slide1
Download
Skip this Video
Download Presentation
Well Control Principles

Loading in 2 Seconds...

play fullscreen
1 / 196

Well Control Principles - PowerPoint PPT Presentation


  • 101 Views
  • Uploaded on

Well Control Principles. Well Control Principles. Primary Well Control Secondary Well Control Tertiary Well Control Hydrostatic Pressure Formation Pressure Porosity And Permeability Kill Mud Density Indications of Increasing Formation Pressure. Well Control Principles.

loader
I am the owner, or an agent authorized to act on behalf of the owner, of the copyrighted work described.
capcha
Download Presentation

PowerPoint Slideshow about ' Well Control Principles' - nita


An Image/Link below is provided (as is) to download presentation

Download Policy: Content on the Website is provided to you AS IS for your information and personal use and may not be sold / licensed / shared on other websites without getting consent from its author.While downloading, if for some reason you are not able to download a presentation, the publisher may have deleted the file from their server.


- - - - - - - - - - - - - - - - - - - - - - - - - - E N D - - - - - - - - - - - - - - - - - - - - - - - - - -
Presentation Transcript
slide1

Well Control

Principles

slide2

Well Control Principles

  • Primary Well Control
  • Secondary Well Control
  • Tertiary Well Control
  • Hydrostatic Pressure
  • Formation Pressure
  • Porosity And Permeability
  • Kill Mud Density
  • Indications of Increasing Formation Pressure
slide3

Well Control Principles

  • The function of Well Control can be subdivided into 3 main categories:
    • Primary Well Control: is the use of the fluid to prevent the influx of formation fluid into the well bore.
    • Secondary Well Control: is the use of the BOP to control the well if Primary WC can not be maintained.
    • Tertiary Well Control: squeeze back, cement ...
slide4

The Well is Balanced:

when Hydrostatic Pressure = Formation Pressure

slide5

The Well is Under Balanced:

when Hydrostatic Pressure < Formation Pressure

slide6

The Well is Over Balanced:

when Hydrostatic Pressure > Formation Pressure

slide7

Hydrostatic Pressure

Because the pressure is measured in psi and depth is measured in feet, it is convenient to convert Mud Weight from ppg to a pressure gradient in psi/ft.

The conversion factor is 0.052

Fluid Density (ppg) x 0.052 = Pressure gradient (psi/ft)

Hydrostatic Pressure is the pressure exerted by a column of fluid at rest, and is calculated by multiplying the gradient of the fluid by the True Vertical Depth at which the pressure is being measured:

Fluid gradient (psi/ft) x TVD = Hyd. Pressure(psi)

slide8

T V D

You have to consider the vertical height or depth of the fluid column, the shape of the hole doesn’t matter.

slide9

Normal Formation Pressure

Normal formation pressure is equal to the hydrostatic pressure of the water occupying the pore spaces from the surface to the subsurface formation.

Native fluid is mainly dependent on its salinity and is often considered to be: 0.465 psi/ft

slide10

Abnormal Formation Pressure

Abnormal formation pressures are any formation pressures that are greater than the hydrostatic pressure of the water occupying the pore spaces.

Commonly caused by the under-compaction of shale’s, clay-stone or faulting...

slide11

Subnormal Pressure: is defined as any formation pressure that is less than “normal” pressure.

It can be due to reservoir depletion,fault …

Transition Zone: is the formation in which the pressure gradient begins to change from a normal gradient to a subnormal gradient or, more usually, to an abnormal gradient.

slide12

UNDERCOMPACTED SHALES / SAND.

UNCONSOLIDATED

SHALE-DENSITY INCREASES WITH DEPTH - WATER ESCAPES

SAND WITH COMMUNICATION TO SURFACE

SHALE-DENSITY DECREASES WITH DEPTH-WATER ENCLOSED

ENCLOSED SAND LENS WITH FORMATION FLUID

slide13

GAS CAP

NORMAL FORMATION

PRESSURE ABOVE CAP

ROCK =0.465 PSI/FT

Ph

Pabnormal = Pf-Pg

Pf

Pg

GAS PRESSURE

GRADIENT = 0.1 PSI/FT

COMMUNICATION BETWEEN FLUID AND GAS

slide16

ARTESIAN WELL

NORMAL FORMATION

PRESSURE AT THE WELL

UNTILL BELOW THE CAP

ROCK

LAKE

HYDROSTATIC

PRESSURE

FROM

FORMATION

WATER

COLUMN

POROUS SANDSTONE

BELOW CAP ROCK

slide17

SURFACE EROSION

ENCLOSED FORMATION

LEVEL CHANGE

H1

H3

Pf

H2

Pf

Pf

slide18

Porosity & Permeability

The essential properties of reservoir rocks are:

- Their porosity and permeability.

Theporosity provides the storage space for fluids and gases and is

the ratio of the pore spaces in the rock to the bulk volume of the rock.

This is expressed as a percentage. Reservoir rocks commonly have

porosity’s ranging from 5% to 30%.

Formation permeability is a measure of how easy the fluid will flow

through the rock. Permeability is expressed in Darcys, from a few

milliDarcys to several Darcys.

These properties will determine how much and how quick a kick will enter into the well. Kicks will enter a wellbore faster from rocks having high permeability.

slide19

Tiny openings in rock are pores Porosity

Pores are connected for the Permeability

slide20

Formation Pressure

When the well is shut in, Formation Pressure can be found with the following formula:

SIDPP + Hydrostatic pressure = Formation Pressure

SICP + Influx Hyd + Mud Hyd = Formation Pressure

SICP

+

Mud Hydrostatic

+

Influx Hydrostatic

=

SIDPP

+

Mud Hydrostatic

=

Formation Pressure

slide22

POSITIVE KICK SIGNS

Positive Indications of a kick:

- Flow from Well (pumps off)

- Increase in Flow from Well (pumps on)

- Pit Volume Gain

slide23

KICKS WHILE TRIPPING

Incorrect Fill or Return Volumes

- Swabbing

- Surging

If any deviation, the FIRST action will be to install a fully open safety valve and make a Flow-Check.

Remember: It is possible that the well will not flow even if an influx has been swabbed in.

slide24

KICKS WHILE DRILLING

Early Warning Signs

That the well MIGHTbe going under-balanced

slide25

Indications of Increasing Formation Pressure

  • Increase in Drilling Rate
  • Change in D - Exponent
  • Change in Cutting size and shape
  • Increase in Torque and Drag
  • Chloride Trends
  • Decrease in Shale Density
  • Temperature Measurements
  • Gas Cut Mud
  • Connection Gas
slide26

ROP

Depth

Increase in Drilling Rate:

While drilling normally pressured shale and assuming a fairly constant bit weight, RPM, and hydraulic program, a normal decrease in penetration rate can be expected. When abnormal pressure is encountered, differential pressure and shale density are decreased causing a gradual increase in penetration rate.

slide27

Torque

Depth

Increase in Torque and Drag

Increase in torque and drag often occurs when drilling under balanced through some shale intervals.

