Well Control Manual

WELL CONTROL MANUAL

Introduction and How to Use

Volume 1 Procedures and Guidelines

Volume 2 Fundamentals of Well Control

BP EXPLORATION © 1995 British Petroleum Company PLC Text originated by BP Drilling Department Manual produced by ODL Publications, Aberdeen, Tel (01224) 637171

BP WELL CONTROL MANUAL

WELCOME Click here to zoom in on text, then click on text to scroll through

Ladies and Gentlemen: Following is the Second Edition of the “BP Well Control Manual” first issued in 1987. When issued it was expected to be a living document, accounting for changes in technology and experience, it still is. Now, eight years later, horizontal and extended reach wells, coil tubing drilling and under balance drilling have or will become part of our kit for improved profitability. Our objective with this Second Edition is to bring three changes to the operating groups: 1)

Issue the manual in an electronic version as a pilot which may lead to collecting all of the manuals on a server or CD-ROM.

2)

Make available Excel based well control worksheets which have been incorporated into the manual.

3)

Modify parts of Volume I Chapters 1 and 6 for high angle and horizontal well operations.

In a separate file we have issued the “HTHP Well Control Manual”. Future updates will tie this manual with the “BP Well Control Manual”. Publication of the manual in electronic format should make the abundance of information in it more accessible to you. A powerful search capability and “hot button” references are part of the software package we have selected. Software used is compatible with Macintosh, MS-DOS and DEC hardware platforms making it accessible to BP and our contractors when needed. Electronic publishing makes modifications easier and we solicit your suggestions for correction, clarification, change or addition to the manual. If we have not managed to make the resource more useful and clear to you we have failed our objective. Your views on how well we have done are important. To open and use the manual please read the section below. While use of the electronic version of the manual is encouraged there is still the option of printing a hard copy of the manual. Hard copies can still be obtained from ODL in Aberdeen at a cost for printing and shipping. Originally this manual was not issued as “policy”. In the October 1994 Drilling Managers Meeting this and two other documents, the “Drilling Policy Manual” and “Casing Design Manual”, were designated as the three core policy documents covering our operations. Every effort has been made in this edition to tie to the other two documents.

March 1995

BP WELL CONTROL MANUAL

HOW TO USE This manual has been converted into Adobe Acrobat software and is a ‘read only’ version, ie you cannot make any changes to text or figures, you can copy the text and figures and paste them in to another application.

Navigating through the Manual When you have read this you will be able to navigate quickly through the manual, to and from volumes, sections, subsections and figures. Clicking the mouse on the `Main Contents' button at the bottom of this page will take you to the Well Control Manual overall contents list, ie Volume 1 or 2. For additional help use the Acrobat Help files.

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To go back or forward to a previous move you have made, use the Acrobat arrows in the Menu Bar.

Once you have reached the section you require (e.g. 1.1 General), the hand cursor will appear with an arrow inside it. Press the mouse button on the section you require to read, and you will be zoomed into the section, press it again and it will scroll through that section, at the end of the section it will reset to the beginning of the section.

Excel Worksheets Each example of a Worksheet in the manual is linked to a blank Excel Template for you to use for your own calculations, just click on the example Worksheet and Excel will automatically open. To return to the manual, simply Quit out of Excel.

Printing When printing to a US Letter size printer please click on the “Shrink to Fit” box in the Print dialogue box. Printing of Excel Worksheets is through Excel.

Manual Contents

March 1995

BP WELL CONTROL MANUAL

Volume 1 – Contents Nomenclature Abbreviations 1 PREPARATION Section 1.1 1.2 1.3 1.4 1.5

Page INSTRUMENTATION AND CONTROL MANPOWER ORGANISATION DRILLS AND SLOW CIRCULATING RATES USE OF THE MUD SYSTEM KICK TOLERANCE

1-1 1-9 1-15 1-27 1-35

2 THE PREVENTION OF A KICK Section 2.1 2.2 2.3

CORRECT TRIPPING PROCEDURES MAINTAIN SUITABLE HYDROSTATIC PRESSURE CONTROL LOST CIRCULATION

2-1 2-9 2-17

3 WARNING SIGNS OF A KICK Paragraph 1 2 3 4 5

GENERAL DRILLING BREAK INCREASED RETURNS FLOWRATE PIT GAIN HOLE NOT TAKING CORRECT VOLUME DURING A TRIP 6 CHANGE IN PROPERTIES OF RETURNED MUD 7 INCREASE IN HOOKLOAD 8 CHANGE IN PUMP SPEED OR PRESSURE

3-2 3-2 3-2 3-3 3-4 3-6 3-6

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BP WELL CONTROL MANUAL

4 ACTION ON DETECTING AN INFLUX Section 4.1 4.2 4.3

Page SHALLOW GAS PROCEDURE SHUT-IN PROCEDURE DURING SHUT-IN PERIOD

4-1 4-9 4-17

5 WELL KILL DECISION ANALYSIS Paragraph 1 2 3 4 5 6 7

GENERAL PIPE ON BOTTOM PIPE OFF BOTTOM – (Drillpipe in the Stack) PIPE OFF BOTTOM – (Drillcollar in the Stack) NO PIPE IN THE HOLE WHILE RUNNING CASING OR LINER UNDERGROUND BLOWOUT

5-2 5-2 5-2 5-5 5-5 5-7 5-9

6 WELL KILL TECHNIQUES Section 6.1

6.2

6.3

March 1995

STANDARD TECHNIQUES – Wait and Weight Method – Driller’s Method SPECIAL TECHNIQUES 1. Volumetric Method 2. Stripping 3. Bullheading 4. Snubbing 5. Baryte Plugs 6. Emergency Procedure COMPLICATIONS

6-1 6-2 6-3 6-31 6-33 6-47 6-67 6-75 6-84 6-93 6-97

BP WELL CONTROL MANUAL

NOMENCLATURE SYMBOL

DESCRIPTION

UNIT

A a An b c C Cp Ca CL CR D Dshoe Dwp dbit dh dhc do di dcut dc F Fsh FPG g G

Cross sectional area Constant Total nozzle area Constant Constant Annular capacity Pipe capacity Cuttings concentration Clinging constant Closing ratio Depth Shoe depth Depth of openhole weak point Bit diameter Hole diameter Hole/casing ID Pipe OD Pipe ID Average cuttings diameter Drilling exponent (corrected) Force Shale formation factor Formation Pressure Gradient Gravity acceleration Pressure gradient

Gi H Hi Hp ITT K L λ MR M m MW

Influx gradient Height Height of influx Height of plug Interval Transit Time Bulk modulus of elasticity Length Rotary exponent Migration rate Matrix stress Threshold bit weight Mud weight

in.2 – in.2 – – bbl/m bbl/m % – – m m m in. in. in. in. in. in. – lb – SG – psi/ft psi/m SG psi/ft m m m µsec/m m – m/hr psi lb SG

March 1995

BP WELL CONTROL MANUAL

SYMBOL

DESCRIPTION

UNIT

N OPG P

Rotary speed Overburden Pressure Gradient Pressure

∆P Pa ∆Pbit Pcl Pdp Pf Pfrac Pfc Pi Pic Plo Pmax

S Sg Sw t

Adjustment pressure Annulus pressure Bit pressure drop Choke line pressure loss Drillpipe pressure Formation pressure Fracture pressure Final circulating pressure Hydrostatic pressure of influx Initial circulating pressure Leak off pressure Maximum allowable pressure at the openhole weak point Wide open choke pressure Pore pressure Slow circulating rate pressure Plastic Viscosity Flowrate Mud flowrate Gas flowrate Reynolds number Resistivity Resistivity of water Rate of Penetration Shale factor Overburden pressure Gas saturation Water saturation Time

rpm SG psi/SG (The units of subsurface pressure may be either psi or SG) psi psi psi psi psi psi/SG psi/SG psi psi psi psi/SG

TR T

Transport Ratio Temperature

TD TVD V

Total Depth True Vertical Depth Kick tolerance

Poc Pp Pscr PV Q Qmud Qgas Re R Rw ROP

March 1995

psi/SG psi psi/SG psi cP gal/min gal/min gal/min – ohm-m ohm-m m/hr meq/100g psi Fractional Fractional seconds min – degrees C, F, R m m bbl

BP WELL CONTROL MANUAL

SYMBOL

DESCRIPTION

V

Volume

v vmud vp vs W

w

w wb wcut WOB x YP Z µ ν σ’1 σ’t Ø Ø600 β ρ ρb

UNIT

bbl cc ml l Velocity m/min m/s Mud velocity m/min Average pipe running speed m/min Slip velocity m/min Weight gm kg lb Weight lb/ft lb/bbl SG Weight of pipe lb/ft Baryte required for weighting up lb/bbl Average cuttings weight SG Weight on Bit lb Offset () Yield Point lb/100ft2 Compressibility factor – Viscosity cP Poissons’s Ratio – Maximum effective principle stress psi/SG Tectonic stress psi/SG Porosity Fractional Fann reading lb/100ft2 Tectonic stress coefficient – Density SG Bulk density SG

March 1995

BP WELL CONTROL MANUAL

ABBREVIATIONS API RP BHA BOP BRT DWT ECD EMW H2S IADC ID KTOL LCM LMRP LO MAASP OBM OD PMS PV ROP SCR SG SPM YP

March 1995

American Petroleum Institute Recommended Practice Bottomhole Assembly Blowout Preventer Below Rotary Table Dead Weight Tester Equivalent Circulating Density Equivalent Mud Weight Hydrogen Sulphide International Association of Drilling Contractors Internal Diameter Kick Tolerance Lost Circulation Material Lower Marine Riser Package Leak off Maximum Allowable Annular Surface Pressure Oil Base Mud Outside Diameter Preventive Maintenance System Plastic Viscosity Rate of Penetration Slow Circulating Rate Specific Gravity Strokes per Minute Yield Point

BP WELL CONTROL MANUAL

1 PREPARATION Section

Page

1.1 INSTRUMENTATION AND CONTROL

1-1

1.2 MANPOWER ORGANISATION

1-9

1.3 DRILLS AND SLOW CIRCULATING RATES

1-15

1.4 USE OF THE MUD SYSTEM

1-27

1.5 KICK TOLERANCE

1-35

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BP WELL CONTROL MANUAL

1.1 INSTRUMENTATION AND CONTROL Paragraph

Page

1

General

1-2

2

Pressure Gauges

1-2

3

Pump Control

1-4

4

Fluid Measurement

1-6

Illustrations 1.1

Suggested Instrumentation for a Floating Rig

1-3

1.2

Suggested Instrumentation for a Fixed Installation

1-5

1.3

Suggested Fluid Measurement System

1-7

1-1 March 1995

BP WELL CONTROL MANUAL

1 General It is essential that an appropriate level of control equipment is provided on every rig in order that a well that is under pressure can be accurately monitored. In general, during a well control incident, there is a necessity for more accurate instrumentation than under conditions encountered during routine drilling. The level of instrumentation on every rig therefore must be evaluated in order to assess its␣ s uitability for well control purposes. This evaluation should ideally be carried out in␣conjunction with the pre contract rig audit and any deficiencies made good prior to contract␣award. The purpose of this section is to highlight the important aspects of instrumentation and control and to recommend a standard level of equipment for all rig types. The level of instrumentation that is recommended will ensure that a suitable level of control is afforded during unusually critical operations, and that adequate back-up is provided. Therefore, much of this equipment would not be necessary in routine circumstances. However equipment failure is most likely when the equipment is highly stressed. It is in these situations that serious incidents can develop if a suitable level of back-up instrumentation and control equipment is not to hand.

2 Pressure Gauges When a well is under pressure it is important that accurate pressure measurements can be made. Each rig will normally be equipped with gauges to read standpipe pressure and annulus pressure. The gauges that are fitted to the choke panel and at the driller’s console are often the only gauges available for well control purposes. Although the standpipe and choke manifold will generally be fitted with ‘Cameron’ gauges, these are considered to be so inaccurate as to have little application to well control. All of these gauges will have a fullscale deflection that is at least equal to the working pressure rating of the equipment. In all cases, this means that it will be necessary to install gauges of lower rating in order that relatively low pressures can be accurately recorded. This will be especially important with high pressure equipment. It is also important that suitable pressure gauges are installed at the choke manifold in case the well has to be controlled from this position. This will apply to land rigs which may be equipped only with manual chokes and the majority of rigs that are equipped with both manual and remote operated chokes. Accurate readout of pump pressure and choke pressure is, in the majority of cases, all that is required. However an extra pressure reading is required on a floating rig in order that the wellhead pressure can be monitored through the kill line. In order to be able to install additional pressure gauges it may be necessary to fabricate manifolds and install high pressure instrument hose between the choke panel and the standpipe/choke manifold. All this equipment must be rated to the working pressure of the␣equipment.

1-2 March 1995

BP WELL CONTROL MANUAL

Figure 1.1 Suggested Instrumentation for a Floating Rig

STANDPIPE 1

CAMERON GAUGE

STANDPIPE 2

1/4in NEEDLE VALVE

D

TRANSDUCER

K

CHECK VALVE

C

STANDPIPE MANIFOLD HYDRAULIC FLUID INLET

CHOKE PANEL

CAMERON GAUGE D

SW

K C

AC

O

PUMP OUTPUT MONITOR

KILL LINE

REMOTELY OPERATED CHOKE

CHOKE MANIFOLD

MANUAL CHOKES

CHOKE LINE

BUFFER TANK FROM BOP

DRAIN

OVERBOARD LINE

D – DRILL PIPE K – KILL LINE

POORBOY DEGASSER

C – CHOKE LINE – 1/4in NEEDLE VALVES FLOWLINE

– CHECK VALVE/HYDRAULIC FLUID INLET

WEOX02.001

1-3 March 1995

BP WELL CONTROL MANUAL

So in general: •

There must be gauges available to read choke pressure, standpipe pressure and kill line static pressure in the case of a floating rig.

•

The above gauges must be readable from the manifold if manual chokes are fitted to the manifold.

•

It must be possible to easily install and remove low range pressure gauges at the choke panel and at the choke manifold.

Suggested pressure recording systems for a floating rig and a fixed installation are shown in Figures 1.1 and 1.2. The proposed systems can also be used for measuring slow circulating rate pressures (SCRs). The following points should be noted from the proposed systems: •

A good selection of gauges should be available. Gauges should be calibrated on a regular basis with a Dead Weight Tester. It is suggested that the gauges are checked at each BOP Test and at this stage the pressure monitors in the mud logging unit should be checked against the rig equipment.

•

It must be easy to change the gauges.

•

A hydraulic fluid hand pump should be available to purge the lines at suitable points as shown.

•

Consideration should be given to completely isolating the supplementary pressure monitoring system from that originally fitted to the rig. This would ensure that the original system was closed and hence in no way susceptible to leaking needle valves or misuse of the supplementary system.

•

Sensitive low pressure rated gauges should be removed from the system unless required. The piping and manifolding should be permanently installed. It would be a good idea to fabricate a cover for the manifolding at the choke manifold and choke panel.

•

The gauges that are used to measure the slow circulating rate pressures should be used to monitor well pressures in the event a kick is taken.

•

A stroke counter, similar to the battery operated ‘Swaco’ unit, is recommended for remote installation at the choke manifold. It should be removed when not required. A suitably isolated terminal should be located at a convenient point at the choke manifold, in order that the signal from the limit switches on the pumps can be transmitted to the counter.

3 Pump Control It is desirable that the remote control of the pump used to kill a well that is under pressure is located reasonably close to the choke operator. In most cases the rig pumps will be used. Generally, the Driller will control these pumps from a position that is close to the choke panel. Most choke panels contain a meter that displays the cumulative output of the pump. Therefore, in the majority of cases, if the well is controlled with a remote operated choke, the man on the pump will be able to co-ordinate with the choke operator.

1-4 March 1995

BP WELL CONTROL MANUAL

Figure 1.2 Suggested Instrumentation for a Fixed Installation

TO STANDPIPE

TO STANDPIPE

STANDPIPE MANIFOLD

D C

D

C

CHOKE PANEL D

SW

AC

O

1/4in HYDRAULIC FLUID FILLED HIGH PRESSURE HOSE

TO PUMP/ CHOKE PANEL

FROM BOP CHOKE CHOKE PRESSURE GAUGE

TO DEGASSER TO BURN PIT REMOTELY OPERATED CHOKE

TO BURN PIT TRANSDUCER

CHOKE MANIFOLD

CAMERON GAUGE

TO BURN PIT TO DEGASSER

C – CHOKE LINE D – DRILL PIPE – 1/4in NEEDLE VALVES – CHECK VALVE/HYDRAULIC FLUID INLET

WEOX02.002

1-5 March 1995

BP WELL CONTROL MANUAL

However, if the choke manifold contains manual chokes, the choke operator may be some considerable distance from the man on the pump and a monitor of the pump output. In such cases, it is recommended that a remote pump output meter is positioned at the choke manifold. This will be especially important on land rigs which may be equipped only with manual chokes and where often the choke manifold is located at some distance from the rig floor. A further complication may arise if a kill pump or cement pump is used during a well control operation. It may become necessary to use these pumps on any rig, but the use of a relatively small displacement pump will be standard well control procedure on a floating rig that is drilling in deep water. Therefore, on a floating rig, it is desirable that it is possible to control and monitor the kill/cement pump from the rig floor.

4 Fluid Measurement During stripping operations, as well as during a volumetric kill, it is important to be␣able to accurately measure small volumes of fluid bled from, or pumped into the␣well. API RP 53 recommends that ‘a trip tank or other method of accurately measuring the drilling fluid bled off, leaked from, or pumped into a well within an accuracy of half a barrel is␣required’. Most rigs will not have suitable equipment to do this. It is usually assumed that the choke manifold lined up across a manual choke to the trip tank␣is a suitable fluid measurement system. However , in most cases this will not be a satisfactory arrangement because of the relatively large volume in the line between the choke and the tank. In general, there is a requirement for a line from the well, terminating at a manual choke positioned directly above a measuring cylinder, such as the trip tank (hydraulically activated chokes are not suitable for this application). However a bleed line from the well to the mixing tanks on the cement/kill pump may be sufficient. The most satisfactory arrangement is to use a strip tank as shown in Figure 1.3. This tank would typically have a 3 to 4 bbl capacity so that very small volumes of fluid can be measured. After bleeding into the strip tank, the tank contents can be emptied into the trip tank where the total volume of mud bled from the well, together with the mud leaked past the preventers, can be measured. Although it is not ideal, it may be sufficient to use a Lo-Torq valve instead of a␣manual choke to bleed fluid to the tank. However, during a long operation this is likely to wash out and so provision should be made to easily and quickly replace the valve. It is not recommended to bleed mud into a measuring tank that is situated in a confined area when there is a possibility that gas is entrained in the mud.

1-6 March 1995

BP WELL CONTROL MANUAL

PRESSURE GAUGE

FROM CHOKE MANIFOLD/BOP

MANUAL CHOKE 3in PIPE

LEVEL INDICATOR

STRIP TANK (3 – 4bbl capacity)

LARGE ID DRAIN WORKING PLATFORM

FLOWLINE RETURNS

TRIP TANK

WEOX02.003

Figure 1.3 Suggested Fluid Measurement System

1-7/8 1-7 March 1995

BP WELL CONTROL MANUAL

1.2 MANPOWER ORGANISATION Paragraph

Page

1

General

1-10

2

Individual Responsibilities

1-10

3

Communication

1-12

Illustrations 1.4

An Example Communication System

1-13

1-9 March 1995

BP WELL CONTROL MANUAL

1 General This section is intended to provide a guideline for the allocation of individual responsibilities during a well control incident. It is Company policy that a well control contingency plan should include the allocation of individual responsibilities. The contingency plan should be drawn up in conjunction with the drilling contractor and should be regularly reassessed. Well control drills provide an opportunity to assess the effectiveness of the contingency plan and to identify and make good any inadequacies.

2 Individual Responsibilities The well control contingency plan must allocate the responsibilities of all those concerned in the operation. Circumstances at the rigsite may dictate that these responsibilities be modified in the event of an incident; however, the following can be used as guidelines for the allocation of responsibilities in the event of a well control incident:

(a) The Company Representative •

Once the well has been shut-in and is being correctly monitored, to organise a pre-kill meeting for all those involved in the supervision of the well control operation.

•

To provide specific well control procedures, using the contingency plan as a guideline.

•

To monitor and supervise the implementation of these procedures.

•

To be present on the rig floor at the start of the kill operation. Either the Toolpusher or the Company Representative should be present at all times on the rig floor during the operation.

•

To maintain communication with the Operations base.

•

The Company Representative has the right to assume complete control of the work required to regain control of the well.

•

To assign the responsibility of keeping a diary of events.

(b) The Company Drilling Engineer •

Will provide technical back-up to the Company Representative.

•

To keep a diary of events.

(c) The Senior Contractor Representative •

Has the overall responsibility for all actions taken on the rig.

•

Has the responsibility for supervising the contractor staff that are not directly involved in the well control operation.

1-10 March 1995

BP WELL CONTROL MANUAL

•

However, in the event that the well gets out of control, the Company Representative has the right to assume complete control and supervise the work required to regain full control of the well. (This entitlement is a standard condition of Company drilling contracts.)

(d) The Contractor Toolpusher •

Has overall responsibility for the implementation of the well control operation.

•

Has the responsibility for ensuring that the driller and the drill crew are correctly deployed during the well control operation.

•

Must be present at the rig floor during the start of the kill operation. Either the Toolpusher or the Company Representative should be present at all times on the rig floor during the operation.

•

Has the responsibility for briefing the off duty drill crew prior to starting a new␣shift.

(e) The Driller •

Has the responsibility for the initial detection of the kick and closing in the well.

•

Has the responsibility for supervising the drill crew during the well control operation.

(f) The Mud Engineer •

Has continuous responsibility for monitoring the mud system and the conditioning of the mud.

It may be prudent to send an extra Mud Engineer to the rig in the event of a well control incident to ensure constant supervision of the mud system.

(g) The Cementing Engineer •

Will ensure that the cement unit is ready for operation at any time.

•

Will operate the cement unit at the discretion of the Company Representative.

(h) The Subsea Engineer (where appropriate) •

Should be available for consultation at all times during the well control operation.

•

Has the responsibility for checking all the BOP equipment during the operation.

