@Rosier - Well Control for the Directional Driller

8/8/2019 @Rosier - Well Control for the Directional Driller

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Well Control for the Directional Driller

C.Rosier

Technical Training InstructorD&M Schlumberger


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ObjectivesAfter completion of this module you will be able to:

Calculate Gradientand Hydrostatic Pressurefor different mudweights and depths.

Define Pore Pressure and be able to identifyNormal

andAbnormalPore Pressure.

Describe the purpose and method of performing a FITand

LOT.


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Describe and calculate Maximum Allowable Annular SurfacePressure.

Describe and calculateMaximum Mud Weight

andEquivalentMud Weight.

Understand Equivalent Circulating Densityand why it is of

concern in well control.


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Understand the terms Primaryand Secondary Well Control.

Identify the signs of a Kick

Identify the key components of a BOP Stackand describe itsoperation.

Understand the need to Space-out.


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Hydrostatic Pressure1ft

1ft

1ft

7.48gallons

7.48

lbf/sq ft

7.48 / 144 = 0.051944 lbf/ sq in.

Hydrostatic Pressure (English Units)

A cubic foot contains 7.48 gallons

and exerts, for a fluid of 1ppg

a force of 7.48 lbsf / sq ft or7.48 / 144 lbsf / sq in.

= 0.051944 lbf / sq in

This is usually rounded to 0.052


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Hydrostatic PressureFor a fluid of a different mud weight we simply multiply thisconstant by the density of the fluid for the gradient and this

by the TVD to obtain the Pressure.

Example for a Mud Wtof 9.8 ppg, depth of 3,800 ft

TVD of 3,118 ft

Mud Wt x Constant = Mud Gradient (psi / ft)

9.8 ppg x 0.052 = 0.5096 psi / ft

Mud Gradient x TVD = Bottom Hole Pressure (psi)

0.5096 psi / ft x 3,118 ft = 1588.93 psi


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Exercise

1. For a Mud weight of 12. 6ppg what is the gradient? Whatis the bottom hole pressure for a 13,256 ft (TVD) well?

2. If my well is 17,678 ft (TVD) and my requires bottom holepressure is 8641psi, what Mud weight do I need? What is

the gradient?

3. What is the increase in bottom hole pressure if I drill from6890 ft (TVD)to 10,975 ft (TVD) with a 10.5 ppg mud?

Calculate for the following:


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Pore Pressure

The pressure of the fluid contained in the pore space in theformation of interest.

Pore Pressure is also referred to as Formation Pressure.

What is the definition of Pore Pressure?


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Normal Pore PressureNormal Pore Pressure is the Hydrostatic Pressure of the fluid

in which the sedimentation took placeDepending on the salinity and purity of the fluid (water) the

normal pressure gradient will vary from 0.433 psi / ft to 0.465

psi / ft.

For normal formation pressure to exist the overburden weight

of the formations above is supported by the grains in therock.


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Abnormal Pore PressureAbnormal Pore Pressure is when the Hydrostatic Pressure of

the fluid in which the sedimentation took place is less than,the Pore Pressure

Abnormal Pore Pressure is usually caused by interruption to

the percolation of the fluids being driven from the porespace during compaction. This causes the fluid to supportpart of the overburden of the formations at shallowerdepths.


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Abnormal Pore PressureAbnormal Pore Pressure is also caused by:

Faults

Salt Domes

Formation dips Erosion of the overburden

Formations with Pore Pressure Gradients below 0.433 psi / ftare described as having Subnormal Formation Pressure.


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Formation Fracture Pressure

Every formation has a limit to the pressure that it can

withstand before it permanently deforms or fractures. Thislimit needs to be determined so that it is not exceeded inwell control operations.

There are two systems for determining the upper pressurelimit during well killing operations:

The Leak Off Test (LOT) The Formation Integrity Test (FIT)


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The Leak Off Test

The Leak Off Test is used to accurately determine the

pressure capacity at the Shoe.Because overburden increases with depth, the shallowest

formation is usually the weakest.

