Overpressure_Mod-3.ppt

5/28/2018 Overpressure_Mod-3.ppt

1/73

OverpressurePrediction, Detection and Consequences

Training course


2/73

Module 3

Qualitative methods, Sequence for

wellsite analysis, Well Control


3/73

Qualitative Methods


4/73

Key Terms - Qualitative Methods

Background gas

Connection gas

Drag and Torque

Pump pressure Flowline Temperature

Shale Density

PWD Cavings


5/73

Gas Source

1 Cuttings gas released as the bit breaks the rock to

cuttings.

2 Gas enters directly from the borehole, due to cavings,fractures, diffusion or insufficient overbalance.

3 Hydrocarbon based products (or contaminants) in the

mud break down under thermal action.

4 Recycled gas due to insufficient degassing at surface.


6/73

Sources of Gas Whilst Drilling


7/73

Gas Data Analysis

The monitoring and interpretation of gas data are

fundamental to the detection of overpressured zones

and in many instances may be the only indicator

available.


8/73

Gas Data AnalysisFactors to Consider

Differential pressures, consider ECDs and Swabpressures during connections or trips.

Porosity and permeability of formation.

ROP and bit size. Pump rate.

Gas trap efficiency, including location

Potential for hydrocarbons in formation Mud propertiesviscosity, temperature, type.


9/73

Background Gas

Trends in Background Gas: Background Gas

Commonly thought of as gas generated

while drilling

Background gas is a composite of gases.

It is a gas that has been re-circulated, It isa gas that has been released while drilling,

and It is the gas that permeates the mud as

the hydrostatic differences from the pore

pressure and mud column approach each

other.

DEPTH-feetMD

Maximum Gas

units0 200

Connection @ 11441 'MD





11400

11500

11600

11700

11800

11900DEPTH-feetMD

Maximum Gas

units0 200


10/73

Background Gas - Trends

Example of Changes in

Background gas prior to

Kick:

Trend can develop rapidly Trend can be very subtly

Trend may not develop

depending on formation fluids.

Well Kicked

DEP

TH-feet

MD

Maximum Gas

units0 200





8700

8800

8900

9000

9100DEPTH-feet

MD

Maximum Gas

units0 200


11/73

Normalised Gas

Various formulas exist.

Basically they correct the gas figures seen for

various factors to give a more quotable figure. Factors include, hole size, ROP and flow rate.

INSITEcalculates normalised gas.


12/73

Connection Gas

Trends in Connection Gas: Connection Gas

Is the gas that is released into well

bore when the pumps are switched

off and the ECD is reduced.

Factors Affecting Connection

Gas

Overbalance

Increasing pore pressure Formation fluids

Swabbing during connections


13/73

Connection GasTips from the Field #1

You see a gas peak on a connection, in all but

exceptional circumstances just watch the next

couple of connections, it may just be a

coincidence.

The hole may be washed out and connection gas

may come in late, remember to allow time for

the gas to get from the trap and through thedetector.


14/73

Connection GasTips from the Field #2

Connection gas figures are normally quoted abovebackground gas or ABG. So if you have a C.G. peak of5.0% and background gas of 1.0%, then quote a figureof 4.0% ABG.

In INSITE delete C.G. peaks from the database. Re-insert the values in C.G. gas record. This is thendisplayed as a line. In theory this line should be drawn

between the background gas value and the CG peak e.g.from 1% to 5% in above example, then labelled 4%ABG. INSITE cant do this and the line starts from 0%.


15/73

Trip Gas

Similar to Connection Gas, but less useful.

Often seen even in normally pressured wells.

The long time interval involved can make it inevitable

in gas rich formations. Peaks often early, the peak may not be from TD and

gas migration gas occur on long trips.

Quote actual figure as it is generated in a break in

drilling. Remove gas peak from INSITE database and reinsert

as a line.


16/73

Gas Cut Mud

Gas Cut Mud: Is the reduction of mud weight coming out of the hole.

Sources of Gas Cut Mud

Gas expansion at the surface

Formations Fluids other than gas

Trapped Air in pipe / pumps

CO2 And H2S

Changing Mud properties

May Decrease Differential Pressure


17/73

Drag and Torque

Drag

Noticed on connections

or when tripping

Also caused by key

seating and BHA design

Drag (overpull) is the excess hookload over thefree handling load.