(j) The Mud Logging Engineers •

Have the responsibility for continuously monitoring the circulating system during the well control operation.

•

One member of the crew must keep a diary of events.

1-11 March 1995

BP WELL CONTROL MANUAL

3 Communication One of the Company Representative’s responsibilities is to organise a pre-kill meeting once the well has been shut-in. The purpose of this meeting is to ensure that all those involved in the supervision and implementation of the well control operation are familiar with the procedures that will be used to kill the well. This meeting is also the first stage in the process of communication during the well control operation. Experience has shown that even the most well conceived well control procedures can go badly wrong if communication before and during the operation is not properly organised and effective. It is therefore most important that the well control contingency plan details the method and line of communication for each individual involved in the operation. The objectives of a suitable system of communication are: •

To ensure that all information relevant to the well control operation is communicated to the Company Representative.

•

To ensure that those involved in the supervision of the operation are at all times in communication with the Company Representative.

•

To ensure that all those involved in the operation are aware of the line and method of communication that they should use.

•

To ensure that communication equipment on the rig is adequate, and is used during the well control operation in the most effective manner possible.

Figure 1.4 shows an example of a possible communication system on a semi-submersible␣rig for use during standard well control operations. The following can be noted from this example: •

After the kick is taken, the well is shut-in and closely monitored.

•

The Company Representative calls a pre-kill meeting of those involved in the supervision of the operation.

•

Responsibilities are allocated to those involved in the operation by the supervisors who attended the meeting.

•

Each line and method of communication is defined. It should be noted that: –

The rig telephone system is not overloaded.

–

The most important lines of communication to and from the Company Representative (denoted by those inside the broken line) are best maintained with the use of hand held radios.

–

The use of intrinsically safe hand held radios ensures that all those inside the broken line can listen in on each others communication.

–

Depending on the type of operation it may be necessary to include others within the broken line.

1-12 March 1995

BP WELL CONTROL MANUAL

Figure 1.4 An Example Communication System

(1) KICK TAKEN – WELL SHUT-IN – WELL BEING MONITORED (2) PREKILL MEETING

COMPANY REPRESENTATIVE COMPANY DRILLING ENGINEER SENIOR CONTRACTOR REPRESENTATIVE TOOLPUSHER MUD ENGINEER MUD LOGGING ENGINEER

(3) ALLOCATE RESPONSIBILITIES

OFF DUTY DRILL CREW

SENIOR CONTRACTOR REPRESENTATIVE

MUD ENGINEER

TOOLPUSHER

SUBSEA ENGINEER

CONTRACTOR STAFF

MATES

CONTRACTOR SHOREBASE

DRILLER

DRILL CREW

PUMPMAN/ DERRICKMAN

(4) MAJOR LINES/METHOD OF COMMUNICATION DURING THE WELL CONTROL OPERATION DRILL CREW

CONTRACTOR SHOREBASE

DRILLER

MARINE STAFF

PUMPMAN/ DERRICKMAN

RT

RT

RT

SENIOR CONTRACTOR REPRESENTATIVE

TOOLPUSHER

S/S

MUD ENGINEER

H/H H/H S/S

H/H COMPANY REPRESENTATIVE

RT

RT

SUBSEA ENGINEER

COMPANY SHOREBASE

RT – RIG TELEPHONE SYSTEM

SERVICE COMPANY ENGINEERS

S/S – SHIP TO SHORE

MUD LOGGING ENGINEER

H/H – HAND HELD SET

WEOX02.004

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BP WELL CONTROL MANUAL

1.3 DRILLS AND SLOW CIRCULATING RATES Paragraph

Page

1

General

1-16

2

BOP Drills

1-16

3

D1: Kick while Tripping

1-17

4

D2: Kick while Drilling

1-17

5

D3: Diverter Drill

1-19

6

D4: Accumulator Drill

1-19

7

D5: Well Kill Drill

1-21

8

Slow Circulating Rate Pressures, SCRs

1-22

9

Choke Line Losses

1-23

Illustrations 1.5

SCR Pressure Plot

1-23

1.6

Choke Line Pressure Loss Data Sheet

1-25

1.7

An example Determination of Choke Line Losses

1-26

1-15 March 1995

BP WELL CONTROL MANUAL

1 General Both BOP Drills and the recording of slow circulating rate pressures will be carried out on a routine basis on all rigs. This section covers the reasons why it is necessary to carry out BOP Drills, to regularly record SCRs, as well as recommended procedures.

2 BOP Drills The purpose of BOP Drills is to familiarise the drillcrews with techniques that will be implemented in the event of a kick. One of the major factors that influences the wellbore pressures after a kick is taken is the volume of the influx. The smaller the influx, the less severe will be the pressures during the well kill operation. In this respect, it is important that the drillcrew react quickly to any sign that an influx may have occurred and promptly execute the prescribed control procedure. Drills should be designed to reduce the time that the crew take to implement these procedures. The relevant Drills should be carried out as often as is necessary, and as hole conditions permit, until the Company Representative and the Contractor Toolpusher are satisfied that every member of the drillcrew is familiar with the entire operation. Every effort must be made to ensure that the Drill is carried out in the most realistic manner possible. Where practical, there should be no difference between the Drill and actual control procedures. Once satisfactory standards have been achieved, the Drills (D1, D2 and D3, as appropriate) should be held at least once per week. If standards fall unacceptably, the Company Representative should stipulate that the Drills are conducted more frequently. It is important that returning drillcrews have frequent Drills. The following Drills should be practised where applicable: D1 – Tripping D2 – Drilling D3 – Diverter D4 – Accumulator D5 – Well Kill (Suffix R to be included if the remote panel was used) These codes should be used to record the results of the Drill on the BOP Drill Record Proforma. This form should be sent to the Drilling Superintendent fortnightly. The results of each Drill must also be recorded on the IADC Drilling Report.

1-16 March 1995

BP WELL CONTROL MANUAL

3 D1: Kick while Tripping The purpose of this Drill is to familiarise the crew with the shut-in procedure that will be implemented in the event of a kick during a trip. This Drill should only be conducted when the BHA is inside the last casing string. Before the trip is started, the Standing Orders to the Driller will have been posted. This will detail the action that the crew should take in the event a kick is detected. When directed by the Company Representative, the Contractor Toolpusher will instruct the Driller to assume that a positive flowcheck has been conducted, and to implement the prescribed control procedure as detailed in the Standing Orders. Shut-in procedures to be adopted in the event of a kick while tripping are detailed in Chapter␣4. However, as a guideline the following procedure should be initiated: •

Without prior notice, the Company Representative will start the Drill by manually raising the trip tank float to indicate a rapid pit gain.

•

The Driller is expected to take the following steps to shut in the well: 1. Stop other operations. 2. Install the drillpipe safety valve. 3. Open the choke line valve. 4. Close the annular preventer. 5. Record the casing and drillpipe pressure. 6. Notify the Company Representative that the well is shut-in. 7. Record the time for the Drill on the IADC Drilling Report.

The Contractor Toolpusher must ensure that the crew are correctly deployed and that each individual completely understands his responsibilities. The time taken for the crew to shut in the well should be recorded. Having shut-in the well, preparations should be made to strip pipe. These preparations should include lining up the equipment as required, assigning individual responsibilities and preparing the Stripping Worksheet.

4 D2: Kick while Drilling The purpose of this Drill is to familiarise the crew with the control procedure that will be implemented in the event of a kick while drilling. This Drill may be conducted either in open or cased hole. However if the drill is conducted when the drillstring is in openhole, the well will not be shut-in .

1-17 March 1995

BP WELL CONTROL MANUAL

When the pipe is on bottom, the following procedure can be used as a guideline for the drill: •

Without prior notice, the Company Representative gradually increases the apparent pit level by manually raising the float.

•

The Driller is expected to detect the pit gain and take the following steps: 1. Pick up the kelly (or topdrive) until the tool joint clears the BOPs and the kelly cock is just above the rotary table. 2. Shut down the pumps. 3. Check the well for flow. 4. Report to the Company Representative. 5. Record the time required for the crew to react and conduct the Drill on the IADC drilling report.

When the bit has been tripped to the previous casing shoe, a further Drill may be conducted that will result in the well being shut-in. Therefore after tripping the bit to the shoe, the following procedure may be used as a guideline for this Drill: •

Stop tripping operations and install the kelly (or topdrive) and start circulating.

•

Having been instructed to do so by the Company Representative, the Driller is expected to take the following steps to shut-in the well: 1. Pull up until the tool joint clears the BOPs. 2. Shut down the pumps. 3. Open the choke line valve. 4. Close the annular preventer. 5. Record the casing and drillpipe pressure.

*

6. Double check spaceout, close and lock hang-off rams and hang-off pipe and check that the kelly cock is just above the rotary table. 7. Notify the Company Representative that the well has been shut-in. 8. Record the time taken for the crew to shut-in the well on the IADC drilling report. * If on a floating rig

The procedures adopted during these Drills should be in line with the shut-in procedures as outlined in the Standing Orders. These procedures are outlined in Chapter 4.

1-18 March 1995

BP WELL CONTROL MANUAL

5 D3: Diverter Drill If shallow gas is encountered and the well kicks, blowout conditions may develop very quickly. It is therefore important that crew initiate control procedures as soon as possible in the event of a shallow gas kick. Diverter Drills should therefore be carried out to minimise the reaction time of the crews. A further objective of the Drill is to check that all diverter equipment is functioning correctly. The time taken for each diverter function to operate should be recorded. A Drill should be carried out prior to drilling out of the conductor casing. The procedures that should be implemented in the event of a shallow gas kick are covered in Chapter 4. Drills should be designed in line with the specific procedure that will be adopted in the event of a shallow gas kick. The Contractor Toolpusher must ensure that the drill crew, and marine staff (offshore), are correctly deployed during the Drill and that each individual understands his responsibilities. The time recorded in the log should be the time elapsed from initiation of the Drill until the rig crew (and marine staff) are ready to initiate emergency procedures.

6 D4: Accumulator Drill The purpose of the Accumulator Drill is to check the operation of the BOP closing system. The following specific tests are recommended:

(a) Accumulator precharge pressure test This test must be conducted on each well prior to spudding and approximately every 30␣days thereafter at convenient times. On closing units with two or more banks of accumulator bottles, the hydraulic fluid line to each bank must have a full opening valve to isolate individual banks. The valves must be in the open position except when accumulators are isolated for testing, servicing or transporting. The precharge test should be conducted as follows: 1. Shut-off all accumulator pumps. 2. Drain the hydraulic fluid from the accumulator system into the closing unit fluid reservoir. 3. Remove the guard from the valve stem assembly on top of each accumulator bottle. Attach the charging and gauging assembly to each bottle and check the nitrogen precharge. 4. If the nitrogen precharge pressure on any bottle is less than the minimum acceptable precharge pressure listed below, recharge that bottle (with nitrogen gas only) to achieve the specified desired precharge pressure. 5. If the nitrogen precharge on any bottle is greater than the maximum acceptable precharge pressure listed below, a sufficient volume of nitrogen gas must be bled from the accumulator bottle to provide the specified desired precharge pressure.

1-19 March 1995

BP WELL CONTROL MANUAL

Accumulator Working Pressure Rating

Desired Precharge Pressure

Min. Acceptable Precharge Pressure

Max. Acceptable Precharge Pressure

1500 psi 2000 psi 3000 psi

750 psi 1000 psi 1000 psi

750 psi 950 psi 950 psi

850 psi 1100 psi 1100 psi

(b) Accumulator closing test This test should be conducted before BOP stack tests. The test should be conducted as follows: 1. Position a joint of drillpipe in the blowout preventer stack. 2. Close off the power supply to the accumulator pumps. 3. Record the initial accumulator pressure. The pressure should be the designed operating pressure of the accumulators. Adjust the regulator to provide 1500 psi operating pressure to the annular preventer. 4. Operate the sequence of functions as relevant to the rig type. For a land rig: Close the annular preventer and one pipe ram (sized for the pipe in the stack). Open the HCR valve on the choke line. For the floating rig: Close and open all the well control functions (apart from blind/shear rams). Duplicate the operation of the blind/shear rams. After each function, record the volume used, the time taken, and the residual accumulator pressure. The residual accumulator pressure after completing all the tests must be at least 200 psi greater than the precharge pressure. 5. Turn on the accumulator pumps. Having completed the tests, recharge the accumulator system to its designed operating pressure. Record the time taken to recharge the system.

(c) Closing unit pump test Prior to conducting any tests, the closing unit reservoir should be inspected to be sure it does not contain any foreign fluid or debris. The closing unit pump capability test should be conducted before BOP stack tests. This test can be conveniently scheduled either immediately before or after the accumulator closing time test. The test should be conducted according to the following procedure. 1. Position a joint of drillpipe in the blowout preventer stack. 2. Isolate the accumulators from the closing unit manifold by closing the required valves.

1-20 March 1995

BP WELL CONTROL MANUAL

3. If the accumulator pumps are powered by air, isolate the rig air system from the pumps. A separate closing unit air storage tank should be used to power the pumps during this test. When a dual power (air and electric) source system is used, both power supplies should be tested separately. 4. Close the annular preventer and open one choke line failsafe valve (or␣HCR valve). Record the time (in seconds) required for the closing unit pumps to close the annular preventer plus open the choke line valve and obtain 200 psi above the accumulator precharge pressure on the closing unit manifold. It is recommended that the time required for the closing unit pumps to accomplish these operations does not exceed two minutes. 5. Close the choke line failsafe (or HCR valve) and open the annular preventer. Open the accumulator system to the closing unit and charge the accumulator system to its designed operating pressure using the pumps.

7 D5: Well Kill Drill The objective of this Drill is to give drillcrews the most realistic type of well control␣training and a feel for the equipment and procedures that they would use to kill a well. This Drill should be carried out prior to drilling out the intermediate and production strings. It should never be carried out when openhole sections are exposed. The following procedure is recommended: 1. Run in hole and tag the top of cement. 2. Pull back one stand and install the kelly (or install topdrive). 3. Break circulation and establish slow circulating rate pressures. (Consider circulating bottoms up prior to this if the annulus may contain contaminated mud). 4. Carry out standard BOP Drill D2, resulting in the well being shut-in. 5. Consider applying low pressure to the casing (typically 200 psi), bring the pump up to kill speed controlling the drillpipe pressure according to a predetermined schedule. It is important that this opportunity to circulate across a choke is used to maximum effect. A drillpipe pressure schedule should be drawn up and carefully adhered to. It is important that the choke operator develops a feel for the lag time between manipulation of the choke and its subsequent effect on the drillpipe pressure. The lag time should be recorded, so that it can be used for reference should a kick be taken in the next hole section.

1-21 March 1995

BP WELL CONTROL MANUAL

8 Slow Circulating Rate Pressures, SCRs There are many reasons why a kick should be displaced from the hole at a rate that is considerably slower than that used during normal drilling. These include: •

To minimise the pressure exerted on the openhole.

•

To allow weighting of the mud as the kick is displaced.

•

To permit adequate degassing of the returned mud.

•

To limit the speed of required choke adjustments.

•

To reduce the pressure exerted on well control equipment.

All these factors must be taken into account when deciding at what rate to displace the kick. However the absolute upper limit for the displacement rate may be restricted by the pressure rating of the surface equipment, in particular the setting of the pump relief valve. It should be noted that it is potentially hazardous to displace a kick from the hole when the surface pressure is close to the relief valve setting. In order to estimate the circulating pressures during the displacement of a kick, it is necessary to know the friction pressure in the circulating system at low rates. For this reason, it is useful to have determined the SCR pressure before a kick is taken. At a given rate of circulation, the initial circulating pressure can be estimated from the sum of the shut-in drillpipe pressure and the SCR pressure. Company policy states that SCRs should be conducted regularly and at least: •

Once per tour (or at 300m intervals during the tour).

•

When the bit is changed.

•

When the BHA is changed.

•

When the mud weight or properties are changed.

The range of circulation rates used will be dependent upon many factors, but should fall within the limits of 1/2 and 4 barrels per minute. If oil base mud is in the hole, when back on bottom after a trip, circulate bottoms up before measuring SCRs. At these relatively low pump speeds the volumetric efficiency of the rig pumps may be significantly less than at normal speeds used during drilling. It is therefore recommended that the volumetric efficiency of the rig pumps is checked at low pump speed, such as when pumping a slug prior to a trip. It is useful to plot the SCRs on a graph as shown in Figure 1.5. The drillstring internal friction should be calculated at the SCRs and used to determine the annulus frictional pressure as shown. The annulus frictional pressure is a major factor that will influence the rate at which the kick will be displaced from the hole (using standard well control procedure the annulus frictional pressure will be added to wellbore pressure as the pump is brought up to speed to kill the well).

1-22 March 1995

STANDPIPE PRESSURE (psi)

BP WELL CONTROL MANUAL

PSCR3

Drillstring internal pressure drop

PSCR2

Annulus pressure drop

PSCR1

SCR1

SCR2

SCR3

PUMP OUTPUT (bbls/min) (stks/min)

Other SCRs can be selected to displace the kick

WEOX02.005

Figure 1.5 SCR Pressure Plot A graph similar to Figure 1.5 aids the selection of circulation rates other than these actually measured and also provides a guide to the size of the annulus circulating losses over a range of circulation rates.

9 Choke Line Losses The frictional pressure caused by circulating through the choke line, while displacing a kick from the well, can cause additional pressures to act in the wellbore. These pressures are not significant in the case of land, platform and jack-up rigs, but can be critical in the case of a floating rig. In most cases however, if the correct procedures are adhered to, the choke line frictional pressure should be accounted for as the kick is displaced out of the hole. The recommended method is to monitor the wellhead pressure through the kill line as the pump is started. If the wellhead pressure remains constant as the pump is brought up to speed then the choke line friction will in most cases be automatically compensated for. (This technique is outlined in detail in Chapter 6.) It is also possible to account for the choke line losses by reducing the choke pressure by an amount equal to the choke line loss as the pump is brought up to speed. This method is not considered to be as reliable as using the kill line monitor.

1-23 March 1995

BP WELL CONTROL MANUAL

It is important that the choke line frictional pressure is accurately known at a wide range of circulating rates. From this information the additional load on the wellbore can be assessed at a range of displacement rates and subsequently the most suitable rate can be selected. The following procedure should be implemented in order to properly assess the choke line frictional pressures at slow circulating rates. This procedure should be carried out initially when the BOP and riser are installed and before drilling out of each subsequent casing shoe. 1. Install suitable pressure gauges to record standpipe and choke pressures during circulation. 2. Record SCR pressure at a range of rates from 1/2 to 4 bbl/min down drillpipe and up the riser. 3. Open choke line valves. 4. Line up choke manifold to route flow across a fully opened remote operated choke. Route returned flow through the poorboy gas separator to the shakers. 5. Space out to ensure no tool joint is opposite annular preventer. 6. Close annular preventer. 7. Circulate down the drillpipe and up through the choke line until returns are uniform. 8. Record SCR pressure at same rates as before. Record the choke pressure at each rate. 9. Calculate the choke line frictional pressure at each rate. Figure 1.6 shows a form that can be used to record the data. The form also shows how to determine the choke line friction pressure from the recorded data. Figure 1.7 shows an example determination of choke line losses. The choke line losses should be adjusted for changes in mud weight as shown on the form. The accuracy of this adjustment is however questionable over a wide range of mud weights. In order to verify choke line losses after drilling out of the casing shoe, it is acceptable to isolate the well and pump down the choke line at the range of slow circulating rates.

1-24 March 1995

WELL No

25

RIG 19

RIG

WELL STATUS DURING TEST

DATE

25/7/87

133/8in CASING RUN AND TESTED / 135/8in STACK INSTALLED AND TESTED

PROPERTIES OF THE MUD IN THE HOLE DURING THE TEST

1.4SG OBM/PV24CP/YP100 lb/100ft2

RECORDED BY

CORRECTED CHOKE LINE LOSS

CORRECTED CHOKE LINE LOSS

1.4 SG AT…………… MUD WEIGHT (psi)

AT…………… MUD WEIGHT (psi)

AT…………… MUD WEIGHT (psi)

AT…………… MUD WEIGHT (psi)

1-25

6.5 ……………in LINER PUMP RATE

……………in LINER PUMP RATE

SCR PRESSURE UP RISER

(bbl/min)

(SPM)

(SPM)

(psi)

4.78

40

RIG PUMPS: NATIONAL 12 - P - 160 985 1435 80

370

3.58

30

680

985

250

2.39

20

400

590

CHOKE PRESSURE AT SCR (psi)

55 40

150

CEMENT PUMP - HT - 400 (4in PLUNGER) 1.00

120

190

25

45

0.5 0.25

50

65

10

0

0

0 0

(1)

(2)

(3)

(2)-(1)-(3)

0

March 1995

WEOX02.006

BP WELL CONTROL MANUAL

CORRECTED CHOKE LINE LOSS

CIRCULATION RATE

SCR PRESSURE UP CHOKE LINE (psi)

J. P.

MEASURED CHOKE LINE LOSS

Figure 1.6 Choke Line Pressure Loss Data Sheet

CHOKE LINE PRESSURE LOSS DATA SHEET

BP WELL CONTROL MANUAL

Figure 1.7 An example Determination of Choke Line Losses

CIRCULATING @ 20SPM UP RISER

CIRCULATING @ 20SPM UP CHOKE LINE (CHOKE WIDE OPEN)

400

600

PSCR @ 20SPM = 400psi

POC = 50psi

50

PCL = PSCR (up choke line) – PSCR (up riser) – POC = 600 – 400 – 50 PCL = 150psi

where

PSCR = Slow Circulating Rate Pressure (psi) PCL = Choke Line Pressure Loss at SCR (psi) POC = Choke Pressure recorded at SCR with choke wide open (psi)

WEOX02.007

1-26 March 1995

BP WELL CONTROL MANUAL

1.4 USE OF THE MUD SYSTEM Paragraph

Page

1

General

1-28

2

Pit Management

1-28

3

Building Mud Weight

1-29

4

Dealing with Gas at Surface

1-31

5

Chemical Stocks

1-34

Illustrations 1.8

An example Mud Gas Separator – operating at maximum capacity

1-32

1-27 March 1995

BP WELL CONTROL MANUAL

1 General Well control contingency plans should outline the manner in which the mud system will be utilised during standard well control operations. This section is intended to highlight the major factors that will determine the most satisfactory arrangement of the mud system in such circumstances.

