following statements about bull heading Which of the following statements about bull heading are ture?are ture?

(2 Answers)

a. Can only be done if the perforations are open

b. Can be done before the intervention work start when there is a two way check valve in the tubing hanger*

c. Can possibly plug the formation

d. Is normally done in preference to opening the SSD*

e. Is more difficult to perform than the bleed and lubricate method


In which of the following situations in bull In which of the following situations in bull heading most likely to be used to kill the well? heading most likely to be used to kill the well? (3 answers)

a) A well with a failed DHSV that cannot be pulled using wire line

b) Where speed is importantc) Where there is not enough information to calculate a reverse

circulation kill*d) Where there is a risk of formation damagee) A well with a packer setting plug stuck in the tailpipe*


In a production well to be killed by bull heading, which of In a production well to be killed by bull heading, which of the following limit the Maximum Surface Pressure^? the following limit the Maximum Surface Pressure^?

(2 Answers)

a. ID of completion tubing

b. Existing Maximum Closed in Tubing Head Pressure*

c. The possible fracture of the formation

d. The burst limit of completion equipment

e. The maximum available pump rate*


A live well is to be killed by bull heading. Which of these A live well is to be killed by bull heading. Which of these factors limit the maximum allowable surface pressure? factors limit the maximum allowable surface pressure?

(3 answers)(3 answers) a. Completion size

b. Maximum pump speed

c. SIWHP

d. Maximum safe working pressure of the surface equipment

e. Completion burst limits

f. DHSV operating pressure

g. Possible formation fracture


In an emergency situation where it is not possible to In an emergency situation where it is not possible to bullhead, what would be most appropriate kill method?bullhead, what would be most appropriate kill method?

a. Volumetric

b. Forward circulation

c. Wait and Weight

d. Lubricate and bleed

e. Concurrent


In which of the following would bull heading be more likely to In which of the following would bull heading be more likely to be used than bleed and lubricate? be used than bleed and lubricate?

(2 Answers)

a.* A well that has stopped flowing because of sand and scale in wellbore

b.* A well with a packer setting plug stuck in the tailpipe

c. A well with an SSD that is stuck closed

d. A well with the DHSV stuck in the open position

e.* A well with severely collapsed casing just above the perforations


Convert following density values to fluid gradients (psi/ft)?Convert following density values to fluid gradients (psi/ft)?

a. 10 ppg

b. 9 ppg

c. 12 ppg

d. 2 ppg

Solution :

a. 0.052 x 10 = 0.52 psi/ft

b. 0.052 x 9 = 0.468 psi/ft

c. 0.052 x 12 = 0.624 psi/ft

d. 0.052 x 2 = 0.104 psi/ft

P&P ASSIGNMENT – 1 P&P ASSIGNMENT – 1 Q. NO. - 1Q. NO. - 1

Convert following specific gravity values to fluid gradients Convert following specific gravity values to fluid gradients (psi/ft)?(psi/ft)?

a. 0.85 sp. gr.

b. 1.1 sp. gr.

c. 0.25 sp. gr.

Solution :

a. 0.85 x 0.433 = 0.368 psi/ft

b. 1.1 x 0.433 = 0.476 psi/ft

c. 0.25 x 0.433 = 0.108 psi/ft


Convert following gradient values to density (lb/gal)?Convert following gradient values to density (lb/gal)?

a. 0.35 psi/ft

b. 0.5 psi/ft

c. 0.6 psi/ft.

Solution :

a. 0.35 /0.052 = 6.73 lb/gal

b. 0.5 / 0.052 = 9.61 lb/gal

c. 0.6 / 0.052 = 11.53 ib/gal


Calculate the specific gravity of following fluids?Calculate the specific gravity of following fluids?a. 25° API oil

b. 40° API oil

c. 35° API OBM (oil base mud)

d. 12 lb/gal brine

e. 10 lb/gal brine

Solution :

a. 141.5/(131.5+25) = 0.90

b. 141.5/(131.5+40) = 0.83

c. 141.5/(131.5+35) = 0.85

d. 12/8.33 = 1.44

e. 10/8.33 = 1.20


Calculate the following pressure values to density (lb/bbl)?Calculate the following pressure values to density (lb/bbl)?a. 3450 psi at 8000 ft

b. 5000 psi at 10000 ft

c. 6000 psi at 11000 ft

d. 4500 psi at 12000 ft MD/10000 ft TVD

e. 3000 psi at 7000 ft MD/8500 ft TVD

Solution :

a. 3450/8000 = 0.431

b. 5000/10000 = 0.50

c. 6000/11000 = 0.545

d. 4500/10000 = 0.45

e. 3000/7000 = 0.428


Calculate the hydrostatic pressure of following fluids ?Calculate the hydrostatic pressure of following fluids ?a. 5000 ft of brine having density of 10 lb/gal

b. 40° API oil to 10000 ft

c. 35° API OBM to 8000 ft

d. 10000 ft of 0.38 psi/ft oil

e. 12 lb/gal brine at 8000 ft MD/6000 ft TVD

Solution :

a. 0.052 x10 x5000 = 5200 psi

b. Change API gravity to sp. gr. # 141.5/(131.5+40) = 0.825 sp. gr.

0.825 x 8.33 = 6.87 lb/gal, 0.052 x 6.87 x 10000 = 3572 psi

c. Change API gravity to sp. gr. # 141.5/(131.5+35) = 0.849 sp. gr.

0.849 x 8.33 = 7.07 lb/gal, 0.052 x 7.07 x 10000 = 2941 psi

d. 0.38 x 10000 = 3800 psi

e. 0.052 x 12 x 6000 = 3744 psi


Calculate the bottom hole pressure for following?Calculate the bottom hole pressure for following?a. Depth of perforation – 10000 ft

35° API oil up to surface, SITHP – 1000 psi

b. Depth of perforation – 10000 ft

35° API oil up to 6000 ft, 0.05 psi/ft gas to surface

SITHP – 1000 psi

Solution :

a. First calculate sp. gr. of oil # 141.5 / (131.5+35) =0.849

Now calculate hyd. pr. of oil # 0.849 x 0.433 x 10000 = 3676 psi

Bottom Hole Pressure = 3676 + SITHP = 3676+1000 = 4676 psi

b. First calculate sp. gr. of oil # 141.5 / (131.5+35) =0.849

Now calculate Height of oil = 10000-6000=4000

Now calculate hyd. pr. of oil # 0.849 x 0.433 x 4000 = 1470 psi

Now calculate hyd. pr. of gas # 0.05 x 6000 = 300 psi

Bottom Hole Pressure = hyd.+ SITHP = 1470 +300+1000 = 2770 psi


Well Information is as below :Well Information is as below :Well TVD – 10000 ft

XN Nipple – 9700 ft TVD

Packer – 9500 ft TVD

SSD – 9450 ft TVD

SITHP – 1000 psi

The well has 10 ppg brine in the annulus. The tubing is filled with 30° API oil to 4000 & 0.04 psi/ft gas up to surface

a. Calculate the differential pressure between annulus & tubing at SSD

b. Before opening SSD, what should be done to SITHP

Solution :

a. First calculate Hyd. Pr. at SSD in annulus # 0.052 x 10 x 9450 = 4914 psi

Now calculate hyd. pr. of tubing # SITHP +hyd. of gas +hyd. of oil

=1000+(0.004 x 4000)+(0.876 x 0.433 x 5450)=1000 +160+2068 = 3228 psi

Differential Pressure at SSD = 4914-3228 = 1686 psi

b. First place a plug in the XN nipple & then pressurize the tubing upto

2686 psi (SITHP + Differential pressure)


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