General causesnot all pressure related

Bit Balling Dog legs

Deviated holes

Differential Sticking

Poor hole cleaning

Cavings Well collapse

Swelling Clays

Junk in hole


18/73

Pump Pressure, Pits and Flow

Less dense fluid enters the well bore:

Pump pressure decreases.

Active pit will rise. Flow will increase


19/73

Tripping

Keep hole full to keep hydrostatic pressure.

Swabbing during the trip works against this.

If insufficient mud is required to top up annulus thenwell may be flowing

On tripping to bottom hole fill may indicate a close

to balance situation

Tight spots on trip also can indicate hole coming in.


20/73

Mud Temperature Analysis

Undercompacted shales have a lower thermal

conductivity (higher fluid content) and show an

abnormally high geothermal gradient.

The insulating effect of the undercompacted

zone is reflected in a lower than normal

geothermal gradient directly above in the

normally compacted formation


21/73

Temperature Response Drilling into

Overpressured Shale


22/73

Mud Temperature Analysis in the Field

In theory this is a good technique, in practice problems arise. Our Mud Temperature Out Sensor is often covered by cuttingswhich insulate it.

Additions (of cooler mud) to the active system distort trends.Using Delta Temperature i.e. MTOMTI may reduce this

affect somewhat. Changes in flow rates coupled with cooling effect of the riser

hide changes.

Bit trips cause trends to be lost, as mud cools during tripsEnd to end temperature analysis is used to try and overcomethis

Use of MWD or wireline temperature data might be of moreuse.


23/73

End to End Temperature Plot


24/73

Downhole Temperature from MWD

Plot shows a normal

temperate gradient (red

line) established.

This is diverged from as

a possible overpressured

zone is entered.

EWR Temperature vs. Depth

3000

3500

4000

4500

5000

5500

6000

6500

7000

7500

6065707580859095

Temperature (deg F)

Depth

(TVD)


25/73

Mud Conductivity Analysis

When using a fresh water based mud, salt water entryfrom the formation will cause an increase in chloridecontent of the mud filtrate.

This amount depends on the contrast betweenchlorides in the mud and chlorides in the formation.

Generally an increase in mud conductivity (assuminga constant chloride content of the mud due to surface

additions) will indicate increased pore fluid withinthe drilled formation, and hence increased formationpore pressure.


26/73

Cuttings Analysis

Includes:

Shale Density

Bulk Density Shale Factor

Cuttings Shape


27/73

Shale Density #1

Overpressured clay zones will show a reduction

in Shale density.

Accurately measuring shale density is a

problem. A density column is constructed, this

is filled with Zinc Bromide. The bottom of the

column is saturated, the top almost pure water,

in between the density grades from high to low.


28/73

Shale Density Column and Calibration

Graph


29/73

Shale Density #2

Problems

Is the tested sample a fresh cutting, a cutting that was

slow to clear from the well or a fragment from an

unstable bore hole? Is the shale reactive i.e. absorbed water from mud.

Sample composition, accessory minerals, siltiness,

escaping gas. User inconsistency


30/73

Shale Factor

As diagenesis proceeds montmorillonite clays areconverted to illite clays plus water. Hencemontmorillonite content should decrease with depth.

However, overpressured zones are assumed to be

sections in which normal diagenesis (for that depth) hasnot taken place. This is because in zones of abnormalpressure the pore fluid bears a greater part of theoverburden stress and the rock matrix a lesser part.

Hence, because clay diagenesis is, in part, a pressuredependant process the montmorillonite/illite ratio in the

formation will increase.


31/73

Cuttings Shape

Changes in Size Cutting becoming larger/smaller

Changes in Shape Cutting become splintery/rounded

/concave or curlednot actually

cuttings but cavings from side ofborehole

Changes in Texture Shales becoming Clays

Changes in Volume

Changes in Mineralogy


32/73

CavingsWellsite Evaluation

If seen at well site samples should be taken. Parameters torecord include:

1 Size

2 Shape

3 % shaker cover4 Point of origin in well bore, shaved off by BHA, fresh or

worked.