2 Pit Management The following guidelines should be considered when specifying pit arrangements:

(a) While drilling a critical hole section •

Keep the active mud system surface area as small as is practical to ease kick detection. Any reserve mud stocks in the tanks should be positively isolated from the active system. Ensure that the gates on the trough are sealing properly.

•

Adequate reserve stocks of mud should be held; the volume and weight of which will be determined by the nature of the next hole section.

•

Ensure all pit level systems and tank isolating valves are working correctly before drilling into possible gas-bearing zones.

•

Keep all mud treatments and pit transfers to the absolute minimum at critical sections of the well. Ensure that the Driller and the Mud Logging Engineer are aware in advance of any changes to the system.

•

Crew safety meetings should discuss the problem of gas kicks, especially if oil based mud is in use, and emphasise the importance of early detection. Mud engineering and mud logging personnel should attend these meetings.

(b) When displacing a kick The major factors that will determine the most satisfactory pit arrangement for displacing a kick include the following: •

The technique that will be used to displace the kick.

•

The usable surface pit volume in relation to the hole volume.

•

The method of weighing up the mud.

•

How to deal with the kick when it is displaced to the surface.

•

How to deal with the pit gain caused by influx expansion during displacement.

•

How to deal with contaminated returns.

•

The nature and toxicity of the influx fluid.

•

The monitoring of pit levels in the active system.

1-28 March 1995

BP WELL CONTROL MANUAL

The kick can be displaced from the hole using either the Wait and Weight Method or the Driller’s Method. The most satisfactory arrangement of the pits will be different for each technique and clearly will be rig-specific. There are three different stages at which the mud can be weighted up for these two techniques: •

•

The Wait and Weight Method –

In a typical situation when it is impractical to weight up a complete hole volume prior to displacement of the kick. This will therefore entail that some mud is weighted while the kick is displaced from the hole. The volume that is weighted prior to displacement of the kick will depend, for a given hole capacity, on the rate at which baryte can be added into the system in relation to the desired rate of displacement.

–

In the unusual situation when there is adequate surface volume, a complete hole volume of kill mud can be prepared before displacement of the kick.

The Driller’s Method –

In this case the mud is weighted either while the kick is displaced with original weight mud or after the first circulation depending on the availability of baryte and tank space.

3 Building Mud Weight (a) Baryte delivery to the mud pits The rate at which baryte can be added to the original mud influences the time required to increase the weight of a volume of mud. For this reason it is important to measure the rate at which both the conventional hopper system and the high rate system (if fitted) can supply baryte. If the Driller’s Method is used this will determine the time required to build the mud weight after the kick has been displaced from the hole. If the Wait and Weight Method is used, the maximum rate at which baryte can be supplied to the mud will: •

Determine the time required to weight the hole volume of mud before the kick is displaced.

•

Or it may limit the rate at which the kick can be displaced, if the mud is weighted as the kick is displaced.

The maximum rate at which the mud can be weighted can be determined for a given required mud weight increase from the following formula: Maximum possible rate = at which the mud can be weighted (bbl/min)

Baryte delivery rate (lb/min) Baryte required to weight up (lb/bbl)

1-29 March 1995

BP WELL CONTROL MANUAL

Therefore for the following example: Required mud weight increase = 0.2 SG (from 1.5 SG to 1.7 SG) Baryte required = 1490 X (1.7 - 1.5) = 117 lb/bbl 4.25 - 1.7 If the maximum barytes delivery rate for the rig = 350 lb/min Then: Maximum rate at which the = 350 = 3 bbl/min mud can be weighted 117 This figure therefore gives an indication of the maximum displacement rate if the mud is weighted as the kick is displaced from the hole.

(b) Baryte storage When possible at least one full barytes storage tank should be pressured up at all times and the bulk delivery system tested regularly. The bulk system should be included in the rig PMS (Preventive Maintenance) system.

(c) Building viscosity into the mud There may be well control situations which require that considerable volumes of weighted mud are built from a water or oil base. This may be the case in the following situations: •

If considerable losses are experienced.

•

If the required volume of kill weight mud is greater than the surface stocks of active and reserve weighted mud.

•

If the returns are severely contaminated and have to be dumped.

The limiting factor for an oil base mud may be the rate at which viscosity can be built into the base oil. Building viscosity is usually a less important factor when water base muds are used. Shear equipment is required for building viscosity using clay viscosifiers in new base oil. Some offshore rigs have jet line mixers to help build viscosity. In circumstances in which large volumes of new oil mud must be built, it would be useful to know the rate at which new mud can be sheared to a level at which barytes can be suspended. This rate is determined by shearing a known volume of new mud until the minimum viscosity is reached. As a guideline, the minimum viscosity would be represented by a yield point of 10, and a 10 second gel reading of 3. In emergency situations, viscosity can be built quickly using an oil mud polymer (Baroid’s LFR 2000 as an example) at 4 lb/bbl in conjunction with organophilic clays. However, it is recognised that these polymers can cause high temperature gelation of the mud, and as such, they are not recommended for use in high temperature wells.

1-30 March 1995

BP WELL CONTROL MANUAL

(d) Volume increase due to baryte addition The volume of a given amount of mud will increase as baryte is added to it. This may be significant when large mud weight increase is required in a large volume of mud. The volume increase due to baryte addition can be determined from the following relationship: Volume increase = 1.48 bbl per metric ton of baryte added Therefore in the following situation: The required addition of baryte = 200 lb/bbl Volume to weight up = 600 bbl Volume increase due to baryte addition = 600 X 200 X 1.48 = 80 bbl 2205

4 Dealing with Gas at Surface It is important that suitable equipment is available on the rig to deal with the influx once it is displaced to surface. Returns should be piped through the mud gas separator and then on to the degasser for further treatment.

(a) The mud gas separator (poorboy) The mud gas separator should be lined up at all times when a kick is being displaced. The separator is used to remove large gas bubbles from the mud and to deal with a flow of gas once the influx is at surface. There will be a limit to the volume of gas that each separator can safely deal with. When this limit is exceeded, there exists the possibility that gas will blow through into the shaker header box. An estimation can be made of the maximum gas flowrate that the separator can handle. The limiting factors will be the back pressure at the outlet to the vent line in relation to the hydrostatic head of fluid at the mud outlet of the separator. When the back pressure due to the gas flow is equal to, or greater than, the hydrostatic head available at the mud outlet, the gas will blow through to the shaker header tank. See Figure 1.8. In order to minimise the possibility of a gas blow-through, the vent line should be as straight as possible and have a large ID. The mud outlet should be configured to develop a suitable hydrostatic head (minimum recommended head is 10 feet). See Figure 1.8.

1-31 March 1995

BP WELL CONTROL MANUAL

The back pressure due to the flow of gas should be monitored with a pressure gauge as shown in Figure 1.8. Some warning of the possibility of a gas blow-through will be given when the registered pressure approaches the hydrostatic head of the fluid in the discharge line. It should be noted that the maximum hydrostatic head available may not be that of the mud in the event that large volumes of oil or condensate are displaced to␣surface. If the safe operating limit of the separator is approached, the choke can be closed in (while ensuring that the well is not overpressured) or the flow switched to the overboard line or the burn pit.

GAS OUTLET 8in ID MINIMUM GAS BACK PRESSURE REGISTERED AT THIS GAUGE (Typically 0 to 20psi) STEEL TARGET PLATE INLET INSPECTION COVER

APPROX HEIGHT 1/2 OF

A

SECTION A-A TANGENTIAL INLET

30in OD

A 4in ID INLET-TANGENTIAL TO SHELL FROM CHOKE MANIFOLD BRACE

10ft MINIMUM HEIGHT

INSPECTION COVER

HALF CIRCLE BAFFLES ARRANGED IN A ‘SPIRAL’ CONFIGURATION

TO SHAKER HEADER TANK MAXIMUM HEAD AVAILABLE DEVELOPED BY THIS HEIGHT OF FLUID eg: 10ft HEAD AT 1.75 SG GIVES 7.6psi MAXIMUM CAPACITY 10ft APPROX

8in NOMINAL ‘U’ TUBE

4in CLEAN-OUT PLUG

2in DRAIN OR FLUSH LINE

Figure 1.8 An example Mud Gas Separator – operating at maximum capacity

1-32 March 1995

WEOX02.008

BP WELL CONTROL MANUAL

(b) The degasser The degasser should be lined up at all times during the well control operation. The degasser is designed to remove the small bubbles of gas that are left in the mud after the mud has been through the mud gas separator. It is important that the degasser is working properly and as such it should be tested every tour. While drilling with gas cut returns, the degasser can be checked as follows: 1. Measure actual (gas cut) mud weight at the shaker header box using a non pressurised mud balance. 2. Measure actual mud weight at the degasser outlet using a non pressurised mud balance. If the actual mud weight at the outlet of the degasser is greater than the actual mud weight at the inlet, then the degasser is working. If the mud weight at this stage is not equal to the active system mud weight, then either the degasser is not working properly, or the returns are at a lower weight than the mud in the active system. If the actual mud weight measured at this stage is equal to the active system mud weight, then the degasser is working properly. 3. Measure mud weight at the degasser outlet and the shaker header box using a pressurised mud balance. If the actual mud weight at the outlet of the degasser is equal to the reading on␣the pressurised mud balance, the degasser has removed all the gas from the mud.

(c) Overboard lines/Flare lines It is recommended that a second method of dealing with severely gas cut returns be available at the rigsite, whether on land or offshore. This will generally be either an overboard line, or a flare line to the burn pit on land. It should be easy to switch the returns from the mud system to the flare line. It may be necessary to use the flare line during a well control operation in the following situations: •

The gas flowrate is too high for the mud gas separator.

•

Hydrates are forming in the gas vent line from the mud gas separator.

•

The gas is found to contain H2S.

•

The mud system is overloaded.

Lines that are required to handle high velocity gas must be as straight as possible to minimise erosion. Significant erosion is likely to occur in the path of high velocity gas and solids, therefore the redundancy in flowlines and manifolds downstream of the choke must be analysed on all rigs.

1-33 March 1995

BP WELL CONTROL MANUAL

5 Chemical Stocks (a) Baryte and mud chemical stocks Company policy details the minimum stocks of baryte and mud chemicals that should be held at the rigsite. The policy states that: ‘Sufficient weighting material stocks must be maintained on site such that the entire mud circulating volume can be raised by a minimum of 0.25 SG (See formula in Paragraph 3). Reserve stocks of bentonite or viscosifier must also be on site to enable this increase in mud weight to be effected’. ‘Where transport and logistics are not assured (offshore and remote locations) the minimum onsite weighting material stock must be 100 tonnes’. This is a minimum standard, and as such, the Company Representative may wish to stock a greater quantity of baryte and chemicals.

(b) Cement stocks Cement stocks should not drop below the quantity of cement and additives that will be required to set 2 X 150m of cement plugs in the hole section being drilled. Additionally, in high pressure wells, an abandonment plug recipe should be onsite prior to drilling into the reservoir. Batch mix tanks should also be onsite during the drilling of such reservoir sections.

1-34 March 1995

BP WELL CONTROL MANUAL

1.5 KICK TOLERANCE Paragraph

Page

1

General

1-36

2

Kick Tolerance Calculation Methods

1-36

3

Procedure for Kick Tolerance Calculations

1-37

4

Considerations for High Angle and Horizontal Wells

1-40

5

When to Calculate Kick Tolerance

1-41

6

Excel Kick Tolerance Calculator

1-42

Illustrations 1.9

Kick Tolerance Values Through a Zone of Increasing Pore Pressure

1.10 Excel Kick Tolerance Calculator – Example Calculations

1-43 1-44

1-35 Rev 1 March 1995

BP WELL CONTROL MANUAL

1 General Many definitions of kick tolerance have been used in the drilling industry. Within BP, Kick Tolerance is defined as the maximum volume of kick influx that can be safely shut-in and circulated out of the well without breaking down the formation at the openhole weak point. It is now an accepted part of the Company Casing Design policy to determine the casing setting depth by the Limited Kick Method. It is therefore particularly important that the kick tolerance in critical hole sections be accurately monitored. This section explains how to calculate kick tolerance and when to calculate kick tolerance. In critical hole sections, it is important to calculate kick tolerance on a regular basis. This is because kick tolerance changes as a function of hole depth, BHA geometry, mud weight, formation pressure and influx type, etc.

2 Kick Tolerance Calculation Methods Depending upon how kick tolerance is defined, a number of methods exist for kick tolerance calculations. In general, these methods can be classified into two categories: 1

Simple Methods In these methods kick tolerance calculations are simplified based on several assumptions: •

The kick influx is a “single bubble”.

•

At the initial shut-in condition, the influx is at the bottom of the openhole.

•

The effects of the gas migration, gas dispersion, gas solubility, downhole temperature and the gas compressibility are ignored.

Although these assumptions may seem unrealistic, the simple methods have gained wide acceptance in the drilling industry because they are simple and generally yield conservative (safer) kick tolerance. However these methods have an inherent shortcoming: they do not measure how quickly an influx will grow. This is to say that in some cases formation deliverability may be such that the well could not be shut in before the kick tolerance volume was exceeded. Therefore the same kick tolerance between two wells may not mean that they share the same level of risk ! 2

Computer Kick Simulators In the recent years many sophisticated computer simulators have been developed which can provide a good approximation of kick conditions from the stage when it flows into the wellbore to that when it is circulated out. In the simulations, assumptions used in the simple methods are replaced by mathematical models. Among many other applications, the kick simulators can be used for kick tolerance calculations. They can predict the maximum pressures at any point of the annulus and the results are more accurate and less conservative than using the simple methods. In addition, as simulators can simulate how quickly an influx will flow into the wellbore, they can predict how much time the rig crew have to shut in the well before the influx exceeds the kick tolerance limit. Therefore simulators can be used to provide direct indications in the level of risk involved under various scenarios.

1-36 March Rev 1 1995 March 1995

BP WELL CONTROL MANUAL

However, due to complexity, kick simulators are recommended only in the situations where kick tolerance is considered critical based on the simple methods. Some computer kick simulators are available from the Drilling & Completions Branch, BP Exploration, Sunbury.

3 Procedure for Kick Tolerance Calculations The method illustrated in the following is one of the simple methods. The method calculates the maximum allowable kick influx volume when the well is shut in. The method considers two scenarios: •

When the influx is at the bottom of the hole at the initial shut in condition

•

When the top of the influx has been displaced to the openhole weak point (with the original mud weight)

The following procedure can be used to calculate the kick tolerance: 1

Estimate the safety factor to be applied to the Maximum Allowable Annular Surface Pressure (MAASP) When the influx is displaced from the hole, there will be additional pressures acting in the wellbore. The following are some of the possible causes of such additional pressures during circulation: •

Choke operator error (depending upon the choke’s condition, operator ’s experience,␣etc.)

•

Annular friction pressure (depending on the hole size, mud properties, etc.)

•

Choke line losses (in particular on floating rigs)

The safety factor (SF) to be applied to the MAASP will be the sum of these additional pressures. The drilling engineer must use his/her judgement to determine the most appropriate safety factor. 2

Calculate the Maximum Allowable Annular Surface Pressure (MAASP) Without Breaking Down the Weak Point Formation: MAASP = Pleak – 1.421 x MW x TVD wp – SF (psi) where: MAASP MW Pleak SF TVDwp

Maximum allowable annular surface pressure (psi) Mud weight in hole (SG) Leak-off pressure at the openhole weak point (psi) Safety factor (psi) Vertical depth at the openhole weak point (m)

It should be seen that MAASP is determined based on the consideration of the formation fracturing pressure at the openhole weak point. So it is considered only when there is a full mud column from the weak point to the surface (i.e. the influx is still below the weak point). If lighter fluids (such as a gas influx) occupy the annulus above the weak point, the surface pressure in excess of MAASP may not cause downhole failure. Therefore from the moment the top of an influx has been displaced past the openhole

1-37 Rev 1 March 1995

BP WELL CONTROL MANUAL

weak point, MAASP is no longer a consideration and may be exceeded by a margin which should be determined based on the casing burst strength and the pressure ratings of BOP stack and choke manifold. The method for estimating the position of the influx top is described in Vol.I, Chapter 6, Section 6.1. 3

Calculate the maximum allowable height of the influx in the openhole section:

H max = where: Hmax Gi Pf TVD h 4

MAASP – ( Pf – 1.421X MW X TVD h) 1.421

X

(m)

(MW – Gi)

Maximum allowable height of the influx (m) Influx gradient (SG) Formation pore pressure (psi) Vertical depth of openhole (bit) (m)

Calculate the maximum allowable influx volume that Hmax corresponds to at the initial shut-in conditions Vbh = H max where: Vbh C1 θ bh

x

C1 / cos(θ bh)

(bbl)

Maximum allowable influx volume at initial shut-in condition (bbl) Annular capacity around BHA (bbl/m) Hole angle in the bottom hole section (degree)

If the bottom hole section is horizontal (or above 90 degree), the hole angle used in the calculation should be the openhole angle immediately above the horizontal section. The kick tolerance should be the sum of the calculated volume (Vbh ) plus the annular volume of the horizontal section. In cases where Hmax /cos(θbh ) is greater than the length of BHA, the maximum allowable volume (Vbh) should be calculated partly based on the annular capacity around BHA and partly around drillpipe. 5

Calculate the maximum allowable influx volume that Hmax corresponds to when the top of the influx is at the openhole weak point Vwp = Hmax where: Vwp C2 θwp

x

C2 / cos(θ wp)

(bbl)

Maximum allowable influx volume when top of the influx is at the openhole weak point (bbl) Annular openhole capacity around drillpipe (bbl/m) Hole angle in the openhole section below the weak point (degree)

In cases where Hmax /cos(θwp ) is greater than the openhole drillpipe length below the weak point, the maximum allowable influx volume (Vwp) should be calculated partly based on the annular openhole capacity around drillpipe and partly around BHA.

1-38 March 1995 1995 Rev 1 March

BP WELL CONTROL MANUAL

6

Convert the maximum allowable influx volume at the weak point (Vwp ) to what would be at the initial shut in condition Based on Boyle’s law, the maximum allowable influx volume at initial shut-in corresponding to Vwp will be:

V bh' = V wp X Pleak Pf 7

(bbl)

The actual kick tolerance should be the smaller of Vbh (Step 4) and Vbh' (Step 6) Example: Bit depth: Current hole size: Hole angle: Mud weight in hole: BHA length / OD: Drillpipe OD: Estimated pore pressure at 4000 m: Last casing shoe: Leak-off test EMW: Annular back pressure at SCR: Safety margin for choke operator error:

4000 m 12-1/4" Vertical 1.60 SG 182 m / 8" 5" 1.58 SG 2695 m 1.72 SG 70 psi 150 psi

1. Estimate the safety margin to be applied to MAASP: SF = 70 + 150 = 220 psi 2. Calculate MAASP: Leak-off pressure, Pleak = 1.421 x 1.72 MAASP = 6587 - 1.421

x

x

2695 = 6587 psi

1.6 x 2695 - 220 = 240 psi

3. Calculate the maximum allowable influx height in the openhole section: Pore pressure gradient, P f = 1.421 x 1.58

H max =

240 - (8981 - 1.421X 1.6X 4000)

x

4000 = 8981 psi

= 178m

1.421 X (1.60 - 0.2)

4. Calculate the maximum allowable influx volume at the initial shut-in condition: Annular capacity around BHA, C1= (12.252 - 8 2) / 313.8 = 0.2743 (bbl/m) As the BHA length (182 m) is longer than Hmax (178 m), so the influx is around BHA only when it is at the bottom of the hole. Therefore: Vbh = 178 x 0.2743 = 49 bbl 5. Calculate the maximum allowable influx volume when the top of influx is at the casing shoe: Annular capacity around openhole DP, C2= (12.252 - 5 2) / 313.8 = 0.3985 (bbl/m) Openhole DP length = 4000 - 2695 - 182 = 1123 m ( > H max of 178 m)

1-39 Rev 1 March 1995

BP WELL CONTROL MANUAL

Vwp = 178 x 0.3985 = 71 bbl 6. Convert Vwp to the initial shut-in condition: Vbh' = 71 x 6587 / 8981 = 52 bbl 7. Therefore the actual kick tolerance is 49 bbl.

4 Considerations for High Angle and Horizontal Wells In high angle and horizontal wells, reservoirs are often drilled at a high or horizontal angle with the last casing or liner string set on top of the reservoir. When considering kick tolerance for the reservoir section, it is often the case that the maximum allowable gas height (determined by step 3 in the previous section) extends from the openhole bottom to inside the casing/liner. This implies that the well can tolerate an infinite volume of gas influx without fracturing the openhole weak point. On the other hand, because of the long openhole section through the reservoir in a high angle or horizontal well, the influx volume can be potentially high. So when the influx is circulated to surface, it may fill up the entire annuli of the vertical and low angle sections and result in very high choke pressures at surface. Therefore, the kick tolerance volume in this case should be determined not only by the formation fracture gradient at the openhole weak point but also by the maximum allowable surface pressure based on the casing burst strength and the pressure ratings of the surface equipment. When drilling a high angle or horizontal well, the following procedure should be used to determine the kick tolerance: a. Calculate kick tolerance volume as V1 using the method as described in the previous section (Step 1 through 7) b. Determine the maximum allowable surface pressure Psurf based on the casing burst strength and the pressure ratings of the surface equipment (BOP stack, choke manifold, etc.). Note its difference with MAASP which is based on the formation fracture gradient at the weak point. c Calculate the maximum allowable gas height Hmax when the gas influx top has reached the surface:

H max = where: Gi Pf SF TVD h

(Psurf - SF) - (Pf - 1.421X MW X TVD h) 1.421 X (MW - Gi)

Influx gradient (SG) Formation pore pressure (psi) Safety factor mainly determined by the choke operator error margin (psi) Vertical depth of openhole (bit) (m)

1-40 March 1995 1995 Rev 1 March

BP WELL CONTROL MANUAL

d Calculate the influx volume that Hmax corresponds to when the gas influx top has reached the surface: Vsurf = Hmax x Ccsn

(bbl)

where: Vsurf Ccsn

Maximum allowable influx volume when the influx top reaches surface (bbl) Annular capacity in the casing near surface (bbl/m)

e Convert Vsurf to the corresponding volume at the initial shut-in condition:

V 2 = V surf X f

Psurf

(bbl)

Pf

The actual kick tolerance volume is the smaller of V2 (step e) and V 1 (step␣a).