There is a build up of cuttings in the annulus and this may be a sign that pore pressure is increasing.

slide28

“d”

Depth

Change in “d” Exponent:

“d” is an indication of drill ability and ROP, RPM, WOB, bit size are used to calculate its value.

Trends of “d” normally increase with depth, but in transition zones, it may decrease with lower than expected value.

slide29

Change in cutting size and shape

Normally pressured shale: cuttings are small with rounded edges, generally flat.

Abnormally pressured shale: cutting are long and splintery with angular edges.

As differential between the pore pressure and bottom pressure is reduced, the cuttings have a tendency to “explode” of bottom.

slide30

Chloride

Depth

Chloride Trends:

The chloride content of the mud filtrate can be monitored both going into and coming out of the hole.

A comparison of chloride trends can provide a warning or confirmation signal of increasing pore pressure.

slide31

Shale

Density

Depth

Decrease in Shale Density:

Shale density normally increases with depth but decreases as abnormal pressure zones are drilled.

When first deposited, shale has a high porosity. During normal compaction, a gradual reduction in porosity occurs with an increase of the overlaying sediments.

slide32

Temp.

Depth

Temperature Measurements:

The temperature gradient in abnormally pressured formations is generally higher than normal.

slide33

Gas Cut Mud

The presence of gas cut mud does not indicate that the well is kicking ( gas may have been entrained in the cutting ). However, the presence of gas cut mud must be treated as an early warning sign of a potential kick.

- Gas cut mud only slightly reduces mud column pressure, when it is close to surface.

- Drilled cuttings from which the gas comes may compensate for the decrease.

slide34

Connection Gas

Connection gas are detected at the surface as a distinct increase above the background gas, as bottom up is circulated after a connection.

Connection gases may indicate a condition of near balance.

If connection gas is present, limiting its volume by controlling the drilling rate should be considered.

slide36

Objectives

  • Identify the different pressures losses in the system
  • Identify which one influence bottom hole pressure
  • Convert this pressure to an equivalent mud weight
mud system pressure losses

100 psi

0 psi

100 psi

Mud System Pressure Losses
  • Pumping through a pipe with a mud pump at 80 spm, with gauges mounted on the discharge of the pump and at the end of the pipe.
  • The gauge on the pump reads 100 psi.
  • The gauge on the end of the pipe reads 0 psi.
  • It can be assumed from this information that the 100 psi drop in pressure through the pipe is the result of friction losses in the pipe as the fluid is pumped through it.

80 SPM

slide38

500 psi

400 psi

100 psi

400 psi

0 psi

Mud System Pressure Losses

80 SPM

slide39

Mud System Pressure Losses

1000 psi

900 psi

100 psi

80 SPM

400 psi

500 psi

500 psi

0 psi

slide40

2300 psi

2200 psi

100 psi

400 psi

1800 psi

500 psi

1300 psi

1300 psi

Mud System Pressure Losses

80 SPM

0 psi

slide41

Mud System Pressure Losses

2600 psi

2500 psi

0 psi

100 psi

80 SPM

Annular

Pressure

Losses

400 psi

300 psi

2100 psi

500 psi

1600 psi

1300 psi

300 psi

apl example

MUD WT = 10 ppg

10,000 ft TVD

Mud System Pressure Losses

APLEXAMPLE

0 psi

0 psi

0 psi

  • A well has been drilled to10,000 ft.
  • The mud weight is 10 ppg.
  • To find our Hydrostatic pressure we use the following formula;
  • Mud Wt x 0.052 x TVD 10 x 0.052 x 10,000 = 5,200psi.
  • The gauge on the drawing shows bottom hole hydrostatic pressure.

0 SPM

0 psi

0 psi

5200 psi

apl example1

2600 psi

2500 psi

100 psi

0 psi

MUD WT = 10 ppg

400 psi

10,000 ft TVD

300 psi

2100 psi

500 psi

1600 psi

1300 psi

5500 psi

Mud System Pressure Losses

APL EXAMPLE
  • If we now start to circulate at 80 spm through our system with the same pressure losses as before.
  • As you can see from this example the bottom hole pressure has increased by 300 psi.
  • This increase is due to the Annular Pressure Losses (APL) acting down on the bottom of the well and is usually called “Bottom Hole Circulating Pressure” (BHCP)

80 SPM

equivalent circulating density
The APL while circulating has the same effect on bottom hole pressure as increasing the mud weight.

This theoretical increase in mud weight is called the Equivalent Circulating Density or Equivalent Mud Weight.

It can be calculated by using the following formula:

_____APL(psi) __ + Original Mud Weight

TVD x 0.052

Equivalent Circulating Density
slide45

Summary:

  • Annular Pressure Losses are the pressure losses caused by the flow of fluid up the annulus and are the only losses in the system that affect BHP.
  • Equivalent Circulating Density is the effective density at any depth created by the sum of the total hydrostatic plus the APL.
slide46

300 psi

600 psi

450 psi

800 psi

1200 psi

Exercise

- Pressure Gradient?

- Hydrostatic Pressure?

- Pump Pressure @ 40 spm?

- A P L?

- ECD at 40 SPM?

40 SPM

MUD WT = 12 ppg

MD = 9,550 ft

TVD = 8,000 ft

mud weight change
MUD WEIGHT CHANGE

2600 psi

  • A well is being drilled using 10 ppg mud. At 80 spm the total circulating system pressure losses are 2600 psi.
  • It is decided to increase the mud weight to 11 ppg.

80 spm

Mud wt 10 ppg

mud weight change1
MUD WEIGHT CHANGE

2860 psi

It is a good drilling practice to calculate the new circulating pressure before changing the mud weight.

The way we calculate this change in pressure is to use the following formula;

New Mud ppg x Old psi.

Old Mud ppg

11 ppg x 2600 = 2860psi

10 ppg

The new pump pressure would be approximately 2860 psi.

80 spm

Mud wt 11 ppg

final circulating pressure
Final Circulating Pressure
  • The formula that was just used to calculate the pressure change due to a change in mud weight, is also the formula used to calculate the Final Circulating Pressure.

Kill Mud wt x Slow circulating rate press .

Old Mud wt

pump stroke change
PUMP STROKE CHANGE

2600 psi

  • A well is being drilled using 10 ppg mud. At 80 spm the total circulating system pressure losses are 2600 psi.
  • It is decided to increase the pump speed from 80 spm to 100 spm.

80 spm

Mud wt 10 ppg

pump stroke change1
PUMP STROKE CHANGE

4063 psi

  • It is a good drilling practice to calculate the new circulating pressure before changing the pump speed.
  • The way we calculate this change in pressure is to use the following formula;
  • New SPM 2 Old psi x Old SPM
  • 2600 x 100 spm 2 80 spm = 4063 psi
  • The new pump pressure would be approximately 4063 psi.