Sometimes buckets may be filled as the cavings drop offthe shakers. The time a bucket fills may give someindication of cavings trends.


33/73

Pressure DetectionNone Logging

Wireline data - FDC, sonic, resistivity,

gamma, temperature,

caliper, RFT, neutron

porosity.

FEMWD - FDC, sonic, resistivity,

gamma, temperature,

caliper, PWD.


34/73

Pressure Whilst Drilling

Gives realtime accurate

ECD values.

Gives recorded mud

weight and ECD values. Supersedes hydraulics or

swab surge programs.

Knowledge of mud

weight and ECD is very

important, too high and

the formation isfractured, too low and a

kick may be taken.

Example PWD Log


35/73

Bit Depthfeet

15000 15500 16000

TimePit Vol To tal

barrels

200 300 400

Running Speedfeet per min

-400 0 400

Gas Hydrcbn Avg

0 50 100

percent Dens M ud In Avg

15.5 16 16.5 17 lbs per gal

RPM Surface Avgrev per min

0 250 500

SPP Avglbs per sq inch

0 2500 5000

Real-tim e PWD Eqv Mu d wt

lbs per gal15.5 16 16.5 17

ROP Instfeet per hr

0 200 400

Flow In Pum Avggallon per min

0 500 1000

PWD Eqv Mu d wt

lbs per gal15.5 16 16.5 17

18:30

ECD drilling

16.26 ppgSwab & surge due

to reaming

Connection

@ 1585 6 ft Square pumps off

pressure profileMud returns

35 bbls

Swab & surge due

to pipe movement

Example PWD Log

Recommended Sequence of


36/73

Recommended Sequence of

Overpressure Detection

1 Prior to Drilling

2 Whilst Drilling

3 At Casing Point / TD

P i D illi


37/73

Prior to Drilling

Obtain from nearby wells: Wireline/FEMWD

Logs, Mud Logs,Pressure Logs.

1 Use density (sonic) data to calculate Overburden Gradient, use air gapand water depth. Use Excel spreadsheet, import into INSITE.

2 Plot up sonic, resistivity and FDC data into INSITE.3 Use any RFT, kick or Well test data to calculate normal trends and

recalculate b exponent.

4 Obtain prognosis, should list pressure estimates, nearby LOT data,formation tops etc.

5 Using all the above data estimate and plot OBG, pore pressure (range)and fracture gradients. Write on comments about hole problems, gaslevels etc. Display on unit wall


38/73

Whilst Drilling

Maintain Pressure Log upto date, including porepressure estimate, OBG and fracture pressure.

Start a separate DxC plot in INSITE with valuesshifted and NCT inserted.

Watch shakers for cavings. Monitor drag and torquerecord values.

Lag connections.

Use any FEMWD available: PWD, temp, gamma etc. Look for any trends, communicate even if your

evidence contradicts what was expected.


39/73

At Casing Point / TD

Collect any wireline data that may become

available, update your estimates accordingly.


40/73

Key TermsWell Control

Ballooning U-tubing

Connection Flow Monitoring

Fingerprinting

Well Control

Kicks

Well kill

Kick tolerance MASP

BOPs

Stripping

Annular Preventer

Rams

Fingerprinting

B h l B ll i (B thi ) Sh l


41/73

Borehole Ballooning (Breathing) ShalesPre-existing FracturesRock at great depth is under tremendous stress

loads for geologic periods of time. The wellbore

replaces neighboring rock with drilling mud which

creates stress release fractures around the

wellbore. These fractures open when induced

pressures exceed the fracture value and remain

open until the induced pressure falls below the

minimum horizontal stress.