5 When to Calculate Kick Tolerance Company policy states that: “The kick tolerance of the weakest known point of the hole section being drilled must be updated continuously whilst drilling. If the kick tolerance is less than 50 bbl the Drilling Superintendent must be informed. If the kick tolerance is less than 25 bbl for offshore wells or 10 bbl for land wells, drilling may only continue when dispensation has been given by the Manager Drilling in town.” Kick tolerance will change if there is a change in hole depth, mud weight, formation pressure or BHA. Therefore kick tolerance must be constantly re-evaluated as the well is drilled, not only based on the current condition but also on the future conditions which are expected to occur deeper in the well. The frequency with which the kick tolerance should be re-evaluated is dependent on the nature of the well. However, in hole sections where kick tolerance is likely to be a critical factor, the following guidelines should be considered: •

After LO test, evaluate the kick tolerance at suitable intervals throughout the next hole section with a number of mud weights that are likely to be used.

•

If the hole section contains a zone of rapid pore pressure increase, the kick tolerance should be evaluated frequently based on the anticipated pore pressure.

•

If any factors that affect the kick tolerance (such as mud weight, BHA) change as the section is drilled, the kick tolerance below that point in the section should be re-evaluated.

•

At each stage in the hole section, the Company Representative and the Drilling Engineer must assess the possibility of the pore pressure developing in a manner different to that predicted and hence its effect on the kick tolerance.

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BP WELL CONTROL MANUAL

Figure 1.9 shows an example of the type of calculations that should be worked. The kick tolerance figures shown are those that would typically be calculated before a transition zone. As shown, the current bit depth is 3500 m and the kick tolerance has been calculated at various intervals across the zone of increasing pore pressure. The kick tolerance has been calculated for the mud weight currently in use, for the maximum mud weight anticipated for the section, and intermediate weight. From these figures, it is clear that a serious situation would develop if a kick was taken from the high pressure zone with the mud weight currently in the hole. This might occur if either the pore pressure developed more rapidly than predicted, or if the steady increase in pore pressure was undetected at the surface. The kick tolerance figures for the intermediate mud weight show that even at this weight, the kick tolerance would be small if the high pressure zone was unexpectedly encountered. The kick tolerance is finally calculated at the maximum mud weight. These figures show a final minimum kick tolerance of 50 bbl at that mud weight. The table also shows the kick tolerance if the pore pressure developed higher than predicted of 1.6 SG. In general these figures indicate that drilling should proceed cautiously through the zone of increasing pore pressure. On the basis of these figures, it may be decided to weight up the mud a certain amount before the predicted increase in pressure occurs. The decisions that are made on the basis of kick tolerance figures such as these will be largely dependent upon the particulars of each situation, including the level of confidence placed in the pore pressure prediction.

6 Excel Kick Tolerance Calculator Figure 1.10 is an Excel Kick Tolerance Calculator, which can be activated to calculate the kick tolerance by entering data into green-shaded cells. The kick tolerance volume, together with a range of other parameters, will be displayed automatically. The calculator is based on the same method as described in the previous sections, except that it uses the pressures at the mid-point of the gas influx. So the calculator is slightly less conservative.

1-42 Rev 1 1995 March 1995 March

BP WELL CONTROL MANUAL

Figure 1.9 Kick Tolerance Values though a Zone of increasing Pore Pressure

PORE PRESSURE (psi) 3000

4000

5000

6000

7000

8000

9000

CASING SHOE Maximum Allowable Pressure 13.8ppg EMW

9000

9.2ppg

10,000 DEPTH (ft)

11,000

CURRENT BIT DEPTH MW = 9.6ppg 12,000

9.2ppg 11.3ppg 13.2ppg

13,000

FOR CURRENT MW (9.6ppg) TVD (ft)

MW (ppg)

11,480 12,470 12,630 12,795 12,960 12,990 13,123

9.6 9.6 9.6 9.6 9.6 9.6 9.6

9.2 9.2 10.2 11.3 12.3 12.4 13.2

12,960

9.6

13.2

FOR MUD AT 12ppg TVD (ft)

MW (ppg)

600 600 460 215 30 7 (0)

11,480 12,470 12,630 12,795 12,960

12 12 12 12 12

9.2 9.2 10.2 11.3 12.3

13,123

12

(0)

12,960 13,123

12 12

PORE KTOL PRESSURE (bbl) (ppg)

FOR MUD AT 13.3ppg TVD (ft)

MW (ppg)

600 600 450 246 112

11,480 12,470 12,630 12,795 12,960

13.3 13.3 13.3 13.3 13.3

9.2 9.2 10.2 11.3 12.3

600 600 450 280 153

13.2

10

13,123

13.3

13.2

50

13.2 13.3

10 (0)

13,123 13,123

13.3 13.5

13.3 13.2

35 40

PORE KTOL PRESSURE (bbl) (ppg)

PORE KTOL PRESSURE (bbl) (ppg)

WEOX02.009

1-43 Rev 1 March 1995

BP WELL CONTROL MANUAL

Figure 1.10 Example Calculations using Excel Kick Tolerance Calculator

KICK TOLERANCE CALCULATOR For Vertical, Deviated or Horizontal Wells Version 1.2, March 1995

Example Calculation

Well:

Kick Zone Parameters: 1 2 3 4 5 6 7

UK

Units: (UK/US):

Input Messages:

Openhole Size ? Measured Depth ? Vertical Depth (m) ? Horizontal Length (Angle>87 deg) ? Tangent Angle Above Horizontal ? Min Pore Pressure Gradient ? Max Pore Pressure Gradient ?

(inch) (m) (m) (m) (deg) (sg) (sg)

12.25 4000 4000 0 0 1.580 1.600

(m) (m) (deg) (sg)

2695 2695 0 1.720

Bottom Hole Assembly OD ? Bottom Hole Assembly Length ? Drillpipe OD ? Gas Hydrostatic Pres Gradient ? Pressure Safety Factor ? Mud Weight in Hole ?

(inch) (m) (inch) (sg) (psi) (sg)

8 182 5 0.2 220 1.600

Annular Capacity Around BHA: Annular Capacity Around DP: Fracturing Pres at Weak Point: Max Allowable Shut-in Csg Pres:

(bbl/m) (bbl/m) (psi) (psi)

Min Pore Pressure at Kick Zone: Maximum Allowable Gas Height: Kick Tolerance at Min Pore Pres:

(psi) (m) (bbl)

8981 178 48.7

Max Pore Pressure at Kick Zone: Maximum Allowable Gas Height: Kick Tolerance at Max Pore Pres:

(psi) (m) (bbl)

9094 120 33.0

Non-Horizontal

Weak Point Parameters: 8 9 10 11

Measured Depth ? Vertical Depth ? Section Angle ( 30 deg) No need to complete this section if the well is vertical (or angle 1000psi

VOLUME OF INFLUX = 10.4bbl VOLUME OF INFLUX = 10.4bbl

VOLUME OF SECONDARY INFLUX = 8.1bbl

BHP = 10,000psi T

25 min

BHP DROPS BELOW 10,000psi

BHP = 10,000psi T

25 min

KEY MUD GAS

WEOX02.040

Figure 6.13 Static Volumetric Control – illustrating the consequences of improper procedure 5

Allow choke pressure to build by overbalance margin The choke pressure should be allowed to build by an overbalance margin that may typically be in the range 50 – 200 psi.

6

Allow choke pressure to build by operating margin The choke pressure should be allowed to continue building a further similar amount to provide an operating margin. The total margin will depend on the resultant wellbore pressures at each stage in the operation.

7

Bleed increment of mud from the well at constant choke pressure A suitable volume of mud should be bled from the well to reduce the bottomhole pressure by an amount equivalent to the operating margin.

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BP WELL CONTROL MANUAL

Figure 6.14 Volumetric Control Worksheet – an example for a land rig

VOLUMETRIC CONTROL WORKSHEET For worksheet calculation enter information into shaded cells.

WELL NO

26

RIG

UK

Units (US/UK):

Rig 10

Version 1/1 1Q'95 by ODL/C. Weddle

DATE AND TIME

MUD WEIGHT IN THE HOLE, sg

1.85

15:30

LUBRICATING MUD WEIGHT, sg

HYDROSTATIC PRESSURE PER BARREL OF

1.85

HYDROSTATIC PRESSURE PER BARREL OF

sg MUD in

5

X

sg MUD in

8.5

X

20/08/95

SHEET NO

ANNULUS:

17.46

psi/bbl

ANNULUS:

psi/bbl

HYDROSTATIC PRESSURE PER BARREL OF

sg MUD in

HOLE:

psi/bbl

HYDROSTATIC PRESSURE PER BARREL OF

sg MUD in

HOLE:

psi/bbl

P1

psi

Distance, (m) 3.743701

OVERBALANCE MARGIN: TIME

( hr

200

psi

OPERATION If DP pressure can't be read see page 6-36 of Vol. 1 of BP Well Control Manual

min)

19:00

OPERATING MARGIN: Choke or DP Choke Monitor Pressure (psi)

Change in Monitor Pressure (psi)

150 Hydrostatic of Mud Bled/ Lubricated (psi)

(psi)

Volume of Mud Bled/ Lubricated (bbl)

Time (min) P2

0

0

100

0

200

0

100

19:25

Influx Migrating

1000

150

0

350

0

100

Bleed Mud at Choke

1000

0

-150

200

8.5

108.5

Influx Migrating

1150

150

0

350

0

108.5

Bleed Mud at Choke

1150

0

-150

200

8.5

117

Influx Migrating

1300

150

0

350

0

117

3:30 / 4:45 4.:55 4:55 / 5:30

Bleed Mud at Choke

1300

0

-150

200

8.5

125.5

Influx Migrating

1450

150

0

350

0

125.5

Bleed Mud at Choke

1450

0

-150

200

8.5

134

+ ve increase

- ve decrease

- ve bled

+ ve overbalance

+ ve bled

+ ve lubricated

- ve underbalance

- ve lubricated WEOX02.199

6-44 March 1995

11.2311

Total Volume of Mud (bbl)

200

3:30

20 5

Rate, (mpm)

850

1:35

0

Overbalance

2

Influx Migrating

1:35 / 3:15

0

Migration Rate

19:15

19:25 / 01.25

650

1

1.85

BP WELL CONTROL MANUAL

The choke pressure must be held constant as the mud is bled from the well. As an example (refer to Figures 6.12 and 6.13): Operating margin = 150 psi Annulus = 8 1/2 in. X 5 in. Mud weight = 1.85 SG Hydrostatic equivalent of mud = Therefore bleed

150 17.5

445.7 – 1.85 = 17.5 psi/bbl (72.25 – 25)

= 8.5 bbl of mud

As can be seen from the example in Figure 6.12 the bottom of the influx has had to migrate from 133m off bottom, to 1824m off bottom, whilst bleeding off 8.5 bbl of mud. This could take considerable time. If the operating margin, in this case 150 psi (8.5 bbl), had been quickly bled off and assuming no migration during this period, the bubble would have expanded by only about 0.36/bbl before bottomhole pressure (BHP) dropped to kick zone pressure. This would result in a further influx of 8.14 bbl. Subsequent volumes bled from the well will require less migration distance, ie for an␣increase of bubble size to 27 bbl (after next bleed off), the distance from bottom will be 2395m. 2200

GAS MIGRATING TO SURFACE

PRESSURE BUILDUP

2050 INFLUX MIGRATING 1900

1750

MUD BLED AT CHOKE (at constant choke pressure until volume bled off corresponds to Operating Margin)

CHOKE PRESSURE (psi)

1600

1450

OPERATING MARGIN

1300

1150 OPERATING MARGIN 1000 OPERATING MARGIN 850 OVERBALANCE MARGIN 650 FINAL SHUT-IN ANNULUS PRESSURE

0

8.5

17

25.5

34

42.5

51

59.5

68

76.5

VOLUME OF MUD BLED FROM ANNULUS (bbl)

WEOX02.041

Figure 6.15 Static Volumetric Method – choke pressure used to monitor bottomhole pressure

6-45 March 1995

BP WELL CONTROL MANUAL

8

Continue the process until the influx migrates to the stack This process should be repeated until the influx migrates to the stack. When the influx has migrated to the stack surface pressures should no longer rise as migration will cease to occur. This may not be the case on a floating rig when some migration may occur up the choke line. Use the Volumetric Control Worksheet to record all the relevant data. Figure 6.14 shows a completed example.

9

Lubricate mud into the hole or implement the Dynamic Volumetric Method See Paragraphs 4 and 5. If this process has been implemented because the pipe was off bottom, it may be feasible to circulate the influx out of the hole when the influx has migrated to the bit. See Figure 6.15 for a typical choke pressure schedule for the Static Volumetric Method.

4 Lubrication This technique may be used to vent the influx from below the stack while maintaining constant bottomhole pressure. Lubrication is most suited to fixed offshore and land rigs. It can be used to vent gas from the stack after implementing the Static Volumetric Method, as well as to reduce surface pressures prior to an operation such as stripping or bullheading. Lubrication is likely to involve a considerable margin of error when implemented on a floating rig because of the complication of monitoring the bottomhole pressure through the choke line. When the influx has migrated to the stack it is quite possible that the choke line will become full of gas cut mud. In this situation it is impractical to attempt to maintain control of the bottomhole pressure with the choke. However lubrication is simpler to implement than the Dynamic Volumetric Method. For this reason alone, it may be considered for use on a floating rig. The following guidelines can be used to lubricate mud into a well: 1

Calculate the hydrostatic pressure per barrel of the lubricating mud This is done in the same manner as for the Volumetric Method.

2

Slowly lubricate a measured quantity of mud into the hole Line up the pump to the kill line. Having determined the safe upper limit for the surface pressure, the pump should be started slowly on the hole. Mud should be lubricated into the well until pump pressure reaches a predetermined limit. At this point the pump should be stopped and the well shut in. The well should be left static for a period while the gas migrates through the mud that has been lubricated into the well.

6-46 March 1995

BP WELL CONTROL MANUAL

The exact amount of mud lubricated into the well should be closely monitored. 3

Bleed gas from the well Gas should be bled from the well to reduce the surface pressure by an amount equivalent to the hydrostatic pressure of the mud lubricated into the well. If the surface pressure increased as the mud was lubricated into the well, the amount that the pressure increased should be bled back in addition. Ensure that no significant quantity of mud is bled from the well during this operation. If mud appears at the choke before the surface pressure has been reduced to its desired level, shut the well in and let the gas percolate through the mud. Returns should be lined up through the mud gas separator to the trip tank to ensure that any volume of mud bled back with the gas is recorded and accounted for.

4

Repeat this procedure until all the influx has been vented from the well This procedure should be repeated until all the gas has been vented from the well. It is likely that it will be necessary to reduce the volume of mud lubricated into the well at each stage during this procedure. This is due to the reduction in volume of gas in the well.

If the influx was swabbed into the well and the mud weight is sufficient to balance formation pressures, the choke pressure should eventually reduce to zero. However, if the mud weight in the hole is insufficient, the final choke pressure will reflect the degree of underbalance. It will then be necessary to kill the well.

5 Dynamic Volumetric Control This technique can be used as an alternative to the Static Volumetric Method. However, it should only be used only as a method of safely venting an influx from below a subsea stack, due to both the complexity of the operation and the level of stress imposed on well control equipment during circulation. Experience has shown that the Dynamic Volumetric Method is the most reliable method of venting gas from a subsea stack, if the drillpipe cannot be used to monitor bottomhole pressure. The principle of the procedure is identical to the Static Volumetric Control, however the implementation is considerably different. In this case, circulation is maintained across the wellhead, whilst the surface pressure and pit gain are controlled with the choke. The kill line pressure is used to monitor the well. It is very important that the active tank be a suitable size to resolve very small changes in level. It should be possible to reliably detect changes of the order of one barrel. Having identified that the influx is at the stack, the following guidelines can be used to implement the Dynamic Volumetric Method: 1

Ensure that the kill line is full of mud If there is any possibility that the kill line contains gas, the well should be isolated and the kill line circulated to mud. This will ensure that the pressure at the stack is accurately monitored during the operation.

6-47 March 1995

BP WELL CONTROL MANUAL

2

Circulate down the kill line and up the choke line Ensure that it is possible to monitor the active pit level accurately. Route returns through the mud gas separator.

3

Bring the pump up to speed As the pump is brought up to speed, the kill line (or pump pressure) must increase by an amount equal to the kill line pressure loss. However if it is not possible to compensate for the choke line pressure loss, the kill line pressure will inevitably increase by more than the kill line pressure loss. The kill line circulating pressure will be monitored during the operation to remove gas from the well.

4

Reduce kill line pressure in line with drop in pit level As gas is bled from the well, the pit level will drop while the choke operator adjusts the choke to maintain a constant kill line circulating pressure. This will result in mud being lubricated into the well. If the kill line circulating pressure is held constant as mud is lubricated into the well (as gas is removed), the bottomhole pressure will increase. Therefore, as the pit level decreases, the kill line pressure should be reduced to account for the greater hydrostatic pressure in the annulus. As an example: Drop in pit level = 10 bbl Annulus = 8 1/2 in. X 5 in. Mud weight = 1.85 SG Hydrostatic equivalent of mud = 445.7 X 1.85 (72.25 – 25)

= 17.5 psi/bbl

Therefore reduce kill line circulating pressure by 17.5 X 10 = 175 psi This procedure should be continued until all the influx has been vented from below the stack. This will be indicated by a constant pit level. If the well has been completely killed by removing gas from the stack, the final circulating kill line pressure will be equal to the sum of the kill line pressure loss, the choke line pressure loss and the wide open choke pressure. If the well is not yet completely killed at this point, the final circulating kill line pressure will be greater than this value. See Figure 6.16 for an example kill line pressure schedule for this technique.

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BP WELL CONTROL MANUAL

Figure 6.16 Dynamic Volumetric Method – used to remove gas from below a stack

KILL LINE PRESSURE (psi)

(PIT GAIN TO ALLOW FOR GAS EXPANSION)

GAS IS REMOVED FROM THE WELL, MUD IS LUBRICATED IN

ORIGINAL KILL LINE PRESSURE ONCE PUMP IS UP TO SPEED

SLOPE OF LINE = HYDROSTATIC PRESSURE PER BARREL OF MUD

GAIN IN PIT LEVEL

ORIGINAL PIT LEVEL ONCE PUMP IS UP TO SPEED

DROP IN PIT LEVEL

CHANGE IN PIT LEVEL (bbl) WEOX02.042

6-49/50 6-49 March 1995

BP WELL CONTROL MANUAL

6.2

SPECIAL TECHNIQUES Subsection 2.2

STRIPPING

Paragraph

Page

1

General

6-52

2

Monitoring Well Pressures and Fluid Volumes

6-52

3

Annular Stripping

6-56

4

Annular Stripping Procedure

6-57

5

Ram Combination Stripping

6-59

6

Ram Combination Stripping Procedure

6-61

7

Dynamic Stripping Procedure

6-67

Illustrations 6.17 A Guide to Interpretation of Surface Pressure Changes during Stripping

6-54

6.18 The Effect of the Pipe/BHA Entering the Influx

6-55

6.19 Surge Dampener Fitted to the Closing Line of an Annular BOP

6-57

6.20 Example Stripping Worksheet – showing effect of migration and BHA entering the influx

6-60

6.21 Surface BOP Stack Suitable for Ram Combination Stripping

6-62

6.22 to 6.25 Annular to Ram Stripping

6-63 to 6-66

6.26 Equipment Rig-up for Dynamic Stripping

6-68

6-51 March 1995

BP WELL CONTROL MANUAL

1 General Stripping is a technique that can be used to move the drillstring through the BOP stack when the well is under pressure. Stripping places high levels of stress on the BOPs and the closing unit, and requires a particularly high level of co-ordination within the drillcrew. Company policy is that a contingency plan must be developed regarding stripping procedure for both Company operated rigs and rigs that are under a Company contract. This Section is intended to aid in the drawing up of this contingency plan and as such the following are proposed as the most important considerations: •

How to move the tool joint through the BOP.

•

Wear on BOP elements and the control unit.

•

The level of redundancy in the BOP and the control system.

•

Wellbore pressures in relation to the maximum allowable pressure for equipment and the formation.

•

The monitoring of pressure and fluid volumes.

•

The organisation and supervision of the drillcrew.

•

Controlling increases in wellbore pressure due to surge pressure.

•

The condition of the drillpipe. (Drillpipe rubbers should be removed and any burrs smoothed out.)

•

The possibility of sticking the pipe.

•

The control of influx migration.

•

Manufacturers’ information regarding minimum closing pressures for annular preventers. (This information should be available at the rig site.)

•

The procedure to be adopted in the event that the surface pressure approaches the maximum allowable as the pipe is stripped into the influx.

See Figure 5.2 in Chapter 5 for a decision analysis related to stripping operations.

2 Monitoring Well Pressures and Fluid Volumes During stripping operations, a constant bottomhole pressure is maintained by carefully controlling the surface pressure and the volume of mud bled from or pumped into the well. The equipment required for this operation is described in Chapter 1, ’Instrumentation and Control’.

6-52 March 1995

BP WELL CONTROL MANUAL

Accurate monitoring of the well is required for the following reasons:

(a) To compensate for the volume of pipe introduced into the hole To avoid over pressuring the well, a volume of mud equal to the volume of pipe and tool joints (the volume of metal plus the capacity) introduced into the well, must be bled off. Where possible, mud should not be bled from the well while the pipe is stripped in. It is recommended that mud is bled from the well during each connection. This ensures that there is a clear indication at surface of the BHA entering the influx. However it is recognised that there may be situations when it is impractical to bleed mud from the well at connections. Such situations include: •

If the surface pressures are close to maximum allowable prior to the stripping operation.

•

If a high pressure water kick is taken. In these circumstances the effective compressibility of the fluid in the hole will be low and as such there may be a very large pressure rise as pipe is stripped into the well.

•

If the pipe has to be stripped out of the hole. In this case, there will be a tendency for the volume of metal removed from the well to be replaced by influx fluid.

In these circumstances it may be necessary to implement the dynamic stripping technique.