100 spm

Mud wt 10 ppg

slide53

Preparation

and

Prevention

slide54

Preparation and Prevention

  • Barite and Mud chemical stocks
  • Equipment line up for shut-in
  • Slow circulating rates
  • M A A S P
  • Well Control Drills
  • Flow Checks
  • Safety Valves and Float Valves
slide55

LINE UP FOR

HARD SHUT IN

FLOWPATH

slide56

HARD SHUT IN

1

Pick off bottom and position string

Stop pumps & Rotation

Close BOP (Ram or Annular)

Open hydraulic side outlet valve

Observe pressure

2

3

5

4

1

5

2

4

3

FLOWPATH

slide57

LINE UP FOR

SOFT SHUT IN

FLOWPATH

slide58

SOFT SHUT IN

1

Pick off bottom and position string

Stop pumps & Rotation

Open hydraulic side outlet valve

Close BOP (Ram or Annular)

Close remote hydraulic choke

Observe pressure

2

3

6

5

4

1

5

6

2

3

4

FLOWPATH

slide59

Slow Circulating Rate

  • A Slow Circulating Rate ( SCR) is the reduced circulating pump rate that is used when circulating out a kick.
  • It is called Dynamic Pressure Losses ( PL ) on the kick sheet
well control operations are conducted at reduced circulating rates in order to

Slow Circulating Rate

Well Control Operations are conducted at reduced circulating rates in order to:
  • Minimise Excess of annulus pressure
  • Allows for more controlled choke adjustments
  • Allows for the weighting up and degassing of the mud and disposal of the influx
  • Reduce the chance of choke erosion
  • Reduce risk of over pressuring system if plugging occurs
scr s pressure for each pump will be taken

Slow Circulating Rate

SCR’s pressure for each pump will be taken:
  • If practical, at the beginning of every tour
  • Any time the mud properties are changed
  • When a bit nozzle is changed.
  • When the BHA is changed.
  • As soon as possible after bottoms-up from any trip
  • At least every 1000 feet (305m) of new hole
slide62

Slow Circulating Rate

  • A minimum of 2 (two) circulating rates should be obtained for all pumps.
  • The pressure must be recorded using the gauges that will be used during well kill operations
  • The SCR pressure will be recorded on the IADC report
slide63

Formation Strength Test or LOT

A leak off test (LOT) determines the pressure at which the formation begins to take fluid.

This test is conducted after drilling out about 10 to 15 ft of new hole below the shoe.

Such a test will establish the strength of the formation and the integrity of the cement job at the shoe.

The test pressure should not exceed 70% of the minimum yield of the weakest casing.

slide64

L O T

Use a high pressure, low volume pump (0.25 - 0.5 bbl/min.) such as a cement pump or a test pump using intermittent or continuous method of pumping.

Rig pumps are not suitable to perform leak off tests.

The objective of the above test is not to fracture the formation, but rather to identify the “formation intake pressure”.

This “intake pressure” is identified as that point where a deviation occurs between the trends of the final pump pressure curve and the static pressure curve. Once the formation intake pressure has been reached, further pumping should be avoided.

slide65

L O T

The total pressure applied at the shoe is the sum ofthe surface pressure from the pump and the hydrostatic pressure for the shoe depth.

This total pressure is applied to the formation.

Surface Casing Pressure

+ Hydrostatic Pressure

=

Pressure at Shoe

slide66

L O T

720 psi

720 psi

+

1498 psi

9.6 ppg

3,000’

2218 psi

This total pressure is applied to the formation.

slide67

0 psi

3,000’

2218 psi

M A M W

The Maximum Available Fluid Density (MAMW).

This is the total pressure, represented as fluid density, above which leak off or formation damage may occurs with no pressure on surface.

MAMW = 14.2 ppg

MAMW= 2218

3000 x 0.052

slide68

0 psi

3,000’

2218 psi

Fracture Gradient

The fracture gradient of the formation will be:

Fracture gradient = MAMW x 0.052

Fracture Gradient = 14.2 x 0.052

= 0.7384 psi/ft

therefore:

MAMW = Fracture Gradient / 0.052

slide69

Maximum Allowable Annular Surface pressure

M A A S P

MAASP is defined as the surface pressure which, when added to the hydrostatic pressure of the existing mud column, results in formation breakdown at the weakest point in the well.

This value is based on the Leak Off Test data.

slide70

Write leak off test pressure here

Write mud weight used for the test

Calculate maximum allow mudweight

and Insert here

Calculate current MAASP and insert here

On Kill Sheet

drills
Drills
  • Pit drill
  • Trip drill
  • Abandonement drill
  • Strip drill
slide72

Actions

Upon

Taking a Kick

slide73

Causes for the Loss of Primary Well Control

  • Kick Size and Severity
  • Kick Detection
  • Recording Pressures
  • Drilling With Oil Base Mud
  • Hard Shut-in
  • Soft Shut-in
  • Height and Gradient of a Kick
slide74

Causes for the loss of Primary Well Control

  • Failure to Fill The Hole Properly While Tripping
  • Swabbing / Surging
        • High pulling speed
        • Mud properties
        • Tight annulus clearance
        • Well Geometry
        • Formation Properties
  • Lost Circulation
  • Insufficient Drilling Fluid Density
slide75

Kick Size and Severity

Minimizing kick size is fundamental for the safety of a Well Control operation.Smaller Kicks:Provide lower choke or annulus pressure both upon initial closure and later when the kick is circulated to the choke.

  • ControllableParameters:Youcaninfluenceon:
  • Degree of underbalance Mud Weight
  • Length of reservoir exposed ROP + Kick detection time
  • Time well remains underbalanced Kick detection + shut-in time
  • Wellbore diameter Hole size
  • Non-controllable Parameters
  • Formation permeability and type of influx
slide76

Kick Detection

  • While Drilling:
  • Drilling breaks: They will be flow checked. Circulating B/up is advisable if F/C is negative. Tool pusher must be informed for all.
  • Increase in flow rate: First positive indicator.
  • Increase in pit volume: Positive indicator. Anyone influencing the active system must communicate with the Driller.
  • Variation in Pump speed and Pressure: (“U-tube”)
  • Well flowing during a Connection: ECD to ESD
  • Change of drilling fluid properties: Gas cut or fluid contaminated.
  • While Tripping:
  • Improper fill-up: swabbing or surging
slide77

Shut- in Procedure: HARD SHUT-IN

  • Stop rotation
  • Pick up the drill string to shut-in position (subsea to hang off position)
  • Stop the pump
  • Flow check
  • If the well flows
  • Close BOP
  • Open remote control choke line valve
  • Notify Tool Pusher and OIM
  • Record time, SIDPP, SICP and pit gain
slide78

Shut- in Procedure:SOFT SHUT-IN

  • Stop rotation
  • Pick up the drill string to shut-in position (Subsea to hang off position)
  • Stop the pump
  • Flow check
  • If the well flows
  • Open remote control choke line valve
  • Close BOP
  • Close choke
  • Notify Tool Pusher
  • Record time, SIDPP, SICP and pit gain
close in methods specified by american petroleum institute
Soft close-in procedure

For a soft close-in, a choke is left open at all times other than during a well control operation. The choke line valves are aligned such that a flow path is open through the choking system, with the exception of one choke line valve located near the blow out preventer. When the soft close-in procedure is selected for closing in a well the:

1 choke line valve is opened.