Leak Off Test


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MAASPWhen the FITor MOThas been performed there becomes a

requirement to use the results in a format that is

independent of depth, as the plan is to drill ahead.

For this we use the Maximum Allowable Annular Surface Pressure

or MAASP:MAASP = Surface Pressure @ Mud Wt


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Maximum Mud Weight

An alternative to the MAASP that facilitates comparison, based

on the Equivalent Mud Weightis the Maximum Mud WeightorMMW. This states the Mud Gradientas a Mud Weight

Example:

LOT BHP = 6,534.6 psi

MMW = 6,534.6 / 9,500 / 0.052 = 13.23 ppg


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Equivalent Mud Weight

The Equivalent Mud Weightis calculated in the same way as

MMW but is for the anticipated BHP or actual BHP and notat the pressure that will cause break down of the formation.

Example:

EMW = (Surf Press / 0.052 / Depth (TVD) ) + MWt ppg

= (1,450psi / 0.052 / 8,500) + 8.9

= 12.18ppg


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Equivalent Circulating Density

The Equivalent Circulating Densityor ECDis the sum of the

Hydrostatic Pressureand the Annular Pressure Losswhencirculating.

In well control we are concerned with this because it is

possible to drill into a new formation with sufficient ECD tohold back the formation fluids, only to take a kick when westop for a connection.


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Primary Well Control

Primary Well Control is the use of the drilling fluid to

contain formation fluids by means of applied HydrostaticPressure.

To do this we need to maintain a full column of drilling fluid

at sufficient weight to overbalance the formation.

The most common causes of kicks indicate what we need tobe monitoring:


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Insufficient Fluid Density

Poor Tripping Practices Improper Hole Filling While Tripping

Swabbing / Surging Lost Circulation

Abnormal Formation Pressure

Obstructions in the Wellbore

Cementing Operations


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Special Situations:

Subsea Riser Failure Water Flushes

Drill Stem Tests (DST) Failure to Maintain Sufficient Back Pressure when Drilling

Underbalanced

Drilling from Platform Legs


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Detecting a Kick

There are certain indicators that may warn of a possible kick:

Drilling Break Increase in Return Flow

Pit Gain Well Flowing

Increase in Pump Rate

Drop in Standpipe Pressure


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Detecting a Kick

Indicators contd:

Oil Shows Insufficient displacement to / from Trip Tank

String Pulling Wet After Slugging String Weight Change


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Control Equipment

The main components of a Blow Out Preventer Stack are:

The Annular The Rams

The Choke Line The Kill Line


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Control Equipment


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Control Equipment


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Control Equipment


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Control Equipment


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Control Equipment


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5/2/2002 While drilling

Drillpipe


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5/2/2002 Closing

Pclose

Drillpipe


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Pclose

Closing

Drillpipe


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Pclose

Drillpipe

Closing


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Pclose

Drillpipe

Closing


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Pclose

Drillpipe

Closing


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Pclose

Drillpipe

Closing


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5/2/2002 Leak while closed.

SICP

Pclose

Drillpipe


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5/2/2002 Emergency seal activated.

SICP

Pclose

Drillpipe


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Control Equipment


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Available with 2 or 3 PumpsHandles High Pressure

Tungsten Carbide Choke Plates

And Extended Wear

Sleeves

Choke

Console

Detail showing

Operation ofChoke

10,000 psi / 20,000 psi

Dual Chokes / Console

Designed for H2S Service

Super Choke

10,000 psi

Control Equipment


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Control Equipment

1 Static Trim2 Dynamic Trim

3 Shuttle4 Position Indicator

5 Casing Pressure6 Set Point Pressure

1

2

3

5

64

Console Control Panel

Super AutoChoke


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Shut In Procedure

The Shut in procedure:

When a kick has been detected the first course of action is toclose the well in. However, because Pipe Rams close on

the tube only, not the tool joints it is important to Space Out

to ensure that the rams do not close on a tool-joint.

At this point the role of the Directional Driller is complete, it istime to leave the drill-floor.

@Rosier - Well Control for the Directional Driller

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