(b) To compensate for influx migration. To compensate for influx migration, it is necessary to bleed mud from the well. This is in addition to the volume of mud bled from the well when introducing the pipe into the hole. Normally, the required volume of mud will be very small in comparison to the volume bled off to compensate for the introduction of pipe into the hole. Influx migration is indicated by a gradual increase in surface pressure even though the correct volume of mud is being bled from the well (however this may be due to the BHA entering the influx). It is confirmed by increasing surface pressure when the pipe is stationary (See Figure 6.17). Influx migration is controlled by implementing the Volumetric Method.

(c) To allow an increase in surface pressure as the BHA enters the influx. When the BHA is run into the influx, the height of the influx will be considerably increased. This can cause a significant decrease in hydrostatic pressure in the annulus, requiring a greater surface pressure to maintain a constant bottomhole pressure (See Figure 6.18). A potential problem arises if this condition is undetected. The choke operator may continue to bleed mud from the well to maintain a constant surface pressure and inadvertantly cause further influx into the wellbore. It is therefore important to accurately monitor the total volume of mud bled from the well. It is recommended that the potential increase in surface pressure resulting from entering the influx should be estimated before stripping into the hole.

6-53 March 1995

BP WELL CONTROL MANUAL

Figure 6.17 A Guide to Interpretation of Surface Pressure Changes during Stripping

START STRIPPING IN

PRESSURE INCREASES AS PIPE IS STRIPPED IN

CONTINUE STRIPPING

BLEED VOLUME OF MUD EQUAL TO VOLUME OF PIPE STRIPPED

SURFACE PRESSURE DROPS TO ORIGINAL VALUE?

NO

SURFACE PRESSURE DROPS TO VALUE GREATER THAN ORIGINAL

YES NO

CONTINUE STRIPPING

CONTINUE STRIPPING

SURFACE PRESSURE INCREASES WHILE PIPE IS STATIONARY?

HAS THE CORRECT VOLUME OF MUD BEEN BLED FROM THE WELL?

NO

YES

YES

INFLUX IS MIGRATING

PIPE HAS ENTERED INFLUX

BLEED MUD TO COMPENSATE FOR MIGRATION

NO

NO

IS THE PIPE ON BOTTOM?

YES

SURFACE PRESSURE LIMIT APPROACHED?

YES

CIRCULATE OUT TOP OF GAS BUBBLE USING THE DRILLER'S METHOD

KILL THE WELL

WEOX02.043

6-54 March 1995

BP WELL CONTROL MANUAL

Figure 6.18 The Effect of the Pipe/BHA Entering the Influx

1. Start stripping

2.

BHA has entered influx

• • •

KEY GAS INFLUX

MUD

Height of influx in annulus has increased Overall hydrostatic in annulus decreases Surface pressure required to balance formation pressure increases

GAS INFLUX

GAS MUD

MUD

WEOX02.044

6-55 March 1995

BP WELL CONTROL MANUAL

3 Annular Stripping There are two stripping techniques, Annular and Ram combination stripping. The decision analysis presented in Chapter 5, ‘Pipe off Bottom – Drillpipe in the Stack’ outlines the basis upon which the most suitable stripping technique is selected. Annular stripping is considered to be the most satisfactory technique. It involves less risk than ram combination stripping for the following reasons: •

Annular stripping is a relatively simple technique.

•

During annular stripping the only item of well control equipment that is subject to high levels of stress is the annular element.

•

The control system is not highly stressed during the operation (as is the case during ram combination stripping).

•

The annular element can be changed out on a surface stack when pipe is in the hole by inserting a split element.

•

The upper annular preventer, on a floating rig, is the only stack component that is subject to wear and this can be changed without pulling the complete BOP stack.

Ram combination stripping is possible on all types of rig but involves significantly more risk when implemented on a floating rig. The surface pressure is the overriding factor which determines whether or not it will be possible to implement annular stripping. However, it is also necessary to consider that the operating life of an annular element is severely reduced by increased wellbore pressure. Field tests* carried out on Hydril and Shaffer 5K Annulars, show good performance at 800 psi wellbore pressure, but at 1500 psi and above the performance was severely reduced and unpredictable. If surface pressures indicate that annular stripping is not possible, attempts should be made to reduce the pressures in order to enable annular stripping to be used. The most appropriate technique will depend on the position of the influx in the hole. The options are; to circulate out the influx, to lubricate the influx from the well or to bullhead. To ensure that the annular is not subjected to excessive pressures as the tool joint is stripped through the element, a surge dampener must be placed in the closing line (See Figure 6.19). This may not be necessary on a surface stack if the pressure regulator can respond fast enough to maintain a constant closing pressure as a tool joint is stripped through the annular. As a word of caution, some drilling contractors have installed check valves in the control lines to the BOPs; the purpose being to ensure that the BOP stays closed if the hydraulic supply is lost. However, if a check valve is installed in the closing line to an annular BOP, it will not be possible to reduce the closing pressure once the annular has been closed. In order to reduce the annular closing pressure, in this case, it will be necessary to open the annular having closed another ram to secure the well. * Tests carried out by Exxon Prod. Research 1977.

6-56 March 1995

BP WELL CONTROL MANUAL

OPENING LINE

SURGE DAMPENER (precharged to 50% of required closing pressure)

CLOSING LINE

WEOX02.045

Figure 6.19 Surge Dampener Fitted to the Closing Line of an Annular BOP

4 Annular Stripping Procedure Having shut in the well, the following procedure can be used as a guideline for the implementation of annular stripping. 1

Install drillpipe dart Allow the dart to fall until it seats in the dart sub. To check that the dart is functioning properly, bleed off pressure at the drillpipe (restrict volumes bled off to an absolute minimum, typically 1/2 – 1 bbl). If the dart does not hold pressure allow more time for the dart to drop or consider circulating the dart into place (restrict volumes pumped to a minimum). If the dart still does not hold pressure, install a Gray valve in the string.

6-57 March 1995

BP WELL CONTROL MANUAL

2 Monitor surface pressures Surface pressures should be monitored after the well has been shut-in to check for influx migration. If the influx is migrating it will be necessary to implement volumetric control during the stripping operation. If the pipe is off bottom, it will not be possible to identify the type of influx in the usual manner. However, a high surface pressure caused by a relatively small underbalance usually indicates that the influx contains a significant quantity of gas. 3

Determine the capacity and displacement of the drillpipe It will be necessary to bleed mud from the well to compensate for the volume of pipe introduced into the hole. This volume is equal to the sum of the capacity and the displacement of the pipe. There are various tables which outline these quantities, but a reasonable estimation can be made as follows: Displacement and capacity = do2 X 0.003187 (bbl/m) where do = outer diameter of the pipe (in.) Allowance should also be made for the extra volume of metal in the tool joints.

4

Calculate hydrostatic pressure per barrel of mud Should migration occur, it will be necessary to bleed from the well at constant choke pressure to allow the influx to expand. The hydrostatic pressure equivalent of the mud in the hole is calculated as follows: Hydrostatic pressure equivalent = 445.7 X MW (d hc2 – d o2)

(psi/bbl)

where MW = mud weight in the hole (SG) dhc = hole/casing ID (in.) do = drillstring OD (in.) or if the pipe is above the influx: Hydrostatic pressure equivalent = 445.7 X MW dhc 2

(psi/bbl)

For more details on this technique, See Sub-section 2.1 ‘Volumetric Method’ in this chapter. 5

Estimate increase in surface pressure due to BHA entering the influx It is possible to estimate the maximum possible pressure increase due to the BHA entering the influx as follows: Max possible surface = 445.7 pressure increase where MW Gi V dhc do

= = = = =

X

(MW – G i)

V

X

1 – (d hc2 – d o2)

mud weight in the hole (SG) influx gradient, converted to SG (water = 1 SG) volume of influx (bbl) hole/casing ID (in.) BHA OD (in.)

6-58 March 1995

X

1 dhc 2

(psi)

BP WELL CONTROL MANUAL

6

Allow surface pressure to increase by overbalance margin An overbalance of 50 to 200 psi should be maintained throughout the stripping operation. If the influx is not migrating, the overbalance margin can be applied by bleeding a volume of mud that is less than the volume of pipe introduced into the hole, at the start of the operation.

7

Reduce annular closing pressure The BOP manufacturers recommend that the closing pressure is reduced, prior to stripping, until a slight leakage occurs through the BOP. This reduces the wear on the annular by lubricating the element during stripping.

8

Strip in the hole The pipe should be slowly lowered through the annular while the surface pressure is accurately monitored. The running speed should be reduced when a tool joint passes through the annular. Mud should be bled from the well at each connection, unless surface pressure limitations dictate that this should be carried out more frequently. The pipe should be filled with mud at suitable intervals, typically every 5 stands. Use original mud weight. A person should be posted at the Driller’s BOP Control Panel at all times to be ready to shut-in the well in the event of failure of the annular preventer.

9

Monitor surface pressure Surface pressures and all relevant data should be recorded on the Stripping Worksheet. (See Figure 6.20.) Use Figure 6.17 as an aid to the interpretation of changes in surface pressure.

10 Strip to bottom. Kill the well The only sure method of killing the well will be to return the string to bottom and implement standard well kill techniques.

5 Ram Combination Stripping There are two types of ram combination stripping; annular to ram, and ram to ram. Both techniques must be considered if either the tool joint cannot be lowered through the annular or the surface pressure is greater than the rated pressure of the annular and this pressure cannot be reduced to within safe limits. Annular to ram stripping is preferable to ram to ram, unless surface pressures indicate that the annular cannot operate reliably. For both ram combination techniques there is a requirement that: •

There is sufficient space for the tool joint between the two stripping BOPs.

6-59 March 1995

BP WELL CONTROL MANUAL

Figure 6.20 Example Stripping Worksheet – showing effect of migration and BHA entering the influx

STRIPPING WORKSHEET Units (US/UK)

For worksheet calculation enter information in shaded cells. WELL NO

3

RIG

MUD WEIGHT IN HOLE INITIAL BIT DEPTH

Rig 10

uk

Version 1/1 1Q'95 by ODL/C. Weddle

DATE AND TIME

1.75

10/7/87

10:30

LUBRICATING MUD WEIGHT

2000

HOLE DEPTH

SHEET NO

1

1.75

2250

STRIPPING DATA VOLUME OF MUD DISPLACED BY OVERBALANCE MARGIN

5 120

Inch Pipe

Drillpipe

psi

0.0797

bbl/m

:

OPERATING MARGIN

150

psi

2.15

bbl/stand

(Max)

VOLUMETRIC CONTROL DATA HYDROSTATIC PRESSURE PER BARREL OF

SG MUD IN

5

x

8.5

ANNULUS

16.52 psi/bbl

HYDROSTATIC PRESSURE PER BARREL OF

1.75

SG MUD IN

6.5

x

8.5

ANNULUS

26.01 psi/bbl

HYDROSTATIC PRESSURE PER BARREL OF

1.75

SG MUD IN

8.5

HOLE

HYDROSTATIC PRESSURE PER BARREL OF TIME

OPERATION

1.75

1.75

SG MUD IN

Choke or Dp

Change in

Choke

Monitor

Monitor

Pressure

10.80

8.75 HOLE Bit

10.80

Pipe Stripped

Depth

psi/bbl psi/bbl Hydrostatic of Mud Bled/

Overbalance

Lubricated

Volume of

Total

Mud Bled/

Volume

Lubricated

of Mud

Pressure ( hr 10:05

min)

(psi) Well Shut In-Pressures

(psi)

550

(

)

(

)

bbl

2000

(psi)

(psi)

(bbl)

(bbl)

N/A

Stabilized 10:20

Drillpipe Dart Installed

10:30

Strip in Stand No 1

770

120

2000 2027

27

2.2

N/A

120

0

0.0

10:36

Strip in Stand No 2

890

120

2054

54

4.4

N/A

240

0

0.0

10:40

Bleed Mud at Connection

770

-120

2054

54

4.4

N/A

120

2.2

2.2

10:45

Strip in Stand No 3

890

120

2081

81

6.6

N/A

240

0

2.2

10:48

Bleed Mud at Connection

770

-120

2081

81

6.6

N/A

120

2.2

4.4

10:53

Strip in Stand No 4

890

120

2108

108

8.8

N/A

240

0

4.4

10:57

Bleed Mud at Connection

770

-120

2108

108

8.8

N/A

120

2.2

6.6

11:00

Strip in Stand No 5

950

180

2135

135

11.0

N/A

240

0

6.6

8.8

(Assume BHA has entered flux)

11:05

Bleed Mud at Connection

830

-120

2135

135

11.0

N/A

120

2.2

11:10

Strip in Stand No6

1080

250

2162

162

13.2

N/A

240

0

8.8

11:15

Bleed Mud at Connection

960

-120

2162

162

13.2

N/A

120

2.2

11.0

11:20

Strip in Stand No 7

1330

250

2189

189

15.4

N/A

240

0

11.0

11:25

Bleed Mud at Connection

1210

-120

2189

189

15.4

N/A

120

2.2

13.2

11:28

Strip in Stand No 8

1460

250

2216

216

17.6

N/A

240

0

13.2

11:33

Bleed Mud at Connection

1340

-120

2216

216

17.6

N/A

120

2.2

15.4

11:40

Strip in Stand No 9

1590

250

2243

243

19.8

N/A

240

0

15.4

11:45

Bleed Mud at Connection

1470

-120

2243

243

19.8

N/A

120

2.2

17.6

+ve increase

M -ve decrease

- ve bled

+ve

+ve lubricated

overbalance

M

+ ve bled -ve lubricated

NA if bled to

- ve

compensate for pipe

underbalance

WEOX02.197

6-60 March 1995

BP WELL CONTROL MANUAL

•

There is an inlet at the stack between the two BOPs used for stripping.

•

There is a suitable level of redundancy in the stack to ensure the lowest BOP is not used during the stripping operation. API RP 53 (issued 1984) states: “The lowermost ram should not be employed in the stripping operation. This ram should be reserved as a means of shutting in the well if other stack components of the blowout preventer fail. It should not be subjected to the wear and stress of the stripping operation.”

In a critical situation, it may be possible to modify a surface stack to suit these conditions after a kick has been taken. An example surface stack that is suitable for ram combination stripping is shown in Figure 6.21. The risks involved in ram combination stripping can be assessed by considering the following points: •

The high level of drillcrew co-ordination required.

•

The level of stress placed on the BOP elements.

•

The level of stress placed on the BOP control system. (During ram combination stripping, the accumulators are charged to maximum operating pressure and isolated from the BOP. The pumps are used for operational functions.)

•

The possibility of replacing the worn BOP elements during operation.

•

On a floating rig, the reduction in level of redundancy within the subsea BOP stack as the ram preventer is used.

6 Ram Combination Stripping Procedure The following procedure can be used as a guideline for the implementation of annular to ram stripping. The procedure for ram to ram stripping will be similar. (For details of Steps 1 to 6 See ‘Annular Stripping Procedure’) 1

Install drillpipe dart

2

Monitor surface pressures

3

Determine the capacity and displacement of the drillpipe

4

Calculate hydrostatic pressure per barrel of the mud

5

Estimate the increase in surface pressure due to the BHA entering the influx

6

Check ram spaceout To confirm the distance BRT of the two preventers that will be used for stripping.

6-61 March 1995

BP WELL CONTROL MANUAL

Figure 6.21 Surface BOP Stack Suitable for Ram Combination Stripping

ANNULAR

BLIND RAM

FLANGED ACCESS POINT TO STACK FOR USE DURING RAM COMBINATION STRIPPING

PIPE RAM

PIPE RAM

WELLHEAD ACCESS POINT

WEOX02.046

6-62 March 1995

BP WELL CONTROL MANUAL

Figure 6.22 Annular to Ram Stripping – stop stripping in when tool joint is above the annular

MUD

VALVE OPEN

ANNULAR

VALVE CLOSED

BLIND RAM TO PUMP CHOKE

PIPE RAM

PIPE RAM

WEOX02.047

6-63 March 1995

BP WELL CONTROL MANUAL

Figure 6.23 Annular to Ram Stripping – close pipe ram – bleed ram cavity pressure

MUD

VALVE OPEN

ANNULAR

VALVE CLOSED

BLIND RAM PRESSURE BLED OFF AT CHOKE

PIPE RAM

PIPE RAM

WEOX02.048

6-64 March 1995

BP WELL CONTROL MANUAL

Figure 6.24 Annular to Ram Stripping – strip in until tool joint is just below annular

MUD

ANNULAR

VALVE OPEN

VALVE CLOSED

BLIND RAM

PIPE RAM

PIPE RAM

WEOX02.049

6-65 March 1995

BP WELL CONTROL MANUAL

Figure 6.25 Annular to Ram Stripping – use rig pump or cement pump to equalize across pipe ram

MUD

VALVE OPEN

ANNULAR

VALVE CLOSED

BLIND RAM

FROM PUMP

PIPE RAM

PIPE RAM

WEOX02.050

6-66 March 1995

BP WELL CONTROL MANUAL

7

Isolate the accumulator bottles at full operating pressure The accumulators should be kept as back-up in the event of pump failure.

8

Allow the surface pressure to increase by the overbalance margin

9

Reduce annular closing pressure and strip in

10 Stop when tool joint is above annular (See Figure 6.22.) 11 Close pipe ram at normal regulated manifold pressure 12 Bleed ram cavity pressure Before the annular is opened it will be necessary to bleed down the pressure below it. (See Figure 6.23). 13 Reduce ram operating pressure 14 Open annular. Lower pipe 15 Stop when tool joint is just below annular (See Figure 6.24.) 16 Close annular at maximum operating pressure 17 Pressurise ram cavity to equalise across ram (See Figure 6.25.) Do not use wellbore pressure to equalise across the ram. 18 Reduce annular closing pressure 19 Open pipe ram 20 Continue to strip in according to the above procedure. Kill the well Fill the pipe as required.

7 Dynamic Stripping Procedure The situations in which it may be necessary to implement Dynamic Stripping are outlined in Paragraph 2. The purpose of this technique is to maintain constant choke pressure as the pipe is stripped into the hole. This is achieved by circulating at a constant rate across the end of the choke line. A manual choke should be used and the equipment rigged up as shown in Figure 6.26. For this technique to be effective the pump output must be considerably greater than the rate at which the volume of pipe is introduced into the well. If the pump rate is too low, pressure surges will be caused at the choke as the pipe is stripped in, and the choke pressure will fluctuate. The same is true for stripping out of the hole, in which case the choke pressure may drop as pipe is stripped from the well, if the pump rate is too low. This may cause further influx to occur.

6-67 March 1995

BP WELL CONTROL MANUAL

Figure 6.26 Equipment Rig-up for Dynamic Stripping

MUD

VALVE OPEN

ANNULAR

VALVE CLOSED

BLIND RAM

PIPE RAM MONITOR PRESSURE GAUGE

MANUAL CHOKE

PIPE RAM MUD TANK

PUMP

WEOX02.051

6-68 March 1995

BP WELL CONTROL MANUAL

The main problem associated with this technique is that migration and entrance into the gas bubble may not easily be detected at surface. If no allowance is made for these complications, further influx may be allowed to occur. To avoid this, the mud tank levels should be closely monitored to ensure that the levels rise, or drop, in direct relation to the volume of pipe that has been stripped into, or out of, the well. If any discrepancy is noticed, the well should be shut-in and the surface pressures verified. Influx migration should be dealt with using the Volumetric Method. The Dynamic Stripping technique can be used during either annular or ram combination stripping. For annular stripping it is implemented along the following lines: (For details of Steps 1 to 6, See Paragraph 4 ‘Annular Stripping Procedure’) 1

Install drillpipe dart

2

Monitor surface pressures

3

Determine the capacity and displacement of the drillpipe

4

Calculate hydrostatic pressure per barrel of the mud

5

Estimate the increase in surface pressure due to the BHA entering the influx

6

Allow the surface pressure to increase by the overbalance margin

7

Line up the pump to the choke line (See Figure 6.26.)

8

Ensure that the manual choke is fully closed. Open choke line valve(s)

9

Open the manual choke at the same time as the pump is brought up to speed

10 Maintain final shut-in pressure on the choke 11 Reduce annular closing pressure 12 Strip in the hole 13 Monitor surface pressures and pit level If the choke pressure increases significantly as the pipe is stripped into the hole, either reduce the pipe running speed or increase the circulation rate. Use the Stripping Worksheet to record all the relevant data. It is very important to accurately record pressures and mud volumes while stripping. 14 Strip to bottom. Kill the well Fill the pipe as required.

1-69/70 6-69 March 1995

BP WELL CONTROL MANUAL

6.2

SPECIAL TECHNIQUES Subsection 2.3 BULLHEADING

Paragraph

Page

1

General

6-72

2

When to Bullhead

6-72

3

The Important Factors

6-72

4

Procedure

6-73

Illustrations 6.27 Well Shut-in after Production – tubing full of gas prior to bullheading

6-74

6.28 Example Guide to Surface Pressures during a Bullheading Operation

6-75

6.29 Well during Bullheading Operations

6-76

6.30 Well after Bullheading Operations tubing displaced to kill weight brine

6-77

6-71 March 1995

BP WELL CONTROL MANUAL

1 General Bullheading is a technique that may be used in certain circumstances during drilling operations to pump an influx back into the formation. This technique may or may not result in fracturing the formation. Bullheading is however a relatively common method of killing a well during workover operations. This technique is generally used only during workover operations when there is adequate reservoir permeability.

2 When to Bullhead During operations, bullheading may be considered in the following situations: •

When a very large influx has been taken.

•

When displacement of the influx by conventional methods may cause excessive surface pressures.

•

When displacement of the influx by conventional methods would result in an excessive volume of gas at surface conditions.

•

If the influx in suspected to contain an unacceptable level of H2 S.

•

When a kick is taken with the pipe off bottom and it is not considered feasible to strip back to bottom.

•

When an influx is taken with no pipe in the hole.

•

To reduce surface pressures prior to implementing further well control operations.

3 The Important Factors Bullheading during drilling operations will be implemented when standard well control techniques are considered inappropriate. During such situations, it is unlikely that accurate information is available regarding the feasibility of bullheading. In most cases therefore, the likelihood of successfully bullheading an influx will not be known until it is attempted. However, the major factors that will determine the feasibility of bullheading include the following: •

The characteristics of the openhole.

•

The rated pressure of the well control equipment and the casing (making allowance for wear and deterioration).

•

The type of influx and the relative permeability of the formation.