2 Blow out preventer is closed.

3 Choke is closed.

This procedure allows the choke to be closed in such a manner to permit sensitive control and monitoring of casing pressure buildup during closure.

Hard close-in procedure

For a hard close-in, the chokes remain closed at all times other than during a well control operation. The choke line valves are aligned such that a flow path is open through the choking system with the exemption of the choke(s) itself and one choke line valve located near the blow out preventer stack. When the hard close-in procedure is selected for closing in a well, the blow out preventer is closed. If the casing pressure cannot be measured at the well head, the choke line valve is opened with the choke or adjacent high pressure valve remaining closed so that pressure can be measured at the choke manifold. This procedure allows the well to be closed in the shortest possible time, thereby minimising the amount of additional influx of kicking fluid to enter the well bore.

Close-in Methods specified byAmerican Petroleum Institute
slide83

Gas Influx in WBM or in OBM

  • Water Base Mud
  • Easier to detect
  • Higher migration rate
  • Gas stay as a separate phase
  • On bottom bigger kick size
  • Higher casing pressure
  • Expansion:
  • - Slow first then Fast
  • Oil Base Mud
  • More difficult to detect
  • Lower migration rate
  • Gas go into solution
  • On bottom smaller kick size
  • Smaller casing pressure
  • Expansion:
    • - none first then very fast at the bubble point
slide85

Well Kill

Techniques

slide86

Driller’s Method

  • Wait and Weight Method
  • Volumetric Method
slide88

Driller’s Method :1 st Circulation

The original mud weight is used to circulate the influx

- Reset the stroke counter.

- Bring the pump up to kill speed while holding the casing pressure constant.

- Maintain DP pressure constant until the influx is circulated out from the well

BHP

slide89

Driller’s Method :1 st Circulation

The maximum shoe pressure is when the top of the influx reaches the shoe

slide90

Driller’s Method :1 st Circulation

When the influx is passing the casing shoe, the shoe pressure will decrease.

slide91

Driller’s Method :1 st Circulation

When the influx is above the casing shoe, the shoe pressure will remain constant.

slide92

Driller’s Method :1 st Circulation

- Surface casing pressure is increasing as the influx is circulated up the well.

- Pit volume is raising.

slide93

Driller’s Method :1 st Circulation

- The maximum surfacecasing pressure is reached when the top of the influx is at surface.

- It will be the maximum increase in pit level.

slide94

Driller’s Method :1 st Circulation

- As the influx is passing through the choke, the surface casing pressure will decrease.

- The pit volume will decrease.

slide95

Driller’s Method :1 st Circulation

If all the influx is successfully circulated from the well and the pump is stopped,

SIDPP = SICP

slide96

Driller’s Method :2 nd Circulation

- Line up the kill mud.

- Reset the stroke counter.

- Bring the pump up to kill speed while holding the casing pressure constant.

- Reset the stroke counter after pumping the surface line volume.

- Keep the casing pressure constant until KMW reach the bit.

( Or follow the calculated DP pressure drop schedule from ICP to FCP.)

Pit volume has increased due to the weighting material added in the system.

slide97

Driller’s Method :2 nd Circulation

When kill mud enters the annulus, maintain FCP constant until kill mud is at surface.

slide98

First Circulation

Driller’s

Method

Drill Pipe

Driller’s

Method

Casing

slide99

Second Circulation

Driller’s

Method

Drill Pipe

Driller’s

Method

Casing

slide100

Driller’s Method

Advantages:

- Can start circulating right away

- Able to remove influx even if not enough barite on board

- Less chance of gas migration

- Less calculation

Disadvantages:

- Higher surface pressure

- In certain situation, higher shoe pressure

- Two circulation, more time through the choke

slide101

Wait and Weight

-The kill mud weight is used to circulate the influx

-Reset the stroke counter

- Bring the pump up to kill speed while Holding the casing pressure constant.

- Reset the stroke counter after pumping the surface line volume.

-Pump kill mud from surface to bit while following a calculated DP pressure drop schedule.

BHP

slide102

Wait and Weight

When kill mud enters the annulus, maintain FCP constant until kill mud is at surface.

slide103

One Circulation Only

Wait

&

Weight

Drill Pipe

Wait

&

Weight

Casing

slide104

Wait & Weight Method

Advantages:

- Can generate lower pressure on formation near the casing shoe

- In most situation generate less pressure on surface equipment

- With a long open hole, less chance to induce losses

- One circulation, less time spent circulating through the choke

Disadvantages:

- Longer waiting time prior to circulate the influx

- Cutting could settle down and plug the annulus

- Gas migration might become a problem

- Need to have enough barite to increase the mud weight

- More Calculations

slide105

Differences between W&W and Driller’s methods

h\'i

h\'i

W & W Method

Gas at Casing Shoe,

kill mud in drill string

hm

hm

Drillers Method

Gas at Casing Shoe

slide106

Differences between W&W and Driller’s methods

h\'i

h\'\'i

W & W Method

Gas at Casing Shoe,

Kill mud in annulus

hm

Drillers Method

Gas at Casing Shoe

hm

hkm

slide107

Gas Behavior

  • Free gas expansion
  • No gas expansion
  • Volume to bleed off to maintain BHP constant
slide108

Free Gas Expansion

Gas may be swabbed into a well and remain at TD. The influx will expand as it moves up the annulus when circulation is started. The amount of expansion can easily be calculated. If undetected, free gas expansion can cause a serious well control problem.

slide109

Free Gas Expansion

A column of 10,000ft of mud, Gm=0.5psi/ft compresses one barrel of gas at TD.

The pressure in the gas is;

10,000 x 0.5 = 5,000 psi

Multiply P x Vg to find the constant.

D=10,000ft

Gm = 0.5 psi/ft

Gas

D

10,000

P

5,000

Vg

1

5,000

CST

slide110

Free Gas Expansion

The gas has risen so that the top of the bubble is at 5,000ft from the surface.

The pressure in the gas is;

5,000 x 0.5 = 2,500 psi

Using the constant, the volume of gas is found:

5,000 / 2,500 = 2 barrels

D=5,000ft

Gm = 0.5 psi/ft

D

10,000

5,000

5,000

2,500

P

Vg

1

2

5,000

5,000

PVg

slide111

Free Gas Expansion

The top of the bubble is at 2,500ft from the surface.