Cohesive Strength

Bonded Grains (Cement)

Pore

Pressure

Increased Pore Pressure

Reduces the Effective Stress

OverburdenStress (Sy )

Horizontal

Stress (Sh )

Horizontal

Stress (SH )

The induced pressure only needs to

exceed the bonding strength

between the rock grains to

propagate the fractures. The

propagation pressure is influencedby:

Pore Pressure

Mud Type (SOBM for example)

Opened by ECD

Ballooning #1


42/73

Causes

Ballooning Shale is a term used to identify a type of FALSE

indication of a kick ( ie, fluid returning from formation when

the pumps are stopped)

Occurrence

Plastic shale is loaded to a pressure greater than the fracture

gradient (ie tensile strength)

Problematic

Can have worse effects if we try to kill it conventionally

g

B ll i #2


43/73

Ballooning #2

IdentifiersThese may also be seen for a kick

Mud must have been LOST during the current drilling

sequence.

Pit gain normally occurs with pumps off.

Shut-in and Casing pressures approach the same . Cure

Recommended procedure is to reduce mud weight until all

losses stop. If no losses then no flow back can occur.

If this cant be done, then need to set casing.

Borehole Ballooning #1


44/73

Bit Depthfeet

15000 15500 16000

TimePit Vol Total

barrels

200 300 400

Running Sp eed

feet per min-400 0 400

Gas Hydrcbn Avg

0 50 100 percent

Dens M ud In Avg

15.5 16 16.5 17lbs per gal


0 250 500


0 2500 5000

Real-tim e PWD Eqv Mud wt

lbs per gal15.5 16 16.5 17

ROP Instfeet per hr

0 200 400


0 500 1000

PWD Eqv Mu d wt

lbs per gal15.5 16 16.5 17

18:30

ECD drilling

16.26 ppgSwab & surge due

to reaming

Connection

@ 1585 6 ft Square pumps off

pressure profileMud returns35 bbls

Swab & surge due

to pipe movement


PWD data No ballooning present.



45/73

Bit Depthfeet

17000 17500 18000

TimePit Vol To tal

barrels

200 300 400

Running Speed

feet per min-400 0 400

Gas Hydrcbn Avg

0 50 100 percent

Dens Mud In Avg

15.5 16 16.5 17lbs per gal


0 250 500


0 2500 5000

Real-time PWD Eqv Mud wt

lbs per gal15.5 16 16.5 17

ROP Instfeet per hr

0 200 400


0 500 1000

PWD Eqv Mud wt

lbs per gal15.5 16 16.5 17

15:00

15:15

15:30

Fracture closure

pressure 16.33 ppg ECD 16.45 ppg

Reported mud

weight 15.8 ppg

Mud returns 60 bbls

and st ill gainingConnection

@ 17696 ft

Static mud we ight

equilibrium not reachedSlow build up

to drilling EC D


PWD data Ballooning present.

U Tube Effect


46/73

U-Tube Effect

12075 ft

16 ppg

11.5 ppg

Drill Pipe

Annulus

10,046 psi 7220 psi

0 2826psi

Differential Pressu re

reflected on the gauge

that has the lighter

f lu id beneath it.

Connection Flow Monitor (CFMTM)


47/73

Connection Flow Monitor (CFM )

To establish if the flowback at a connection is normal,

and to differentiate between wellbore breathing andinfluxes.

In normal circumstances the backflow should stabilise

shortly after the pumps are switched off. The amount ofbackflow will depend on the pump rate being used. The

higher the pump rate the more backflow will be seen

Trends can be identified as normal, ballooning or a kick.

Ideal for combining with PWD data.

CFM - Ballooning


48/73

(1), 10:35, 14/02

(2), 21:50, 14/02

(3), 03:05, 15/02

After drilling out of shoe, flow back totaled 80 bbl (1)(typical of stable

well without breathing). After pack-off, breathing induced and seapage

losses noted. Flowback increased to 140 bbl (2). Added CaCO3 toreduce seepage losses. Flowback cut to 110 bbl (3).