•

The quality of the filter cake at the permeable formation.

•

The consequences of fracturing a section of the openhole.

•

The position of the influx in the hole.

6-72 March 1995

BP WELL CONTROL MANUAL

4 Procedure In general bullheading procedures can only be drawn up bearing in mind the particular circumstances at the rigsite. For example there may be situations in which it is considered necessary to cause a fracture downhole to bullhead away an influx containing H2S. In another situation with shallow casing set, it may be considered totally unacceptable to cause a fracture in the openhole. During a workover operation a procedure for bullheading will be drawn up along the following lines: 1

Calculate surface pressures that will cause formation fracture during bullheading Calculate also the tubing burst pressures as well as casing burst (to cover the possibility of tubing failure during the operation).

2

Calculate static tubing head pressure during bullheading

3

Slowly pump kill fluid down the tubing. Monitor pump and casing pressure during the operation

As an example consider the following well (See Figure 6.27). Well information:

•

Depth of formation/perforations at 3100 m Formation pressure Formation fracture pressure Tubing 4 1/2 in. N80 Vam Internal capacity Internal yield Shut-in tubing pressure Gas density

= = = = = =

1.06 SG 1.66 SG 0.0499 bbl/m 8430 psi 3650 psi 0.1 psi/ft

Total internal volume of tubing = 3100

X

0.0499

(bbl)

= 155 bbl •

Maximum allowable pressure at pump start up = (1.66 X 3100

X

1.421) – (0.1

X

3.2808 X 3100)

(psi)

= 6300 psi •

Maximum allowable pressure when the tubing has been displaced to brine at 1.06 SG = (1.66 – 1.06) X 3100

X

1.421 (psi)

= 2640 psi

6-73 March 1995

BP WELL CONTROL MANUAL

Figure 6.27 Well Shut-in after Production – tubing full of gas prior to bullheading

3650 psi

4 1/2in N80 TUBING

PACKER

PERFORATIONS @ 3100m – 1.06SG FORMATION PRESSURE FORMATION FRACTURE GRADIENT – – 1.66SG

KEY BRINE

VALVE OPEN

GAS

VALVE CLOSED

WEOX02.052

6-74 March 1995

BP WELL CONTROL MANUAL

•

Static tubing head pressure at initial shut-in. = 3650 psi

•

Static tubing head pressure when tubing has been displaced to brine = 0 psi (ie the tubing should be killed)

The above values can be represented graphically (as shown in Figure 6.28). This plot can be used as a guide during the bullheading operation. Figures 6.29 and 6.30 show a schematic of the well at two stages of the operation.

10000

10000 TUBING BURST

9000

9000

SURFACE PRESSURE (psi)

8430 8000

8000

WORKING PRESSURE RANGE DURING BULLHEADING OPERATION

7000

7000 STATIC TUBING PRESSURE THAT WOULD FRACTURE FORMATION

6300 5800

6000

INCLUDING 500psi SAFETY FACTOR (if fracturing is a consideration)

5000

5000 4000

4000 3650 3000

2640 2000

2140

1000

1000

STATIC TUBING PRESSURE TO BALANCE FORMATION PRESSURE

0

0 0

10

20

30

40

50

60

70

80

90

100

110

120

130

140

155

VOLUME OF TUBING DISPLACED (bbl)

WEOX02.053

Figure 6.28 Example Guide to Surface Pressures during a Bullheading Operation

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BP WELL CONTROL MANUAL

Figure 6.29 Well during Bullheading Operations

4000psi 60bbl OF THE TUBING DISPLACED (FROM FIG 6.28, TUBING PRESSURE WITHIN ACCEPTABLE LIMITS) BULLHEAD BRINE

4 1/2in N80 TUBING

PACKER

PERFORATIONS

KEY BRINE

VALVE OPEN

GAS

VALVE CLOSED

WEOX02.054

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BP WELL CONTROL MANUAL

Figure 6.30 Well after Bullheading Operations – tubing displaced to kill weight brine

0psi

4 1/2in N80 TUBING

PACKER GAS TRAPPED UNDER PACKER

PERFORATIONS

KEY BRINE

VALVE OPEN

GAS

VALVE CLOSED

WEOX02.055

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6.2

SPECIAL TECHNIQUES Subsection 2.4

SNUBBING

Paragraph

Page

1

General

6-80

2

Snubbing Units

6-80

3

Selection of a Snubbing Unit

6-82

Illustrations 6.31 Rig Assisted Snubbing Unit

6-81

6.32 Concentric Cylinder Snubbing Unit

6-83

6.33 Multicylinder Snubbing Unit

6-84

6.34 Force Diagram for Snubbing Pipe

6-85

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1 General Snubbing is a technique used to force pipe into a shut-in well when the upthrust due to well pressure makes it impossible to strip the pipe through the BOP under its own weight. Snubbing is relatively common in some areas in workover operations, when the well may be allowed to continue flowing as remedial work is carried out. Snubbing may be considered during drilling operations for well control purposes, either when it is impossible to introduce pipe into a well that is under pressure, or if the rig BOP system is not considered adequate to provide reliable pressure containment during a prolonged stripping operation. A snubbing unit can be used to introduce a range of sizes of pipe into the well. It can be used to snub tubing, drillpipe and even casing in exceptional circumstances. The lowermost components of the snubbing unit are the snubbing BOPs, which are made up to the top flange of the annular preventer on the rig’s stack. This flange is often poorly maintained because it is normally made up to the bell nipple and does not generally need to form a pressure seal. It must therefore be inspected and, if necessary, repaired before the snubbing BOPs are nippled up. The snubbing BOPs are likely to be too tall to fit underneath the rotary table and too wide to go through it. To overcome this problem, the snubbing company can provide suitable spacer riser sections to bring the assembly above the rig floor. The weight of the snubbing unit is supported by the wellhead. Guy lines from the work platform prevent lateral movement. Snubbing units can therefore be rigged up on land rigs and fixed offshore installations in a relatively straightforward manner. Snubbing units are not commonly used on floating rigs, however they have been used successfully in the past for well control operations. In order to use a snubbing unit on a floating rig, pressure containment must be established between the rig BOP and the unit on the rig floor. Drillpipe or tubing may provide this pressure containment, in which case small diameter tubing may be run into the well through the drillpipe or tubing. An operation of this type can only be carried out in relatively calm seas so that the rig heave does not cause excessive movement of the snubbing unit.

2 Snubbing Units (a) The Rig Assisted Type The rig assisted unit uses the travelling blocks to generate the snubbing force through a series of pulleys and cables. (See Figure 6.31.) The rig assisted unit can handle larger diameter pipes such as casing up to 13 3/8 in. and have snubbing capacities of 80,000 lb to 400,000 lb. These were the first snubbing units used and the few that are currently available are operated by Otis and Cudd Pressure Control.

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BP WELL CONTROL MANUAL

Figure 6.31 Rig Assisted Snubbing Unit

TRAVELLING BLOCK

BALANCE WEIGHT

TRAVELLING SNUBBERS

SNUB LINE

STATIONARY SNUBBERS

PLATFORM

STRIPPING OR SNUBBING PREVENTERS

PUMP INLET

SAFETY PREVENTERS

WELL PRESSURE WEOX02.056

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BP WELL CONTROL MANUAL

The unit consists of a set of travelling snubbers which are connected to the travelling block. The travelling snubbers grip the pipe and force it into the well as the blocks are raised. A set of stationary snubbers grip the pipe while the travelling snubbers are being raised (by the counter balance weights) for a new bite on the pipe. Once sufficient pipe has been run to reach the balance point, the travelling snubbers will be removed and the pipe will be run in by conventional stripping.

(b) The Hydraulic Self Contained Type Hydraulic snubbing units are the most common type available. They are completely self contained and can be used either inside the derrick or when there is no rig on location. There are two different types of hydraulic unit available, these being: •

The concentric cylinder unit (See Figure 6.32) for snubbing capacities up to 30,000 lb and for pipe up to 5 1/2 in. OD.

•

The multicylinder type (See Figure 6.33) for snubbing capacity up to 150,000 lb and for pipe up to 7 5/8 in. OD.

The units are operated from the work platform which is on top of the hydraulic jack assembly. From this position the speed of the pipe and the slips are controlled as can be the rotary table, if required. Stationary and travelling slips are operated in sequence to grip the pipe as it is snubbed into the well. One operator will control the BOPs and equalising valves. Another operator will co-ordinate the pipe handling, using the counter balance system.

3 Selection of a Snubbing Unit The following are the criteria that should be used to determine the most suitable unit for a given application: •

Snubbing Force This is the force that the unit must exert to push the pipe into the hole. The snubbing force will be a maximum for the first joint of pipe and decrease gradually as the weight of the pipe in the hole increases in normal conditions.

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Figure 6.32 Concentric Cylinder Snubbing Unit

WORKBASKET WITH CONTROLS

TRAVELLING SLIPS (CLOSED)

TRAVELLING SLIPS (OPEN)

PISTON

STATIONARY SLIPS (CLOSED)

STATIONARY SLIPS (OPEN)

ACCESS WINDOW STATIONARY SLIPS (OPEN)

SNUBBING UNIT BLOWOUT PREVENTER STACK

KEY HYDRAULIC CONTROL FLUID WELL PRESSURE

PISTON EXTENDED AND TRAVELLING SLIPS CLOSED PRIOR TO FORCING PIPE INTO WELL

PISTON RETRACTED AND TRAVELLING SLIPS OPEN BEFORE PISTON IS AGAIN EXTENDED

WEOX02.057

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BP WELL CONTROL MANUAL

Figure 6.33 Multicylinder Snubbing Unit

POWER TONGS BOP CONTROL PANEL CONTROL PANEL COUNTERBALANCE WINCH

WORK PLATFORM TRAVELLING SLIPS

FOUR OPERATING CYLINDERS

TELESCOPING MAST

STATIONARY SLIPS

WINDOW – for stripper bowl or annular BOP

SPOOL HANGER FLANGE

PUMP INLET SNUBBING UNIT BLOWOUT PREVENTER STACK

WEOX02.058

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BP WELL CONTROL MANUAL

The snubbing force is calculated as follows: – Snubbing force, Fs = F p + Ff – (w a – Ly X 3.281) – (wb X L z X 3.281) where Fp = Pw – Ao (See Figure 6.34) where F s Fp Ff wa wb Ly Lz Ao

= = = = = = = =

required snubbing force (lb) force due to well pressure (lb) frictional force (lb) weight of pipe (lb/ft) buoyant weight of pipe (lb/ft) length of pipe above BOP to the travelling snubber (m) length of pipe in the hole (m) outside cross sectional area of pipe (in.2)

COMPRESSION FORCE Fs POINT OF APPLICATION OF TRAVELLING SNUBBERS

Fs

wa Ly

Ff PIPE

(SNUBBING UNIT STROKE)

SNUBBING BOP

Ff (wa)(Ly) wb

Pw

Lz

WELLBORE

Fp Fp

(wb)(Lz)

Equilibrium Equation (from ∑ Forces = 0) Therefore: Fs = Fp + Ff – (wa) (Ly) – (wb) (Lz) Where

Fs Fp Ff wa wb Ly Lz

= required snubbing force (lb) = force due to well pressure (lb) = frictional force (lb) = weight of pipe (lb ft) = bouyant weight of pipe (lb ft) = length of pipe above BOP to the travelling snubber (m) = length of pipe in the hole (m)

WEOX02.059

Figure 6.34 Force Diagram for Snubbing Pipe

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BP WELL CONTROL MANUAL

– Snubbing force for the first joint of pipe. In this case, the length of pipe in the hole (Lz) is zero, and the length of pipe above the BOP is considered insignificant. Consider the following example: The well is shut in with a wellhead pressure of 5000 psi. 2 7/8 in. tubing produces a frictional force of 3000 lb at the stripping rams. The area of pipe exposed to the wellbore pressure therefore equals 6.492 in. Snubbing force, F s = Fp + F f = (6.492 X 5000) + 3000

(lb)

= 35,460 lb – The snubbing force, Fs, if there is already some pipe in the hole. In this case the length of the pipe above the BOP is again considered insignificant. As an example: 2 7/8 in. tubing of 6.5 lb/ft is run empty to 1000 metres in 1.2 SG mud. The wellhead pressure is 5000 psi. Drag in the hole is 2000 lb, friction at the BOPs is 5000 lb. Ai Ao wi wo wa wb D

= = = = = = =

internal cross sectional area area of pipe (in.2 ) outside cross sectional area area of pipe (in.2 ) weight of fluid inside the pipe (SG) weight of fluid in annulus (SG) weight of pipe in air (lb/ft) buoyant weight of pipe (lb/ft) depth of tubing (m)

wb = wa + (w i X Ai) – (wo X Ao) wb = 6.5 + (O X Ai) – (1.2

X

62.4 X 6.492) 144

(lb/ft)

wb = 3.12 lb/ft Therefore the snubbing force is given by: Fs = Fp + Ff – (wa X Ly) – (w b X L z) Fs = (6.492 X 5000) + 2000 + 5000 – (3.12

X

1000 X 3.281)

(lb)

= 29,200 lb •

Size of the Unit The dimensions of the unit must be checked against the internal dimensions of the derrick, if the unit is to be used with a rig on location.

•

Lifting Force The unit must be able to provide a reasonable overpull, over and above the weight of the maximum string weight.

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•

Tubular Selection If there is already pipe in the hole, this will determine the most suitable type of pipe to be used. Drillpipe can be used, however the following points should be considered: – Drillpipe will require a relatively high snubbing force because of its large crosssectional area at the tool joints. – Drillpipe does not have gas-tight connections. – The drillpipe must be in good condition and inspected thoroughly before running in. Tubing is more commonly used for snubbing for the following reasons: – The force required to snub it in is very much less, and the unit required corresponding smaller. – External flush tubing can be run through the stripper rubbers without the need for sequencing the rams. The following points must also be considered: – The limitations imposed by the ID of the tubing on the maximum pump rate. – External upset tubing will be slower to run, but will be easier to control, if it starts to be forced out of the well. – Premium connections are desirable because they are gas tight. – The collapse strength of the tubing. – The susceptibility of the tubing to failure due to buckling.

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6.2

SPECIAL TECHNIQUES Subsection 2.5 BARYTE PLUGS

Paragraph

Page

1

Characteristics of Baryte Plugs

6-90

2

Deflocculation

6-92

3

Pilot Tests

6-92

4

Slurry Volume

6-92

5

Pumping and Displacement Rate

6-93

6

Preparation of a Baryte Plug

6-93

7

After Pumping a Baryte Plug

6-93

8

Baryte Plug Procedure

6-94

Illustrations 6.35 Field Mixing of Baryte Plugs

6-91

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BP WELL CONTROL MANUAL

1 Characteristics of Baryte Plugs (a) Hydrostatic Kill Since baryte settling is inherently slow and since the results of settling are quite unpredictable, the use of a settling recipe should not be a dominant factor in designing a well control operation. In general, the goal in using a baryte kill slurry should be the same as with any other kill weight mud – achieving a hydrostatic kill. Three factors contribute to achieving a hydrostatic kill: the density of the fluid, the volume of the fluid, and the rate at which the fluid is pumped. The density and volume of the kill weight mud must be high enough to control the formation, and the pump rate during the kill must exceed the influx rate by sufficient margin so that the kill weight mud is not blown out of the wellbore. The properties of the fluid pumped should be chosen with these three factors in mind. The ideal kill weight mud would be inexpensive and simple to mix and handle over a wide range of densities. Deflocculated baryte slurries fit this description except that the settling of the baryte can be a problem in surface handling and pumping.

(b) Bridging effect It has been suggested that a baryte plug can stop unwanted flow by a bridging effect and that achieving a hydrostatic kill is not necessary. Some field experiences support this view; there are cases where a well has stopped flowing after being treated with a small baryte plug. Nonetheless, it is imprudent to rely on baryte bridging when attempting to kill a well. Laboratory tests show clearly that even very low gas volumes (0.01 Mcf/d at bottomhole conditions) can flow through a settling baryte plug. This fact, as well as field experience, shows that the bridging action of a baryte plug is not dependable. For this reason, the design of a baryte plug should be based on achieving a hydrostatic kill. The strength of the settled baryte is another significant factor in well control. Laboratory tests show that the strength of a settled baryte plug is quite variable. Settled baryte can appear rock-solid when pushed hard and yet move slowly out of the way of a persistent gently force. This behaviour is actually a well understood property of deflocculated cakes. A baryte plug can fail unexpectedly if a hydrostatic kill condition is not maintained.

(c) Settling/Non-settling Since baryte settling is of little value downhole and troublesome on the surface, it should be an optional feature of the slurry recipe. Figure 6.35 shows two recipes for baryte slurries. The recipes are identical except that one contains XC polymer to eliminate baryte settling. It would seem reasonable to use the settling recipe for small jobs or where the settling baryte might really be helpful downhole. For large kill operations, the non-settling recipe would be preferred. Bentonite or some polymer other than XC could be used to suspend the baryte in a slurry. The particular recipe in Figure 6.35 was selected because it is prepared easily in both fresh and seawater and because XC solutions are shear-thinning enough to allow good pumpability while adequately suspending the baryte in the pits.

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BP WELL CONTROL MANUAL

Figure 6.35 Field Mixing of Baryte Plugs

(a) For use with water based muds 1. Prepare mix water equal to 54 percent of final volume of slurry required. Recipes below are for one barrel of mix water: •

Setting recipe 1 bbl water (fresh or sea) 15 lb lignosulphonate 2 lb/bbl of caustic (pH = 10.5 to 11.5)

•

Non-setting recipe 1 bbl water (fresh or sea) 15 lb lignosulphonate 1 lb XC polymer Defoamer (octanol or other) 2 lb/bbl of caustic (pH = 10.5 to 11.5)

2. Add baryte to mix water to prepare final slurry. For 1 bbl of 2.5 SG slurry, mix 0.54 bbl mix water 700 lb baryte

(b) For use with oil based muds 1. Prepare mix oil equal to 47 percent of final volume of slurry required. Recipes below are for one barrel of mix oil: •

Setting recipe 1 bbl base oil 1.5 US gal oil wetting agent

•

Non-setting recipe 1 bbl base oil 4 lb organophilic clay 1.5 US gal oil wetting agent

2. Add baryte to mix oil to prepare final slurry. For 1 bbl of 2.5 SG slurry, mix 0.54 bbl mix water 700 lb baryte

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Baryte-plug-type slurries can be prepared with all of the baryte substitutes which are now on the market. In general the recipes in Figure 6.35 do not require change except that, in some cases, the higher density of the substitue allows higher slurry weights than were possible with baryte. For example, hematite slurries can be prepared to 3.00 SG using the non-settling recipe in Figure 6.35. Replace the baryte with 870 lb hematite per final bbl of slurry. The non-settling recipe is strongly recommended for hematite slurries because of the relatively coarse grind of oil-field hematite.

2 Deflocculation For years it has been standard practice to add a thinner to baryte slurries used for well control. Both lignosulphonates and phosphates have been used, with the phosphate SAPP having the widest acceptance. Chemicals of either type can deflocculate a baryte slurry to improve pumpability and allow settling into a firm cake. The choice of deflocculant will influence the baryte slurry properties as follows: •

Use of SAPP gives a slurry with fairly high fluid loss (50cc). SAPP will not deflocculate in sea water or in the presence of some contaminants which occur in natural baryte.

•

Use of lignosulphonate gives a slurry with low fluid loss (5cc). Lignosulphonate is effective in sea water and tolerates both contamination and elevated temperatures.

Use of a high fluid loss baryte slurry is advantageous, possibly because it might dehydrate and plug the wellbore, or promote, perhaps, hole instability. On the other hand, a low fluid loss slurry would reduce the chances of differential sticking. Faced with this choice, prudence suggests using the more reliable lignosulphonate rather than the somewhat unpredictable SAPP. The recipes in Figure 6.35 contain lignosulphonate.

3 Pilot Tests Because of variation and possible contamination of ingredients throughout the world, it is always advisable to pilot test a baryte slurry. Prepare a sample of the slurry using the recipe chosen and the ingredients at the wellsite. After being stirred well, the sample should have the expected density and be easily pumpable. If the baryte needs to settle in the wellbore, this should also be checked ahead of time. Reasonable settling is 2 in. in a mud cup after a 15 minute wait. The settled cake should be hard and somewhat sticky rather than soft and slippery. The settling test is not a guarantee that the baryte pill will form an effective plug under downhole conditions, but will certainly give an indication of the settling characteristics.

4 Slurry Volume Slurry volumes depend upon the amount of openhole and the severity of the kick. These volumes normally range from 40 bbl to 400 bbl. The slurry volume should be 125 to 150 percent of the annular capacity necessary to give the height of plug desired, but should not be less than 40 bbl. If a second baryte plug is required, the slurry volume should be greater than the first.

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5 Pumping and Displacement Rate Baryte plugs should always be pumped with the drillpipe close to the bottom of the hole. If there is any significant volume of mud under the baryte slurry then the baryte slurry will mix with the mud because of the large differences in density. If the influx zone is somewhat above the bottom of the hole, then the baryte slurry should be pumped to bottom and then above the influx zone far enough to provide the desired hydrostatic kill height. A baryte plug should be pumped and displaced at a rate somewhat higher than the kick rate. If the kick rate is unknown, a reasonable rate (5 to 10 bbl/min) should be used for the first attempt although very large blowouts can ultimately require kill weight mud placement at greater than 50 bbl/min.

6 Preparation of a Baryte Plug For field preparation of either a settling or non-settling baryte slurry, it is best to prepare the mix water first and then add baryte to the desired density. The equipment needed on location to prepare and pump a baryte plug is a cementing unit equipped with a high pressure jet in the mixing hopper, a means of delivering the dry baryte to the cementing unit, and sufficent clean tankage for the mix water so that the lignosulphonate and caustic soda can be mixed in advance. The non-settling slurry may be recirculated through the mixing hopper several times if necessary to obtain a particular weight; service companies are reluctant to recirculate settling baryte slurries through their equipment. It is possible to weight-up to 2.5 SG in one pass provided the mix water is fed to the hopper␣at 600 to 1000 psi. Hopper nozzles and feed rate should be selected to give this pressure drop. Settling-type baryte slurries may only be stored in ribbon blenders or similar equipment which provide continuous, thorough agitation. Non-settling slurries may be stored in standard␣mud tanks although even these slurries may drop out a few in. of baryte per day if not stirred. The baryte slurry may be pumped into the drillpipe either through a cementing head or␣through the standpipe and kelly . In either case, the pump tie-in to the drillpipe should contain provisions for hooking up both the cementing unit pump and the rig pump so that either can be used to displace the slurry. If this is not done, and the cementing unit breaks down, the baryte may settle in the drillpipe before the mud pump tie-in can be made or the cementing unit repaired. Blockage of the drillstring by baryte settling will complicate the well control problem.