The pressure in the gas is;

2,500 x 0.5 = 1,250 psi

The volume of gas is found:

5,000 / 1,250 = 4 barrels

D=2,500ft

Gm = 0.5 psi/ft

D

10,000

5,000

2,500

P

5,000

2,500

1,250

Vg

1

2

4

PVg

5,000

5,000

5,000

slide112

D

10,000

5,000

2,500

1,250

P

5,000

2,500

1,250

625

Vg

1

2

4

8

5,000

PVg

5,000

5,000

5,000

Free Gas Expansion

At 1,250ft from the surface.

Pressure;

1,250 x 0.5 = 625 psi

Volume of gas;

5,000 / 625 = 8 barrels

D=1,250ft

Gm = 0.5 psi/ft

slide113

D

10,000

5,000

2,500

1,250

0

P

5,000

2,500

1,250

625

14.7

Vg

1

2

4

8

341

PVg

5,000

5,000

5,000

5,000

5,000

Free Gas Expansion

Gm = 0.5 psi/ft

slide114

No Gas Expansion

0 psi

0 ft

2,500 ft

5,000 ft

7,500 ft

1 bbls

10,000 ft

5,200 psi

Gm = 0.52 psi/ft

1 bbl gain

slide115

No Gas Expansion

0 psi

1,300 psi

0 ft

2,500 ft

5,000 ft

7,500 ft

1 bbls

1 bbls

10,000 ft

5,200 psi

6,500 psi

Gm = 0.52 psi/ft

1 bbl gain

1 bbl gain

slide116

No Gas Expansion

0 psi

1,300 psi

2,600 psi

0 ft

2,500 ft

1 bbls

5,000 ft

7,500 ft

1 bbls

1 bbls

10,000 ft

5,200 psi

6,500 psi

7,800 psi

Gm = 0.52 psi/ft

1 bbl gain

1 bbl gain

1 bbl gain

slide117

0 psi

1,300 psi

2,600 psi

3,900 psi

No Gas Expansion

0 ft

2,500 ft

1 bbls

1 bbls

5,000 ft

7,500 ft

1 bbls

1 bbls

10,000 ft

5,200 psi

6,500 psi

7,800 psi

9,100 psi

Gm = 0.52 psi/ft

1 bbl gain

1 bbl gain

1 bbl gain

1 bbl gain

slide118

0 psi

1,300 psi

2,600 psi

3,900 psi

5,200 psi

No Gas Expansion

0 ft

1 bbls

2,500 ft

1 bbls

1 bbls

5,000 ft

7,500 ft

1 bbls

1 bbls

10,000 ft

5,200 psi

6,500 psi

7,800 psi

9,100 psi

10,400 psi

Gm = 0.52 psi/ft

1 bbl gain

1 bbl gain

1 bbl gain

1 bbl gain

1 bbl gain

slide119

500 psi

1800 psi

500 psi

Volume to bleed off to keep BHP constant

0 ft

2,500 ft

5,000 ft

5700 psi

4400 psi

1.3bbls

7,500 ft

1bbls

P1V1 = P2V2

V2 = 5700 x 1 / 4400

V2 = 1.29 bbls

2500 x .52 = 1300 psi

1 bbls

10,000 ft

5,700 psi

7000 psi

5,700 psi

Gm = 0.52 psi/ft

1 bbl gain

1 bbl gain

1.3 bbl gain

slide120

500 psi

1800 psi

500 psi

Volume to bleed off to keep BHP constant

0 ft

2,500 ft

3100 psi

4400 psi

1.84bbls

5,000 ft

1.3bbls

P1V1 = P3V3

V3 = 5700 x 1 / 3100

V3 = 1.84 bbls

1.3 bbls

7,500 ft

5000 x .52 = 2600 psi

10,000 ft

5,700 psi

7,000 psi

5,700 psi

Gm = 0.52 psi/ft

1.3 bbl gain

1.3 bbl gain

1.84 bbl gain

slide121

500 psi

1800 psi

500 psi

Volume to bleed off to keep BHP constant

0 ft

3100 psi

1800 psi

2,500 ft

1.8bbls

3.16bbls

P1V1 = P4V4

V4 = 5700 x 1 / 1800

V4 = 3.16 bbls

1.8 bbls

5,000 ft

7,500 ft

7500 x .52 = 3900 psi

10,000 ft

5,700 psi

7,000 psi

5,700 psi

Gm = 0.52 psi/ft

1.84 bbl gain

1.84 bbl gain

3.16 bbl gain

slide122

500 psi

1800 psi

500 psi

Volume to bleed off to keep BHP constant

1800 psi

500 psi

0 ft

P1V1 = P5V5

V5 = 5700 x 1 / 500

V5 = 11.4 bbls

3.16 bbls

11.4bbls

2,500 ft

3.16 bbls

5,000 ft

7,500 ft

10000 x .52 = 5200 psi

10,000 ft

5,700 psi

7,000 psi

5,700 psi

Gm = 0.52 psi/ft

3.16 bbl gain

3.16 bbl gain

11.4 bbl gain

slide123

WELL # 1

HOLE SIZE

HOLE DEPTH TVD/MD

CASING 9-5/8” TVD/MD

DRILL PIPE CAP.

HEAVY WALL DRILL PIPE

CAPACITY

DRILL COLLARS 6-1/4”