C a oo g

CFM - Kick


49/73

0.00

10.00

20.00

30.00

40.00

50.00

60.00

0:00:00 0:01:26 0:02:53 0:04:19 0:05:46 0:07:12

11659.75 ft

11721.66 ft

11800.65 ft

11842.09 ft

11874.1 ft

11893.14 ft

11932.21 ft

11989.05 ft

Volume

(bbl)

Time

From changes in flowback trends an

influx can be identified at an early

stage. This triggers alarms in theprogram

Fingerprinting #1


50/73

g p g

Rig and well specific

Measurement and recording of real time changes in

surface mud volumes and/or downhole pressures

when specific operations take place

Baseline events in known good conditions

The purpose is to differentiate:

The expected (ie, what COULD happen)

From the actual (what DID happen)

under a given set of circumstances

Fingerprinting #2


51/73

Fingerprinting #2

Test Objective

Monitor trip volume in cased in

hole

Obtain real opposed to

calculated pipe displacementsPressure test casing Find mud compressibility factor

Swab test Record PWD data

Stripping Drill Record volume and pressuresChoke drill Perform SCRs, record

pressures and times

Typical Fingerprinting exercises

Well Control


52/73

Well Control The Control of formation fluid into the wellbore.

The three phases of Well Control are:

Phase Definition Objective

Primary

First Line of Defence

Control kicks with

hydrostatic pressure only.

(Normal drilling)

Drill to TD without a

well control event

Secondary

Second Line of

Defence

Control kicks with

hydrostatic pressure

assisted by BOPs

Safely kill the kick

without the loss of

circulation

Tertiary

Third Line of Defence

An underground blowout Avoid a surface

blowout. Regain

primary well control

Kick


53/73

Causes of a kickImproper hole fill on trips

Swabbing

Insufficient mud density

Loss of circulation

Abnormally pressured formations

Overpressured shallow gas sands

High ROPs in gas bearing formations

Loss of hydrostatic during or after

cementing operationsIncomplete removal of formation

fluids from the wellbore during testing

or workover operations

Warning Signs of a kickDrilling Break

Increase in flow returns

Pit gain

Incorrect trip volumes

Decrease in SPP or rise in SPM

Increasing gas values.

Well flows with the pump off

Change in mud properties.

CavingsCutback in DxC or shale density

PWD

When formation fluid enters the wellbore. It is a critical state of well imbalance.


54/73

Kick Types

Two types of Kick exist:

1 Underbalance KickThe formation pressure

increases to higher than the hydrostatic

2 Induced KickHydrostatic decreases to

below formation pressure.


55/73

Well Kill

The act of removing the formation fluid from

the well bore and reasserting the hydrostatic

overbalance.

Two (basic) methods for Well Kill exist:

1 Wait and weight.

2 Drillers Method.

Kick Tolerance


56/73

The maximum volume / EMW (of kick) that can be

circulated from the well without fracturing the casingshoe.

Kick tolerance is highest on drilling out the casingshoe. It drops with increasing TVD and increasing

mud weight. Kick tolerance is affected by: Shoe depth, LOT/ FIT,

mud weight, influx of gradient, kick depth, height ofinflux.

Use a worst case scenario of a gas kick (0.1 psi/ft)and so calculate a kick volume.


57/73

MAASP

Maximum Allowable Annular Surface Pressure

Also referred to as MASP

The Maximum pressure allowed on CSIP gauge

during a kick.

MAASP = (LOT EMWMW) x 0.052 x TVD @Shoe

(For ppg calculations)

Blowout Preventers


58/73

Shut in the wellPipe in or out of the hole

Provide a means of pumping fluids into the well

under pressure Allow the controlled release of fluids from the

well

Allow movement of the pipe under pressure

Provide redundancy in case of failure

Subsea BOP Stack


59/73

Subsea BOP Stack

Stripping


60/73

pp g

Tripping the string through closed (Annular preventer) BOP

into pressurized wellbore under its own weight. Can be used to return to bottom at constant BHP when shut-in

off bottom.

Once on bottom, influx can be safely circulated out.

Places high stress on equipment

Requires training and requires coordination between crew

members

Short term annular stripping and long term ramcombination stripping.

Annular Preventers


61/73

Capable of closing on various shapes and sizesof pipe including kelly, spiral drill collars and

HWDP.

Enables pipe to be rotated or stripped while

under pressure.

Closure is wellbore pressure assisted

Hydraulic operating pressure is regulated to

enable stripping operations.