7 After Pumping a Baryte Plug Baryte plugs may be used in a variety of situations, it is not possible to give one fixed␣procedure which will always work. There will always be a need for local decisions and good judgement. This is especially true in deciding what to do after a baryte plug has been pumped.

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The decision after placing a baryte plug is whether to pull pipe or not. The goal of pumping a high-density slurry is to achieve a hydrostatic kill; the decision whether to pull pipe depends on an assessment of the success of this kill. If a hydrostatic kill was probably achieved then it is usually best to pull up above the slurry and try circulating mud. If there is doubt about the hydrostatic kill it may be better to stay on bottom to be ready to pump a larger baryte plug if needed. The risk in pulling out is that the pipe may become stuck off bottom or may have to be stripped back to bottom if the baryte plug fails. The risk of staying on bottom is that the pipe may become stuck or plugged. It is possible to keep the pipe free by moving it (especially in a non-settling plug) but there is no way to circulate (to avoid plugging) unless the pipe is pulled above the top of the baryte slurry.

8 Baryte Plug Procedure (a) Leave Pipe in Place 1

Mix and pump the slurry at the appropriate rate Monitor the slurry density with a densometer in the discharge line or a pressurised mud balance. Displace the slurry immediately at the same rate.

2

Overdisplace the slurry by 5 bbl to clear the drillstring Continue to pump 1/4 bbl at 15 min intervals to keep the drillstring clear.

3

Verify that underground flow has stopped A noise log may be used. It is more definitive than temperature logs. Temperature surveys can be used in addition or if the noise log is not available. If temperature surveys are used, wait 6 to 10 hr for the temperatures to stabilise. The survey will show a hotter than normal temperature in the zone of lost returns. Wait another 4 hr, run a second survey. If the underground flow has stopped, the temperature in the lost returns zone will have decreased.

4

After it has been determined that the flow is stopped, bullhead a cement slurry through the bit to provide a permanent seal Observe the annulus during the pumping. If the casing pressure begins varying appreciably, or if a sudden change in the pumping pressure occurs, the baryte plug may have been disturbed. Overdisplace the cement to clear the drillstring. Additional cementing to obtain a squeeze pressure might be desirable.

5 Plug the inside of the drillstring The cement in step 4 can be underdisplaced, but a wireline bridge plug set near the top of the collars is preferred. Cement should be dump bailed on the wireline bridge plug for additional safety. 6

Pressure test the inside plug

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7

Perforate the drillstring near the top of the baryte plug. Attempt to circulate It may be difficult to tell whether the well is circulating or flowing from charged formations. Pressure communication between the drillpipe and annulus is one clue; a pressure increase should have appeared on the drillpipe from annulus pressure or on the casing from hydrostatic pressure in the drillpipe when the perforation was␣made. Consideration should be given to circulating with lighter mud because of the known lost returns zone. •

Well will circulate: – Use drillpipe pressure method to circulate annulus clear of formation fluid. – Run a free-point log. – Begin fishing operations.

•

Well will not circulate: – Squeeze cement slurry through perforation. Cut displacement short on final stage to provide an interior plug or set wireline bridge plug. WOC and pressure test plug. – Run free-point log. – Perforate the pipe near the indicated free point. – Circulate using drillpipe pressure method until annulus is clear. If well will not circulate, squeeze perforations with cement or set a wireline bridge plug above perforations and perforate up the hole.

(b) Pull Out of Plug (High Pressure, Low Permeability Formation) 1

Mix and pump the slurry Monitor the slurry weight with a densometer in the discharge line or a pressurised mud balance. If mixing is interrupted for any reason, immediately begin displacement of the slurry using either the cement unit pumps or the rig pumps. Work the pipe while pumping and displacing.

2

Displace the slurry with mud at the same rate Cut the displacement short by 2 or 3 bbl to prevent backflow from the annulus. If a non-ported, drillpipe float is in the drillstring, overdisplace the slurry.

3

Immediately begin pulling the pipe It may be necessary to strip the pipe through the annular preventer. Pull at least one stand above the calculated top of the baryte slurry.

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4

Monitor the annulus •

If no pressure is on the annulus, continue working the pipe, and observe annulus mud level. – If the annulus is full, begin circulating at a low rate keeping constant watch on pit levels. – If the annulus is not full, fill annulus with water and observe. If annulus will stand full, begin circulating at a slow rate. Consider cutting mud weight, if feasible.

•

If pressure is on the annulus, circulate the annulus using normal well control techniques. Continue working the pipe. – If returns become gas-free, the baryte plug was successful and the well is dead. – If returns do not become essentially gas-free after circulating two or three annular volumes, the baryte plug was not effective. A second plug will be necessary.

5

Trip out of the hole after verifying that the well is dead If the bottom part of the hole is being abandoned, then a cement plug should be placed on top of the baryte.

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6.2

SPECIAL TECHNIQUES Subsection 2.6 EMERGENCY PROCEDURE

Paragraph

Page

1

Use of Shear Rams

6-98

2

Dropping the Pipe

6-99

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1 Use of Shear Rams Shear rams can be used to cut drillpipe and then act as a blind ram in order to isolate the drilling rig from the well. Shearing the pipe is a technique that will be required only in exceptional circumstances. The use of the shear rams can be considered in the following situations: •

In preference to dropping the pipe in the event of an uncontrollable blowout up the drillstring (an internal blowout).

•

When it becomes necessary to move a floating rig off location at short notice.

•

When there is no pipe in the hole, the shear rams can be used as blind rams.

Most shear rams are designed to shear effectively only on the body of the drillpipe. Procedures for the use of shear rams must therefore ensure that there is no tool joint opposite the ram prior to shearing. Be aware that many subsea stacks have insufficient clearance between the top pipe rams and the shear rams to hang off on the top rams and shear the pipe. Specialist shear rams, such as the Cameron Super Shear Rams, are available that are designed to shear 7 in. drillcollars and casing up to 13 3/8 in. OD. It is clearly important however, that rigsite personnel are aware of the capabilities and operating parameters of the shear rams installed in the rig’s BOP stack. Optimum shearing characteristics are obtained when the pipe is stationary and under tension. It is therefore recommended practice that the pipe weight is partially hung off prior to shearing. Hanging the pipe off also ensures that there is no tool joint opposite the shear rams. Maximum operating pressure should be used to shear the pipe. The following procedure can be used as a guideline for shearing the pipe in the case of an internal blowout: 1

Space out to ensure that there is no tool joint opposite the shear rams

2

Close the hang-off ram

3

Hang off on the rams Ensure that the pipe above the hang-off rams remains in tension.

4

Prepare to operate the shear rams

5

Close the shear rams at maximum accumulator pressure

6

Monitor the well. Implement appropriate control procedures

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2 Dropping the Pipe Situations in which it will be necessary to drop the pipe will be extremely rare. Dropping the pipe is an emergency procedure and as such it is a procedure that will only be required as a last resort when the safety of the rig and personnel is threatened. Situations that may require the pipe to be dropped include: •

If an internal blowout occurs on a rig that has no shear rams.

•

If an internal blowout occurs when the drillcollars are in the stack.

•

As an alternative to the use of shear rams in the event of an internal blowout when drillpipe is in the stack.

•

If the pipe is pushed out of the hole under the influence of wellbore pressure.

•

If a BOP develops a leak and there is no back-up available.

Once the pipe has been dropped the well is shut-in with the blind/shear rams. However, re-establishing control of the well in this situation will be time consuming and costly. It is clearly important to be sure that the pipe will clear the stack once it has been dropped (especially on a floating rig in deep water). The possibility of damaging the ram packings must also be considered. There are two techniques that can be used to drop the string:

(a) Unlatch the elevators 1

Lower the string until the elevators are at a manageable distance from the␣floor

2

Ensure that the BOP is closed at maximum operating pressure

3

Attach a tugger line to the elevators

4

Clear the floor

5

Open the choke line to bleed down surface pressure

6

Open the elevators

7

Open the BOP. Allow the string to drop

8

Close the blind/shear ram

9

Close the choke

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(b) Back off a tool joint 1

Set the slips

2

Break a tool joint. Ensure that the joint can support the weight of the string

3

Pull the slips

4

Run the joint below the rotary

5

Set the slips

6

Ensure the BOP is closed at maximum closing pressure

7

Open the choke line to reduce the surface pressure

8

Turn the rotary to the left to back off the joint

9

Open the BOP and allow the pipe to drop

10 Close the blind/shear ram 11 Close the choke Both of these techniques involve a certain amount of risk. The most suitable method in each case will depend on the particular conditions at the rigsite.

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BP WELL CONTROL MANUAL

6.3 COMPLICATIONS Paragraph

Page

1

Plugged Bit Nozzle

6-102

2

Plugged Choke

6-102

3

Cut Out Choke

6-102

4

Pump Failure

6-103

5

Pressure Gauge Failure

6-103

6

String Washout

6-103

7

Stuck Pipe

6-104

8

Well Control Considerations in Horizontal Wellbores

6-104

9

Hydrates

6-105

10

Surface Pressures Approach the MAASP

6-109

11

Impending Bad Weather

6-110

12

Loss of Control

6-111

13

Well Control Considerations in Slim Hole Well

6-111

Illustrations 6.36 Temperature at which Gas Hydrates will Freeze (Katz)

6-106

6.37 Natural gas expansion – Temperature reduction curve (NATCO)

6-107

6.38 Height of 10 bbl Gas Influx in Annulus

6-113

6.39 Reduction in Bottom Hole Pressure Due to 10 bbl Gas Influx

6-114

6.40 Annular Friction Pressure Drop

6-115

6.41 Swab Pressure in a 1000 m Hole

6-116

6-101 March 1995

BP WELL CONTROL MANUAL

1 Plugged Bit Nozzle A plugged nozzle in the bit is indicated by an unexpected increase in drillpipe pressure with little or no change in the choke pressure. The choke operator may be tempted to open the choke in an attempt to reduce the drillpipe pressure to the original circulating pressure. This will result in a drop in choke pressure and a corresponding drop in bottomhole pressure. Therefore should a plugged bit nozzle be suspected, the pump should be stopped, the well shut-in and the pump restarted to establish the increased standpipe pressure that will maintain a suitable bottomhole pressure. An increase in drillpipe pressure could also be caused by the hole packing off around the BHA. This would be likely to cause increased, though fluctuating, circulating pressures. The drillstring should be reciprocated in order to clear this problem. If the bit becomes totally plugged, this will cause an abrupt and continually increasing drillpipe pressure, with little or no change in choke pressure. In this event, if increased drillpipe pressure does not clear the problem, the string must be perforated as close as possible to the bit in order to re-establish circulation. It is good practice, especially in critical hole sections, to run a circulating sub above the bit or above a core barrel.

2 Plugged Choke A plugged choke is indicated by an unexpected increase in choke pressure accompanied by an equal increase in drillpipe pressure. Some plugging of the choke is to be expected if the annulus is loaded with cuttings. Clearly the first course of action is to open the choke in an attempt to both clear the restriction in the choke and to avoid overpressuring the well. If this action is not successful the pump should be stopped immediately. After switching to an alternate choke the excess pressure in the well should be bled at the choke and the displacement restarted in the usual manner. One of the reasons for displacing a kick at slow circulation rates is to avoid overpressuring the well if cuttings plug the choke. In this respect, circulation rates should be minimised in critical conditions if the annulus is likely to contain a substantial volume of cuttings.

3 Cut Out Choke A choke is unlikely to suddenly cut out. In this respect, there will not be any dramatic indication that this problem is occurring. As a choke wears it will become necessary to gradually close it in to maintain circulating pressure. If the operator finds that he has to gradually close in the choke to maintain circulating pressure, the first reaction should be to check the pit volume to ensure that lost circulation is not occurring.

6-102 March 1995

BP WELL CONTROL MANUAL

Having established that there is no loss of circulation a worn out choke should be suspected. There may come a stage when it is no longer possible to maintain a suitable circulating pressure even with the choke apparently fully closed. At, or preferably before this stage, the flow should be switched to another choke and repairs effected to the worn choke.

4 Pump Failure The most obvious indicator of failure at the fluid end is likely to be erratic standpipe pressure together with irregular rotary hose movement. This may be preceded by an unexplained drop in circulating pressure. If pump failure is suspected, the pump should be stopped and the well shut-in. The displacement should be continued with the second rig pump, or if necessary, the cement pump. The faulty pump should be repaired immediately.

5 Pressure Gauge Failure Every effort should be made to ensure that all pressure gauges are working correctly, and that back-up gauges are available in the event of failure of a pressure gauge during a well control operation. Should gauge failure occur during a well control operation it is important that the defective gauge be replaced as quickly as possible. If no back-up gauge is immediately available, stop the operation and shut in the well.

6 String Washout A washout in the drillstring may be indicated by an unexpected drop in standpipe pressure, while the choke pressure remains unchanged. The recommended procedure in the event of a drillstring washout is to stop the pump and shut the well in. Every effort must be made to ensure that the washout is not enlarged by extended circulation and drillstring manipulation. The most critical situation would be in the event of a washout close to the surface. Should this occur, it is unlikely that it will be possible to displace the influx from the hole effectively, unless the influx is above the washout. If the washout is identified as being near the bottom of the well, it may be possible to displace the kick from the well effectively. In this case, there will of course be the risk of parting the drillstring with continued circulation. Regardless of the depth of the washout, it will be necessary to re-establish the correct circulating pressure if the pump is restarted. Excessive downhole pressures may be caused if the original circulating pressure is maintained at the standpipe. It is advisable to periodically re-establish the circulating pressure, if the circulation is contained for prolonged periods through a washout.

6-103 March 1995

BP WELL CONTROL MANUAL

7 Stuck Pipe The complication of stuck pipe during a well control operation can cause serious problems, most especially if the pipe is stuck off bottom. Unfortunately, the likelihood of the pipe becoming stuck during a well control operation is increased if the pipe is off bottom. The pipe should be rotated, to minimise the risk of sticking the pipe, if the well is shut-in with the pipe off bottom and the BHA in openhole. Due to the relatively high wellbore pressures during a well control operation, the most likely cause of stuck pipe is differential sticking. However, mechanical sticking may result if the hole sloughs and packs-off as a result of the contact with the influx fluids. If the pipe is differentially stuck with the bit on bottom, continue the operation because it is most likely that circulation can still be carried out in order to kill the well. Efforts to free the pipe can be made once the well has been killed. Should the pipe be differentially stuck with the bit off bottom, the situation is complicated in that it will generally not be possible to reduce the wellbore pressure at that depth by circulation. It may be possible to free the pipe by spotting a freeing agent. However, if the influx was swabbed in, it may be possible to regain control of the well by volumetric control. If the pipe is mechanically stuck, a combination of working the pipe and spotting a freeing agent can be used in attempting to free the pipe.

8 Well Control Considerations in Horizontal Wellbore Well control procedures in horizontal wellbores use the same basic principles as those for vertical or deviated holes. Downhole equivalent mud weights are calculated using the true vertical depth, as always. There are however several additional points to consider, these are as follows: •

The purposes of drilling a horizontal well are to improve hydrocarbon recovery and to maximise the area of reservoir exposed at the wellbore, in order to maximise production rates. It must therefore be considered that influx flowrates, in the event of a kick, will be considerably greater than for a well drilled vertically through the reservoir. Particular attention must be paid to tripping procedures when the reservoir is exposed.

•

It is possible that shut-in pressures in the event of a kick will be identical on both drillpipe and annulus, although a large influx has been taken; this would depend on the length of the horizontal openhole section. This is not a problem, however it does mean that it is not possible to check the validity of kick data. The possibility that the wellbore contains a large influx should therefore be addressed in such circumstances.

6-104 March 1995

BP WELL CONTROL MANUAL

•

There is a greater potential for swabbing when a large surface area of reservoir is exposed. Correct tripping procedure must be rigorously adhered to. It is quite feasible, in a horizontal well, that the horizontal section is full of reservoir fluid and yet the well be dead. It is therefore recommended that extreme caution be paid when tripping back into such a reservoir after a round trip. When back on bottom it is recommended to circulate bottoms up through the choke manifold. In the event of a kick whilst tripping it may not be possible to drop or pump down the dart. This will depend on the hole angle at the dart sub position. If it is not possible to install the dart into the dart sub, the ‘Gray’ valve can be used.

9 Hydrates Natural gas hydrates have the appearance of hard snow and consist of chemical compounds of light hydrocarbons and liquid water. They are formed at temperatures above the normal freezing point of water at certain conditions of temperature and pressure (See Figure 6.36). This formation process is accelerated when there are high gas velocities, pressure pulsations or other agitations, such as downstream of a choke and at elbows, which cause the mixing of hydrocarbon components. During well control operations, gas hydrates may cause the following serious problems: •

Plugging of subsea choke/kill lines, preventing opening and closing of subsea BOPs, sealing off wellbore annuli and immobilising the drillstring. There have been recorded incidences of such occurrences with subsea stacks in water depths of 350m and deeper.

•

Plugging of surface lines at and downstream of the choke or restriction. This is particularly hazardous when high gas flowrates are experienced through low pressure equipment (such as the poorboy separator and gas vent line). The formation of hydrate plugs under these conditions can rapidly overpressure low pressure well control equipment.

The major factors which determine the potential for hydrate formation are gas composition, liquid content and pressure and temperature. The formation of hydrates can be predicted using Figure 6.36. It should be noted that the conditions for hydrate formation can be created at a subsea stack operating in a cold water environment. Figure 6.37 can be used to predict the temperature drop associated with a pressure drop (across a choke, for example). As an example, if gas at 3000 psi and 90°F was choked to 1800 psi, the temperature would be expected to drop to 55°F, in which case, hydrate formation could be expected.

6-105 March 1995

BP WELL CONTROL MANUAL

Figure 6.36 Temperature at which Gas Hydrates will Freeze (Katz)

The purpose of this chart is to determine the temperature below which hydrates will form, when sufficient liquid water is present.

4000

3000

1000

NE

HA

900 800

ET

M

700 600 500

400

AV

R

6

0.

G

300

7

0.

0.

8

PRESSURE FOR HYDRATE FORMATION (psia)

2000

200

9

1.

0

0.

100 90 80 70 60

35

40

45

50

55

60

65

70

75

80

85

TEMPERATURE (°F)

Example: With 0.7 specific gravity gas at 1000psia, hydrates may be expected at 64°F. At 200psia this would be 44°F.

WEOX02.061

6-106 March 1995

GAS TEMPERATURE (°F)

0

10

20

30

40

50

60

70

80

90

100

110

120

130

140

0

6

0 50 00

60

00

50

1000

00

55

00

45 00

40 00

35 00 30

2

00

15

0

0 20

MP

2000

0 50

TE

D

ET

CO

0

ES

SU

R

OP

PRESSURE (lb/in )

3000 2

S VE

4000

HYDRATE EXPECTANCY DEGREES FAHRENHEIT

R ED

R CU S PY GA L A T TH U F EN 0 C T 0 N 0 TA U/1 NS BT

0

50

DU

00

10

P RO

R OP

INITIAL TEMP RISE

150

00

70

105° - 80° = 25°

160

NATURAL GAS EXPANSION – TEMP REDUCTION CURVE BASED ON 7 SP GR GAS (From NATCO)

5000

EXAMPLE REQUIRED: REDUCE GAS PRESSURE FROM 2400 # PSI AT 80°F TO 1500 # PSI DETERMINE INITIAL TEMPERATURE RISE NECESSARY SO THAT AFTER EXPANSION TO 1500 # PSI THE FINAL TEMPERATURE WILL BE 75°F

BASE LINE

0

10

20

30

40

50

60

70

80

90

100

110

120

130

140

150

160

BP WELL CONTROL MANUAL

Figure 6.37 Natural Gas Expansion – Temperature reduction curve (NATCO)

WEOX02.062

6-107

March 1995

BP WELL CONTROL MANUAL

Hydrates can be combated by one or a combination of the following: •

Injecting antifreeze agents such as methanol into the gas flow; this has the effect of dissolving liquid water deposits, and thus lowering the temperature at which hydrates would be expected to form. Methanol is often injected at the subsea test tree during well testing operations from a floating rig. The most appropriate place to inject methanol at surface is at the choke manifold. The point of injection should be upstream of the choke. High pressure chemical injection pumps (as manufactured by Texsteam) are suitable for this application.

•

Heating the gas above the temperature at which hydrate will form. During gas well testing operations, a steam exchanger will usually be provided for this purpose. Experience has shown that this is the most effective and reliable method of preventing the formation of hydrates. The combination of heating and antifreeze injection is ideal.

•

Reducing line pressure in order to allow the hydrates to melt. This is a temporary measure and not always practical. Once hydrates have formed, it often takes a considerable length of time to clear the line.

It is important that adequate contingency is provided, along the above lines, to deal with hydrates, if it is suspected that the potential exists for hydrate formation. Subsea water temperatures and pressures should be checked as well as the potential for hydrate formation at surface in the event of a gas kick.

10 Surface Pressures Approach the MAASP The MAASP is defined as the maximum allowable annular surface pressure. Bearing in mind the method that is used to calculate its value (i.e. assuming that MAASP is calculated from LO Test result), it is clear that the MAASP is a consideration only when there is a full column of mud from the openhole weak point to the surface. Surface pressures in excess of the MAASP therefore may not cause downhole failure if lighter fluids (such as a hydrocarbon influx) occupy the annulus above the openhole weak point. Consequently, during a well control operation, from the moment that the top of an influx is displaced past and above the openhole weak point, the MAASP is no longer a consideration and may be exceeded. In the event that surface pressures exceed the MAASP when the kick is still below the openhole weak point, consequently causing excessive downhole pressures, there are two distinct options: •

Hold the choke pressure so as to maintain bottomhole pressure equal to, or slightly greater than, the kick zone pore pressure.

•

Reduce the choke pressure and limit it to the MAASP.