CAPACITY

DRILLING FLUID DENSITY

CAPACITY OPEN HOLE/COLLARS

CAPACITY OPEN HOLE/DRILL PIPE-HWDP

CAPACITY CASING/DRILL PIPE

FRACTURE FLUID DENSITY

SIDPP

SICP

PUMP DISPLACEMENT

RRCP 30 SPM

PIT GAIN

8-1/2 INCH

11536 FEET

9875 FEET

0.01741 BBL/FEET

600 FEET

0.00874 BBL/FEET

880 FEET

0.00492 BBL/FEET

14.0 PPG

0.03221 BBL/FEET

0.04470 BBL/FEET

0.04891 BBL/FEET

16.9 PPG

530 PSI

700 PSI

0.1019 BBL/STRK

650 PSI

10.0 BBL

slide124

DRILLERS METHOD

1st CIRCULATION

DP

CSG

0

1489

0

MAASP

SHUTTING

IN

WELL

700

530

O

C

7889

7189

Ph= 8398 psi

Pf= 8928 psi

slide125

DRILLERS METHOD

1st CIRCULATION

DP

CSG

30

1489

22

REACHING

ICP

KEEP CONSTANT

CASING PRESSURE

WHILE BRINGING

PUMPS UP

PUMPS UP AND

PRESSURE STABILISED

KEEP CONSTANT

DRILL PIPE PRESSURE

MAASP

700

1180

O

C

7889

BHP= 8928 PSI

Pf= 8928 psi

slide126

DRILLERS METHOD

1st CIRCULATION

DP

CSG

30

GAS IN OPEN HOLE

CONSTANT

DRILL PIPE PRESSURE

GAS EXPANDING

CASING PRESSURE

INCREASE

SHOE PRESSURE

INCREASE

MAASP CONSTANT

1489

310

MAASP

740

1180

O

C

7929

BHP= 8928 PSI

Pf= 8928 psi

slide127

DRILLERS METHOD

1st CIRCULATION

DP

CSG

30

GAS REACH SHOE

CONSTANT

DRILL PIPE PRESSURE

GAS EXPANDING

CASING PRESSURE

INCREASE

SHOE PRESSURE

INCREASE TO MAX

MAASP CONSTANT

1489

470

MAASP

775

1180

O

C

7964

BHP= 8928 PSI

Pf= 8928 psi

slide128

DRILLERS METHOD

1st CIRCULATION

DP

CSG

30

GAS MOVES INSIDE

CASING

CONSTANT

DRILL PIPE PRESSURE

GAS EXPANDING

CASING PRESSURE

INCREASE

SHOE PRESSURE

DECREASE

MAASP INCREASING

1685

620

MAASP

785

1180

O

C

7718

BHP= 8928 PSI

Pf= 8928 psi

slide129

DRILLERS METHOD

1st CIRCULATION

DP

CSG

30

GAS MOVING INSIDE

CASING

CONSTANT

DRILL PIPE PRESSURE

GAS EXPANDING

CASING PRESSURE

INCREASE

SHOE PRESSURE

CONSTANT

MAASP INCREASING

2020

2300

MAASP

1120

1180

O

C

7718

BHP= 8928 PSI

Pf= 8928 psi

slide130

DRILLERS METHOD

1st CIRCULATION

DP

CSG

30

GAS REACH CHOKE

CONSTANT

DRILL PIPE PRESSURE

GAS EXPANDING

CASING PRESSURE

INCREASE TO MAX

SHOE PRESSURE

CONSTANT

MAASP

INCREASE TO MAX

2480

4800

MAASP

1580

1180

O

C

7718

BHP= 8928 PSI

Pf= 8928 psi

slide131

DRILLERS METHOD

1st CIRCULATION

DP

CSG

30

GAS OUT OF WELL

CONSTANT

DRILL PIPE PRESSURE

CASING PRESSURE

DECREASING TO SIDPP

SHOE PRESSURE

CONSTANT

MAASP DECREASING

TO ORIGINAL VALUE

1489

5400

MAASP

530

1180

O

C

7718

BHP= 8928 PSI

Pf= 8928 psi

slide132

DRILLERS METHOD

2nd CIRCULATION

DP

CSG

30

START PUMPING

KILL MUD 14.9 PPG

CASING PRESSURE

CONSTANT

SHOE PRESSURE

CONSTANT

MAASP CONSTANT

1489

5400

MAASP

530

1180

O

C

7718

BHP= 8928 PSI

Pf= 8928 psi

slide133

DRILLERS METHOD

2nd CIRCULATION

DP

CSG

30

KILL FLUID INSIDE

DRILL PIPE

CASING PRESSURE

CONSTANT

DRILL PIPE PRESSURE

DECREASING

SHOE PRESSURE

CONSTANT

MAASP CONSTANT

1489

6306

MAASP

530

936

O

C

7718

BHP= 8928 PSI

Pf= 8928 psi

slide134

DRILLERS METHOD

2nd CIRCULATION

DP

CSG

30

KILL MUD REACH

BIT

CONSTANT CASING

PRESSURE

DRILL PIPE PRESSURE

DECREASING TO FCP

SHOE PRESSURE

CONSTANT

MAASP CONSTANT

1489

7212

MAASP

530

692

O

C

7718

BHP= 8928 PSI

Pf= 8928 psi

slide135

DRILLERS METHOD

2nd CIRCULATION

DP

CSG

30

KILL MUD REACH

SHOE

DRILL PIPE PRESSURE

CONSTANT

CASING PRESSURE

DECREASING

SHOE PRESSURE

DECREASING

MAASP CONSTANT

1489

7832

MAASP

469

692

O

C

7657

BHP= 8928 PSI

Pf= 8928 psi

slide136

DRILLERS METHOD

2nd CIRCULATION

DP

CSG

30

KILL MUD INSIDE

CASING

DRILL PIPE PRESSURE

CONSTANT

CASING PRESSURE

DECREASING

SHOE PRESSURE

CONSTANT

MAASP DECREASING

1253

10202

MAASP

233

692

O

C

7657

BHP= 8928 PSI

Pf= 8928 psi

slide137

DRILLERS METHOD

2nd CIRCULATION

DP

CSG

30

KILL MUD AT

SURFACE

DRILL PIPE PRESSURE

CONSTANT

CASING PRESSURE

DECREASING TO ZERO

SHOE PRESSURE

CONSTANT

MAASP DECREASING

TO NEW MAASP w/KMW

1020

12600

MAASP

0

692

O

C

7657

BHP= 8928 PSI

Pf= 8928 psi

slide138

WELL # 1

HOLE SIZE

HOLE DEPTH TVD/MD

CASING 9-5/8” TVD/MD

DRILL PIPE CAP.

HEAVY WALL DRILL PIPE

CAPACITY

DRILL COLLARS 6-1/4”