Annular Preventers


62/73

Annular Preventer Closed on Pipe

Ram Type Blowout Preventers


63/73

Pipe Rams

Designed to close and seal around the pipe body

Blind Rams

Designed to close and seal on open hole

Shearing Blind Rams Designed to shear the pipe body then close and seal the

wellbore

Variable Bore Rams

Designed to close and seal on multiple pipe sizes


64/73

Basic Well Kill

Identify Kick Type


65/73

Kick Type Required Condition

Under Balance Kick Occurs only whilst drilling

Caused by overpressure

SIDPP is greater than standpipe

hydrostaticInduced Kick Can occur during any open hole

situation

All formation pressure regimes can

produce an induced kick

SIDPP is equal to standpipe hydrostatic

Best Kill Procedure for Kick Type


66/73

Under Balance Kick Induced Kick

Wait and Weight Method Drillers Method

A constant bottom hole

pressure method to avoid

additional kicks.

Minimises pressures imposed

to wellbore and equipment.

Kills kick in one complete

circulation.

A constant bottom hole

pressure method to avoid

additional kicks.

Allows kill process to be

started immediately.

Removes influx in one

bottoms up.

Wait & Weight Method


67/73

Whilst preparing for kill monitor for gas migration, bleed off

to keep constant pressure. Calculate kill mud weight

Hold casing/kill line pressure at shut-in value whilst increasing

pump to kill rate.

Hold pump speed at kill rate, adjusting pressure with choke.

When kill mud reaches bit, hold pump rate and adjust choke to

hold final drill pipe pressure until kill mud returns.

Flow check, condition mud system.

Drillers Method


68/73

Whilst preparing for kill monitor for gas migration, bleed off

to keep constant pressure.

Hold casing/kill line pressure at shut-in value while

increasing pump to kill rate.

With pump at kill rate, record observed circulating drill pipepressure.

Hold pump speed at kill rate and adjust choke to maintain

drill pipe pressure until bottoms up strokes pumped.

Flow check condition mud system.

Basic Well Kill Formula


69/73

FP = (MW x 0.052 x TVD) + SIDPP

KMW = SIDPP / (0.052 x TVD) + OMW

Inf. Grad. = (MW x 0.052)((CSIPSIDPP) / HT)

HT = Gain / Ann. Vol.

Where:

FP = Formation Pressure SIDPP = Shut in Drill Pipe Pressure

KMW = Kill Mud Weight, OMW = Original Mud Weight

CSIP = Casing Shut in Pressure

HT = Height of influx

Inf. Grad. = Influx gradient Using ppg, ft and psi

Gradients / Weights


70/73

Gradient

Psi/ft

ppgEMW SG

Gas 0.1 2.0 0.23

Oil/Gas/WaterMixture

0.10.45 2.08.6 0.238.6

Water 0.45 8.6 1.03

Approximate gradients of oil, water and gas.

Well Kill Question


71/73

A 8 bbl kick is taken whilst drilling ahead at 10500 ftTVD. The well is now shut in. The Mud weight is11.3 ppg and SIDPP 325 psi, the CSIP 440 psi. Thehole is 8 and the BHA 300ft of 6 collars, then 5

drill pipe.1 What type of kick has been taken?

2 What kill method do you propose?

3 What is your kill mud weight?4 What type of kick (gas, oil, water etc) is it?

Well Kill Answer


72/73

1 Kick type is presumably underbalanced.

2 Use the Wait & Weight method.

3 KMW = SIDPP / (0.052 x TVD) + OMW

So: KMW = 325 / (0.052 x 10500) + 11.3 = 11.9 ppg

4 HT = Gain / Ann. Vol. so HT = 8 / 0.035 = 229 ftInf. Grad. = (MW x 0.052)((CSIPSIDPP) / HT)

So: Inf Grad = (11.3 x 0.052)((440325) / 229) = 0.09 psi/ft

This would indicate a gas kick.

End of Module SummaryKey Terms


73/73

Ballooning

U-tubing CFM

Fingerprinting

Well Control

Kicks Well kill

BOPs

Stripping

Annular Preventer Rams

Background gas

Connection gas Drag and Torque

Pump pressure

Flowline Temperature

Shale Density PWD

Cavings

Kick tolerance

MASP Fingerprinting

Documents

Overpressure_Mod-3.ppt