CAPACITY

DRILLING FLUID DENSITY

CAPACITY OPEN HOLE/COLLARS

CAPACITY OPEN HOLE/DRILL PIPE-HWDP

CAPACITY CASING/DRILL PIPE

FRACTURE FLUID DENSITY

SIDPP

SICP

PUMP DISPLACEMENT

RRCP 30 SPM

PIT GAIN

8-1/2 INCH

11536 FEET

9875 FEET

0.01741 BBL/FEET

600 FEET

0.00874 BBL/FEET

880 FEET

0.00492 BBL/FEET

14.0 PPG

0.03221 BBL/FEET

0.04470 BBL/FEET

0.04891 BBL/FEET

16.9 PPG

530 PSI

700 PSI

0.1019 BBL/STRK

650 PSI

10.0 BBL

slide139

WAIT & WEIGHT METHOD

DP

CSG

0

1489

0

MAASP

SHUTTING

IN

WELL

MIXING KILL MUD

14.9 PPG

700

530

O

C

7889

7189

Ph= 8398 psi

Pf= 8928 psi

slide140

WAIT & WEIGHT METHOD

DP

CSG

30

REACHING

ICP

KEEP CONSTANT

CASING PRESSURE

WHILE BRINGING

PUMPS UP

PUMPS UP AND

PRESSURE STABILISED

KEEP DRILL PIPE

PRESSURE ON

SCHEDULE

1489

22

MAASP

700

1180

O

C

7889

BHP= 8928 PSI

Pf= 8928 psi

slide141

WAIT & WEIGHT METHOD

DP

CSG

30

GAS IN OPEN HOLE

DRILL PIPE PRESSURE

DECREASING

CASING PRESSURE

INCREASING

GAS EXPANDING

SHOE PRESSURE

INCREASING

MAASP CONSTANT

1489

310

MAASP

740

1097

O

C

7929

BHP= 8928 PSI

Pf= 8928 psi

slide142

WAIT & WEIGHT METHOD

DP

CSG

30

GAS REACH SHOE

DRILL PIPE PRESSURE

DECREASING

CASING PRESSURE

INCREASING

GAS EXPANDING

SHOE PRESSURE

INCREASE TO MAX

MAASP CONSTANT

1489

470

MAASP

775

1053

O

C

7964

BHP= 8928 PSI

Pf= 8928 psi

slide143

WAIT & WEIGHT METHOD

DP

CSG

30

GAS MOVES INSIDE

CASING

DRILL PIPE PRESSURE

DECREASING

CASING PRESSURE

INCREASING

GAS EXPANDING

SHOE PRESSURE

DECREASING

MAASP INCREASING

1685

620

MAASP

785

1013

O

C

7718

BHP= 8928 PSI

Pf= 8928 psi

slide144

WAIT & WEIGHT METHOD

DP

CSG

30

KILL MUD AT BIT

GAS INSIDE CASING

DRILL PIPE PRESSURE

DECREASE TO FCP

CASING PRESSURE

INCREASING

GAS EXPANDING

SHOE PRESSURE

CONSTANT

MAASP INCREASING

1950

1812

MAASP

1050

692

O

C

7718

BHP= 8928 PSI

Pf= 8928 psi

slide145

WAIT & WEIGHT METHOD

DP

CSG

30

KILL MUD AT SHOE

GAS INSIDE CASING

DRILL PIPE PRESSURE

CONSTANT

CASING PRESSURE

INCREASING

GAS EXPANDING

SHOE PRESSURE

DECREASING

MAASP INCREASING

1980

2432

MAASP

1080

692

O

C

7641

BHP= 8928 PSI

Pf= 8928 psi

slide146

WAIT & WEIGHT METHOD

DP

CSG

30

KILL MUD INSIDE

CASING

GAS REACH CHOKE

DRILL PIPE PRESSURE

CONSTANT

CASING PRESSURE

INCREASING

GAS EXPANDING

SHOE PRESSURE

CONSTANT

MAASP INCREASING

2178

4800

MAASP

1278

692

O

C

7641

BHP= 8928 PSI

Pf= 8928 psi

slide147

WAIT & WEIGHT METHOD

DP

CSG

30

KILL MUD INSIDE

CASING

GAS OUT OF WELL

DRILL PIPE PRESSURE

CONSTANT

CASING PRESSURE

DECREASING

SHOE PRESSURE

CONSTANT

MAASP DECREASING

1204

5360

MAASP

180

692

O

C

7641

BHP= 8928 PSI

Pf= 8928 psi

slide148

WAIT & WEIGHT METHOD

DP

CSG

30

KILL MUD AT

SURFACE

DRILL PIPE PRESSURE

CONSTANT

CASING PRESSURE

DECREASING TO ZERO

SHOE PRESSURE

CONSTANT

MAASP DECREASING

TO NEW MMASP w/KMW

1027

7200

MAASP

0

692

O

C

7641

BHP= 8928 PSI

Pf= 8928 psi

slide149

WELL # 1

HOLE SIZE

HOLE DEPTH TVD/MD

CASING 9-5/8” TVD/MD

DRILL PIPE CAP.

HEAVY WALL DRILL PIPE

CAPACITY

DRILL COLLARS 6-1/4”

CAPACITY

DRILLING FLUID DENSITY

CAPACITY OPEN HOLE/COLLARS

CAPACITY OPEN HOLE/DRILL PIPE-HWDP

CAPACITY CASING/DRILL PIPE

FRACTURE FLUID DENSITY

SIDPP

SICP

PUMP DISPLACEMENT

RRCP 30 SPM

PIT GAIN

8-1/2 INCH

11536 FEET

9875 FEET

0.01741 BBL/FEET

600 FEET

0.00874 BBL/FEET

880 FEET

0.00492 BBL/FEET

14.0 PPG

0.03221 BBL/FEET

0.04470 BBL/FEET

0.04891 BBL/FEET

16.9 PPG

530 PSI

700 PSI

0.1019 BBL/STRK

650 PSI

10.0 BBL

slide150

VOLUMETRIC METHOD

MIGRATION DISTANCE

GMD = -------------------------

P2 - P1

MUD GRADIENT

MIGRATION RATE/HRS

GMR = -------------------------

GMD x 60

T2 - T1

slide151

VOLUMETRIC METHOD

KEY POINT:

EVERY BARREL OF MUD IN THE WELLBORE REPRESENT

A CERTAIN AMOUNT OF HYDROSTATIC PRESSURE

Ph

Ph

slide152

VOLUMETRIC METHOD

CHOKE PRESSURE

SICP + SAFETY FACTOR + WORKING RANGE

PRESSURE/BARREL

PSI/BBL = ----------------------------

14.88 = ----------------------------

WORKING RANGE

50 PSI

VOLUME TO BLEED =--------------------

3.36 BBL =-----------------------------

MUD GRADIENT

W.R.

CAPACITY

PSI/BBL

14 x 0.052

50

0.04891

14.88

slide153

300 psi

PA

P2 - P1

GMD = --------------------------

GMR = --------------------------

Where: GMD = Gas migration distance

MWG = Mud gradient

P1 = Surface pressure at time T1

P2 = Surface pressure at time T2

GMR = Gas migration rate ( feet per hour)

T1 = Time 1 (hour)

T2 = Time 2 (hour)

MWG

GMD

12.5 ppg

T2 - T1

10000 ft

GAS

6500 psi

VOLUMETRIC METHOD

slide154

300 psi

PA

P2 - P1

GMD = --------------------------

GMR = --------------------------

Where: GMD = Gas migration distance

MWG = Mud gradient

P1 = Surface pressure at time T1

P2 = Surface pressure at time T2

GMR = Gas migration rate ( feet per hour)

T1 = Time 1 (hour)

T2 = Time 2 (hour)

MWG

GMD

12.5 ppg

T2 - T1

10000 ft

GAS

6500 psi

VOLUMETRIC METHOD

slide156

BOP

Vm

HALLIBURTON

PA

P3

Vm

6

KILL LINE

P3

Vm

5

P3

Vm

3

4

Pa

P3

GAS

6

2

P1

1

5

GAS

S

I

C

P

4

GAS

BLEED OFF

LUBRICATE

3

GAS

P3

2

GAS

1

GAS

BHP

P1

VOLUMETRIC METHOD

slide157

PRESSURE

Gas bubble pressure

Bottom hole pressure

Annular pressure

Drill pipe pressure

BLEED OFF

LUBRICATE

TIME

VOLUMETRIC METHOD

bull heading
Bull heading
  • Involves forcing formation fluids back into the formation using surface hydraulics
  • Usually considered if:

1 Formation fluid cannot be safely handled on surface (eg with H2S)

2 If anticipated formation pressures exceed what can be safely handled

  • Method usually employed as a last resort
tertiary well control methods
Tertiary well control Methods
  • Cement Plug
  • Barite plug
  • Gunk plug
slide160

Shallow Gas

  • Evaluation & Planning
  • Drill a pilot hole
  • Heavy mud in ready(1-2 ppg higher)
  • Controlled ROP
  • Use of Viscous pills instead of weighted pills
  • High circulation rates
  • Float in string
diverting shallow gas
Diverting Shallow Gas

INTERLOCKED

  • Open vent line
  • Close Diverter
  • Switch suctions to heavy mud
  • Increase pump speed to maximum
  • Circulate heavy mud round
  • Flow check
  • If still positive continue pumping.( if mud finished continue with water)
slide162

Well Control

Complications

lost circulation
Lost Circulation
  • Formation breakdown
  • Fractures and Fissures
  • Bad cement
loss circulation
Loss Circulation

Categories:

  • Seepage losses (<2bbl/Hr)
  • Partial losses (5-50 bbl/Hr)
  • Severe losses (>50bbl/Hr)
  • Complete losses (unable to maintain fluid level at surface with desired mud weight)
slide167

Hydrates

Hydrates

slide168

Hydrates

  • What are hydrates?
  • Hydrates are a solid mixture of water and natural gas (commonly methane).
  • Once formed, hydrates are similar to dirty ice .
slide169

Hydrates

  • Why are they important?
  • Hydrates can cause severe problems by forming a plug in Well Control equipment, and may completely blocking flow path.
  • One cubic foot of hydrate can contain as much as 170 cubic feet of gas.
  • Hydrates could also form on the outside of the BOP stack in deepwater.
slide170

Hydrates

  • Where do they form?
  • In deepwater Drilling
  • High Wellhead Pressure
  • Low Wellhead temperature
slide171

Hydrates

  • How to prevent hydrates?
  • Good primary well control = no gas in well bore
  • Composition of Drilling Fluid by using OBM or Chloride (Salt) in WBM.
  • Well bore temperature as high as possible
  • Select proper Mud Weight to minimize wellhead pressure.
  • injecting methanol or glycol at a rate of 0.5 - 1 gal per minutes on the upstream side of a choke
slide174

Tripping Dry

When a length of pipe is pulled from the hole, the mud level will fall.

slide175

Tripping Dry

The volume of fall is equal to the volume of steel pulled from the hole.

The trip tank is then used to fill up the hole.

If 1 barrel of steel is removed from the hole, then using the trip tank, we have to add 1 barrel of mud.

slide176

Tripping Dry

1- Calculate the volume of steel pulled:

Length x Metal Displacement

Example:

DP Metal Disp = 0.00764 bbls/ft

Length Pulled 93 feet

Volume Of Steel Pulled:

93 x 0.00764 = 0.711 bbls

slide177

Tripping Dry

2- Fill up the hole:

You must pump 0.711 barrel of mud from the trip tank.

You must investigate ( flow check) if more mud or less mud is needed.

slide178

Tripping Dry

3- NO FILL UP:

If you fail to fill up the hole, the mud level will drop by the volume of steel pulled.

It will drop inside the pipe and in the annulus.

slide179

Tripping Dry

3- NO FILL UP:

Example:

Volume Of Steel Pulled:

93 x 0.00764 = 0.711 bbls

DP Capacity: 0.01776 bbl/ft

Annular Capacity: 0.0504 bbl/ft

The mud will drop inside the pipe and the annular:

0.01776 + 0.0504 = 0.06816 bbl/ft

slide180

Tripping Dry

3- NO FILL UP:

Example Cont’d:

The volume of drop is 0.711 bbls and will drop in a volume of

0.06816 bbl / ft,

then the length of drop will be:

0.711 / 0.06816 = 10.4 feet.

If 93 feet (1 stand) are pulled with no fill up, the mud level will drop by 10.4 feet.

slide181

Tripping Wet

When a length of pipe is pulled from the hole, the mud level will fall.

slide182

Tripping Wet

The volume of fall is equal to the volume of steel pulled from the hole plus the volume of mud inside this pipe.

The trip tank is then used to fill up the hole.

If 3 barrels of steel and mud are removed from the hole, then using the trip tank, we have to add 3 barrels of mud.

slide183

Tripping Wet

1- Calculate the volume of steel pulled:

Length x Metal Displacement

Example:

DP Metal Disp = 0.00764 bbls/ft

Length Pulled 93 feet

Volume Of Steel Pulled:

93 x 0.00764 = 0.711 bbls

slide184

Tripping Wet

2- Calculate the volume of mud pulled:

Length x DP Capacity

Example:

DP Capacity = 0.01776 bbls/ft

Length Pulled 93 feet

Volume Of Mud Pulled:

93 x 0.01776 = 1.65 bbls

slide185

Tripping Wet

3- Calculate the total volume of steel and mud pulled:

1.65 + 0.711 = 2.36 barrels

slide186

Tripping Wet

4- Fill up the hole:

You must pump 2.36 barrels of mud from the trip tank.

You must investigate ( flow check) if more mud or less mud is needed.

slide187

Tripping Wet

5- NO FILL UP:

If you fail to fill up the hole, the mud level will drop by the volume of steel and mud pulled.

It will drop inside the annulus.

slide188

Tripping Wet

5- NO FILL UP:

Example:

Volume Of Steel and Mud Pulled:

93 x (0.00764+0.01776) = 2.36 bbls

Annular Capacity: 0.0504 bbl/ft

The mud will drop inside the annular by:

2.36 / 0.0504 = 46.9 feet

slide189

Pumping a Slug

It is usefull to pump a slug before tripping.

The slug weight being heavier than the mud, a length of pipe will be empty.

The HP is not reduced because the heavier mud will compensate for the empty pipe.

slide190

Pumping a Slug

The total HP is the same on both sides of the pipe.

HP kmw

HP mud

HP mud

slide191

Pumping a Slug

Example:

If 20 bbls of 12 ppg slug are pumped in a 10,000 ft hole containing 10 ppg mud, what will be the height of empty pipe?

DP capacity = 0.01776 bbl/ft

1- Calculate the height of the slug:

20 / 0.01776 = 1126 ft

slide192

Pumping a Slug

2- Calculate the HP of the slug:

1126 x 12 x 0.052 = 702.6 psi

702.6 psi

slide193

Pumping a Slug

2- Calculate the HP of the mud in the annulus:

10,000 x 10 x 0.052 = 5,200 psi

702.6 psi

5,200 psi

slide194

Pumping a Slug

3- The total hydrostatic beeing the same on both sides, calculate the HP of the mud below the slug:

5,200 - 702.6 = 4497.4 psi

702.6 psi

5,200 psi

4497.4 psi

slide195

Pumping a Slug

4- Calculate the height of mud needed to give 4497.4 psi as a HP:

TVD = 4497.4 / ( 10 x 0.052 ) = 8648.8 feet

1,126 ft

10,000 ft

8648.8 ft

slide196

Pumping a Slug

4- Calculate the height of empty pipe

10,000 - 8648.8 - 1,126 = 225.2 ft

225.2 ft

1,126 ft

10,000 ft

8648.8 ft

ad