6-108 March 1995

BP WELL CONTROL MANUAL

The consequences of overpressuring the openhole weak point as in the first option can be assessed, bearing in mind the following factors: •

The depth of the casing shoe.

•

The quality of the cement job.

•

By how much the openhole weak point will be overpressured.

•

The length of time that the openhole weak point will be overpressured.

•

The characteristics of the openhole weak point.

•

Any safety factor included in the calculation of the MAASP.

•

The possibility of broaching around the casing.

The consequences of underbalancing the formation as in the second option can be assessed, bearing in mind the following factors: •

The type of kick zone fluid.

•

The permeability of the kick zone.

•

The degree of underbalance.

•

The length of time that the kick zone will be underbalanced.

The appropriate course of action should therefore be selected on the basis of these factors. However, in general, a kick zone should only be underbalanced in exceptional circumstances such as when the zone is known to have low permeability. This can often be assessed from the rate of pressure build after shutting in a well that has kicked.

11 Impending Bad Weather Bad weather is most likely to cause serious problems as regards well control on offshore␣rigs. For example, it may not be possible to offload baryte supplies or remove excess personnel in bad weather. On a floating rig, a critical situation is reached should it become necessary to unlatch the riser during a well control operation. In this situation it will not be possible to monitor the well and hence control the migration of the influx, should this occur. Should weather conditions deteriorate with very little warning, the following procedure can be implemented: 1

Attempt to bullhead the influx back to the formation

2

Displace the drillstring to kill weight mud

3

Close lowermost pipe rams (in addition to the hang-off rams). Shear the pipe rams

4

Prepare to unlatch, monitoring wellbore pressures until it becomes necessary to unlatch

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BP WELL CONTROL MANUAL

If additional time is available, consideration should be given to spotting a heavy pill or plug on bottom to either kill the well hydrostatically or provide a barrier to migration. Bad weather may cause problems regarding the supply of chemicals and barytes to all types of rigs. In this respect, it may be necessary to implement the Driller’s Method, should there not be adequate chemical stocks at the rigsite. In certain areas of the world, severe cold may cause operational problems. Points of particular concern are, BOP operating fluid, manifolds and flowlines.

12 Loss of Control Loss of control during a well control operation may result from excessive loading of pressure control equipment or exposed formations. However there are recorded incidents of equipment failure at pressures significantly below rated values. These failures have been attributed to faulty manufacture, lack of proper maintenance, or corrosion. High pressure equipment is considered particularly susceptible to failure when exposed to corrosive fluids such as H2 S. It is not possible to detail specific procedures in the event of loss of control during a well control operation. However, in critical situations, action should be taken bearing in mind that the absolute priority is the safety of rigsite personnel.

13 Well Control Considerations in Slim Hole Well A slim hole is commonly defined as one in which 90% or more of the length of the well is drilled with drill bits less than 7" in diameter. A well with hole sizes smaller than those in a conventional well is also broadly considered as a slim hole well. Whilst the immediate difference between a conventional well and a slim hole well is their hole sizes, other major characteristics of a slim hole include the practice of long sections of continuous coring and the requirements of higher drillpipe rotary speeds, lower weights on bit, lower mud flow rates and special mud systems. So a slim hole well requires significant changes in the well design, well operation and the well control procedures.

(a) Slim Hole Characteristics In terms of well control, a slim hole well has the following characteristics when compared with a conventional well: •

Greater Influx Length Due to the reduced annular size in a slim hole, the same volume of formation influx will occupy a longer section of the annulus in a slim hole well than in a conventional well. As shown in Fig.6.38, a 10 bbl influx occupies 66 m long annulus in a conventional 8.5"x5" well and 523 m long in a 3.5"x2.5" slim hole well.

6-110 Rev 1 March March 1995 1995

BP WELL CONTROL MANUAL

•

Greater Bottom Hole Pressure Reduction As the result of the greater influx length, the same volume of formation influx will result in a greater reduction in the bottom hole pressure in a slim hole well. As␣shown in Fig.6.39, a 10 bbl gas influx will reduce the bottom hole pressure by about 743 psi in a 3.5"x2.5" slim hole well and only 94 psi in a conventional 8.5"x5" well.

•

Higher Annular Friction Pressure Also due to the reduced annular size, the annular friction pressure drop can be many times higher in a slim hole well than in a conventional well, as shown in Fig.6.40. Therefore the friction pressure drop can become significant during well control operations in a slim hole well whereas it is all but ignored in the case of a conventional well.

•

Higher Swab and Surge Pressures Fig.6.41 compares the swabbing pressure in both slim hole and conventional wells. It can be seen that the swabbing pressure is much higher in a slim hole well than in a conventional well. Also the swabbing pressure increases more rapidly in a slim hole well with increasing the trip speed.

•

Effect of High Drillpipe Rotational Speed During a slim hole drilling operation, the drillpipe is often rotated at a much higher rate than that during a conventional drilling operation. Due to the high rotational speed together with the small annular size, the drillpipe rotation can result in a significant increase in the annular friction pressure and the ECD. This effect must be taken into account in the well control procedures. Otherwise, the weak formation may be broken down when the drillpipe starts to rotate, or a kick influx be induced when rotation stops (whilst still maintaining circulation).

(b) Kick Detection System As described above, a small volume of influx can occupy a long section of the annulus in a slim hole well and thus greatly reduce the bottom hole pressure. This will cause the influx flow to intensify continuously. As the result, a kick can develop more rapidly in a slim hole well than in a conventional well. Therefore it is important to be able to detect a kick at a very early stage during a slim hole well operation. Although the basic principles in the kick detection technique remain the same for slim holes, the sensitivity of the detection system must be enhanced. The basic requirements for a slim hole kick detection system are: •

The system must be able to detect a small volume of pit gain (typically 1 or 2 bbl). This technique is most reliable when the influx flow is slow (low kick intensity).

•

The system must be able to detect the difference between the mud flow in and out of the well (typically 25 gpm). When the influx flow is fast, this technique is more sensitive and reliable than the pit volume detection technique.

•

The system must be able to detect a kick whilst making a connection. The high annular friction pressure creates a high ECD during drilling ahead. So the most likely time for a kick to occur will be when the pumps are shut down to make a connection.

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BP WELL CONTROL MANUAL

(c) Well Kill Technique As the annular friction pressure is small in a conventional well, it is used as a safety factor during the well kill operation to ensure that the bottom hole pressure stays slightly above the formation pressure. So the annular friction pressure is usually ignored in the conventional well control calculations. In a slim hole well however, the annular friction pressure may be so high that when used as a safety factor, it will break down the formation at the weak point and cause lost circulation. Therefore a decision that must be made when drilling a slim hole is whether the␣ c onventional well kill technique can be applied. This can be made in the following␣steps: •

Estimate the annular friction pressure at the slow circulating rates and add this to the maximum static pressure (i.e. the sum of the mud hydrostatic pressure and the surface casing pressure) at the weak point in the wellbore.

•

Compare the total wellbore pressure with the breakdown pressure at the weak point. Will lost circulation be likely?

•

If lost circulation is unlikely, the conventional well control technique can be applied. Otherwise the slim hole well control technique must to be used.

(d) Slim Hole Well Control Manual This section briefly summarises the key differences in well control for slim holes. A BP Slim Hole Well Control Manual is available that details the principles and procedures for kick prevention, kick detection, well shut-in and the well kill technique for slim holes. The manual can be obtained from the Drilling and Completions Branch, BP Exploration, Sunbury.

6-112 Rev 1 March March 1995 1995

Reduction In BHP (osi) 1.0 sg Mud

1 0 400

8.5 x 5

66

94

8.5 x 5

10

6 x 4.5

199

283

6 x 4.5

3.5 x 2.5

523

743

3.5 x 2.5

Height of Gas Influx (m)

Gas Influx Height (m)

10

200

Friction Pressure (psi) Brine: 4.0 cPMud: PV=15/YP=10 13.8 31.2

523 m

199 m 0

66 m 8.5 x 5

6 x 4.5 Size of Annulus (inch)

3.5 x 2.5

41

128.6

68.9

254.3

BP WELL CONTROL MANUAL

6-113

Annular Size (inch)

Figure 6.38 Height of 10 bbl Gas Influx in Annulus

Figure 6.38a: Height of 10 bbl Gas Influx in Annulus Gas Influx 600 Volume (bbl)

Rev 1 March March 1995 1995

(1.0 SG Density Difference Between Mud and Gas) 800

254.3

Reduction in BHP (psi)

6-114

128.6

400

743 psi

200 283 psi 0

94 psi 8.5 x 5

6 x 4.5 Size of Annulus (inch)

3.5 x 2.5

BP WELL CONTROL MANUAL

Mud: PV=15/YP=10 31.2 600

Figure 6.39 Reduction in Bottom Hole Pressure Due to 10 bbl Gas Influx

March Rev 1 March 1995 1995

Figure 6.38b: Reduction in Bottom Hole Pressure Due to 10 bbl Gas Influx

swab pressures

200 Brine: 4.0 cP

150

sec/std

Mud: PV=15/YP=10

129

100 50 0

31.2

41

13.8 8.5 x 5

6 x 4.5 Size of Annulus (inch)

8.5/5 300 250 200 150 100 50 40 30 25 20 15

6/4.5 40.9 41 41.3 68.9 41.7 42.5 44.8 46.2 3.5 x 2.5 48.3 55 58.8 64.8

3.5/2.5 45.8 46 46.3 48.8 47.8 50.9 52.5 55.1 66.4 92.2 147

90 90.8 92.1 94.2 98.5 110 117.7 128.4 168 238 368

BP WELL CONTROL MANUAL

6-115

Friction Pressure Drop (psi/1000m)

254 250

Swab Pressure (psi/1000m)

Height of Ga (m)

(Mud Annular Velocity = 150 ft/min)

300

Figure 6.40 Annular Friction Pressure Drop

Figure 6.38c: Annular Friction Pressure Drop

Rev 1 March March 1995 1995

Reduction in (psi)

(Mud: 1.0 SG, PV=15 cP, YP=10 lbf/100sqft) 300

3.5"x2.5"

6-116

90 90.8 92.1 94.2 98.5 110 117.7 128.4 168 238 368

Swab Pressure (psi/1000m)

3.5/2.5

1 8 08 . 5 / 5 6.0"x4.5" 120 8.5"x5.0" Annulus

60 0 90

60

30

Trip Speed (sec/30m std.)

0

BP WELL CONTROL MANUAL

240

Figure 6.41 Swab Pressure in a 1000 m Hole

March 1995 1995 Rev 1 March

Figure 6.38d: Swab Pressure in a 1000 m Hole

BP WELL CONTROL MANUAL

Volume 2 – Contents Nomenclature Abbreviations 1 THE ORIGINS OF FORMATION PRESSURE Section

Page

1.1

INTRODUCTION

1-1

1.2

NORMAL FORMATION PRESSURE

1-9

1.3

SUBNORMAL FORMATION PRESSURE

1-11

1.4

ABNORMALLY HIGH FORMATION PRESSURE

1-17

1.5

SHALLOW GAS

1-33

2 FORMATION PRESSURE EVALUATION Section 2.1

INTRODUCTION

2-1

2.2

FORMATION PRESSURE EVALUATION DURING WELL PLANNING

2-5

FORMATION PRESSURE EVALUATION WHILST DRILLING

2-25

FORMATION PRESSURE EVALUATION AFTER DRILLING

2-69

2.3 2.4

March 1995

BP WELL CONTROL MANUAL

3 PRIMARY WELL CONTROL Paragraph 1 GENERAL

3-2

2 HYDROSTATIC PRESSURE

3-2

3 EQUIVALENT MUD WEIGHT, EMW

3-2

4 CIRCULATING PRESSURES AND ECD

3-4

5 CALCULATING THE CIRCULATING PRESSURE LOSSES

3-7

6 SWAB AND SURGE PRESSURES

3-10

7 SWAB AND SURGE CALCULATIONS

3-12

4 FRACTURE GRADIENT Paragraph 1 GENERAL

4-2

2 STRESSES IN THE EARTH

4-2

3 FRACTURE ORIENTATION

4-3

4 FRACTURE GRADIENT PREDICTION

4-4

5 DAINES’ METHOD OF FRACTURE GRADIENT PREDICTION

4-4

6 AN EXAMPLE PRESSURE EVALUATION LOG

4-7

7 LEAK OFF TESTS

4-9

8 LEAK OFF TEST PROCEDURE

4-10

9 INTERPRETATION OF RESULTS

4-11

March 1995

BP WELL CONTROL MANUAL

5 BASICS OF WELL CONTROL Paragraph 1 GENERAL

5-4

2 DISPLACING A KICK FROM THE HOLE

5-4

3 FACTORS THAT AFFECT WELLBORE PRESSURES

5-9

4 SUBSEA CONSIDERATIONS

5-20

5 SAFETY FACTORS

5-25

6 CALCULATING ANNULUS PRESSURE PROFILES

5-29

6 WELL CONTROL EQUIPMENT Section 6.1

WELLHEADS

6-1

6.2

BLOWOUT PREVENTER EQUIPMENT

6-5

6.3

CONTROL SYSTEMS

6-43

6.4

ASSOCIATED EQUIPMENT

6-57

6.5

EQUIPMENT TESTING

6-67

March 1995

BP WELL CONTROL MANUAL

NOMENCLATURE SYMBOL

DESCRIPTION

UNIT

A a An b c C Cp Ca CL CR D Dshoe Dwp dbit dh dhc do di dcut dc F Fsh FPG g G

Cross sectional area Constant Total nozzle area Constant Constant Annular capacity Pipe capacity Cuttings concentration Clinging constant Closing ratio Depth Shoe depth Depth of openhole weak point Bit diameter Hole diameter Hole/casing ID Pipe OD Pipe ID Average cuttings diameter Drilling exponent (corrected) Force Shale formation factor Formation Pressure Gradient Gravity acceleration Pressure gradient

Gi H Hi Hp ITT K L λ MR M m MW

Influx gradient Height Height of influx Height of plug Interval Transit Time Bulk modulus of elasticity Length Rotary exponent Migration rate Matrix stress Threshold bit weight Mud weight

in.2 – in.2 – – bbl/m bbl/m % – – m m m in. in. in. in. in. in. – lb – SG – psi/ft psi/m SG psi/ft m m m µsec/m

March 1995

m – m/hr psi lb SG

BP WELL CONTROL MANUAL

SYMBOL

DESCRIPTION

UNIT

N OPG P

Rotary speed Overburden Pressure Gradient Pressure

∆P Pa ∆Pbit Pcl Pdp Pf Pfrac Pfc Pi Pic Plo Pmax

S Sg Sw t

Adjustment pressure Annulus pressure Bit pressure drop Choke line pressure loss Drillpipe pressure Formation pressure Fracture pressure Final circulating pressure Hydrostatic pressure of influx Initial circulating pressure Leak off pressure Maximum allowable pressure at the openhole weak point Wide open choke pressure Pore pressure Slow circulating rate pressure Plastic Viscosity Flowrate Mud flowrate Gas flowrate Reynolds number Resistivity Resistivity of water Rate of Penetration Shale factor Overburden pressure Gas saturation Water saturation Time

rpm SG psi/SG (The units of subsurface pressure may be either psi or SG) psi psi psi psi psi psi/SG psi/SG psi psi psi psi/SG

TR T

Transport Ratio Temperature

TD TVD V

Total Depth True Vertical Depth Kick tolerance

Poc Pp Pscr PV Q Qmud Qgas Re R Rw ROP

psi/SG psi psi/SG psi cP gal/min gal/min gal/min – ohm-m ohm-m m/hr meq/100g psi Fractional Fractional seconds min – degrees C, F, R m m bbl

March 1995

BP WELL CONTROL MANUAL

SYMBOL

DESCRIPTION

V

Volume

v vmud vp vs W

w

w wb wcut WOB x YP Z µ ν σ’1 σ’t Ø Ø600 β ρ ρb

March 1995

UNIT

bbl cc ml l Velocity m/min m/s Mud velocity m/min Average pipe running speed m/min Slip velocity m/min Weight gm kg lb Weight lb/ft lb/bbl SG Weight of pipe lb/ft Baryte required for weighting up lb/bbl Average cuttings weight SG Weight on Bit lb Offset () Yield Point lb/100ft2 Compressibility factor – Viscosity cP Poissons’s Ratio – Maximum effective principle stress psi/SG Tectonic stress psi/SG Porosity Fractional Fann reading lb/100ft2 Tectonic stress coefficient – Density SG Bulk density SG

BP WELL CONTROL MANUAL

ABBREVIATIONS ASN BHA BHC BHT BGG BRT CDP CEG CG DE DIL DRG DST ECD EMW ES FDC FIT HCR ID ITT LMRP MWD OD PV RFT RMS ROP SLS TD TG UV WOB YP

Amplified Short Normal Bottomhole Assembly Borehole Compensated Tool Bottomhole Temperature Background Gas Below Rotary Table Common Depth Plot Cation Exchange Capacity Connection Gas Drilling Engineer Dual Induction Laterolog Designated Resident Geologist Drillstem Test Equivalent Circulating Density Equivalent Mud Weight Electrical Survey Formation Density Compensated Tool Formation Interval Tester High Closing Ratio Internal Diameter Interval Transit Time Lower Marine Riser Package Measurement while Drilling Outside Diameter Plastic Viscosity Repeat Formation Tester Root Mean Squared Rate of Penetration Long Spacing Sonic Tool Total Depth Trip Gas Ultra Violet Weight of Bit Yield Point

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BP WELL CONTROL MANUAL

1 THE ORIGINS OF FORMATION PRESSURE Section

Page

1.1 INTRODUCTION

1-1

1.2 NORMAL FORMATION PRESSURE

1-9

1.3 SUBNORMAL FORMATION PRESSURE

1-11

1.4 ABNORMALLY HIGH FORMATION PRESSURE

1-17

1.5 SHALLOW GAS

1-33

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BP WELL CONTROL MANUAL

1.1

INTRODUCTION

Paragraph

Page

1

General

1-2

2

Subsurface Pressures

1-2

3

Pressure Seals

1-6

4

Pressure Gradients

1-7

Illustrations 1.1 1.2

Composite Overburden Load for Normally Compacted Formations

1-4

Schematic Diagram of Subsurface Pressure Concepts

1-5

Types of Formation Pressure Seals

1-6

Tables 1.1

1-1 March 1995

BP WELL CONTROL MANUAL

1 General All formations penetrated whilst drilling a well exert pressures of varying magnitudes. To gain an understanding of the origins of these pressures, it is neccesary to define and explain certain subsurface pressure concepts. These are explained in this Section.

2 Subsurface Pressures (a) Hydrostatic Pressure Hydrostatic pressure is defined as the pressure due to the unit weight and vertical height of a fluid column. The size and shape of the fluid column do not affect the magnitude of this pressure. Mathematically: P=rXgXD where P ρ g D

= = = =

(1-1)

hydrostatic pressure average fluid density gravitational acceleration vertical height of fluid column

Relating this to drilling operations and commonly used oilfield units gives: P = C X MW X D where P MW D C

= = = =

(1-2)

hydrostatic pressure (psi) fluid density or mud weight (lb/gal or ppg) vertical depth (ft) conversion constant (psi/ft per lb/gal)

The constant, C, is necessary to allow the use of oilfield imperial units (psi, ft, lb/gal). It has a value of 0.052 psi/ft per lb/gal and is derived as follows: Using consistent units (pressure in lb/sq.ft, length in ft, density in lb/cu.ft) and rearranging equation 1-2, C would be numerically equal to 1: C=

P D X MW

= 1 lb/sq.ft/ft per lb/cu.ft

Substituting the standard conversion constants of 144 sq.in/sq.ft and 7.48/gal/cu.ft gives: C=1

X

C = 0.052

7.48 144

lb/sq.ft ft X lb/cu.ft

X

sq.ft/sq.in cu.ft/gal

lb/sq.in ft X lb/gal

C = 0.052 psi/ft per lb/gal

1-2 March 1995

BP WELL CONTROL MANUAL

So in imperial oilfield units (psi, ft, lb/gal), equation 1-2 becomes: P = 0.052 X MW – D

(1-3)

For the Company’s system of units (psi, SG, m): P = C'

X

SG

X

D

(1-4)

where SG = specific gravity of the fluid (no units) D = vertical depth (metres) C' = conversion constant (psi/m) NOTE: Specific gravity (SG) is not a unit of density. It is the ratio of the density of a␣fluid to the density of fresh water at a specified temperature, and hence has no units. The constant, C', has a value of 1.421 psi/m and is derived as follows: To express equation 1-2 in terms of SG (as in equation 1-4), the constant C' must be related to the density of fresh water, which is 8.33 lb/gal. Hence for fresh water: C' = C

X

8.33 psi/ft/lb/gal X lb/gal

C' = 0.052

X

8.33 psi/ft

C' = 0.433 psi/ft

(1-5)

Expressing this in terms of metres using 3.2808 ft/m gives: C' = 0.433

X

3.2808 psi/ft X ft/m

C' = 1.421 psi/m Equation 1-4 thus becomes: P = 1.421

X

SG X D

(1-6)

(b) Overburden Pressure Overburden pressure is the result of the combined weight of the formation matrix (rock) and the fluids (water, oil and gas) in the pore space overlying the formation of interest. It was originally assumed that overburden pressure increases uniformly with depth. The average density of a thick sedimentary sequence is equivalent to an SG of 2.3. Hence, the overburden pressure (S) is given by: S = 0.433

X

SG X D

(1-7)

where D = vertical depth (ft). The overburden pressure gradient (OPG) is given by: OPG = S D

= 0.433

OPG = 0.433

X

X

SG

2.3 = 1.0 psi/ft

1-3 March 1995

BP WELL CONTROL MANUAL

Figure 1.1 Composite Overburden Load for Normally Compacted Formations

1. 2. 3. 4.

Constant gradient 1.0psi/ft Gulf of Mexico, Texas and Louisiana, USA Santa Barbara Channel, California, USA North Sea area

0

1 4

2

3

1

DEPTH 1000m

2

3

4

5

6 0.7

0.8

0.9

1.0

1.05

OVERBURDEN GRADIENT psi/ft

WEOX02.063

1-4 March 1995

BP WELL CONTROL MANUAL

However, because the degree of compaction of sediments varies with depth, the overburden pressure gradient is not constant. Worldwide experience indicates that the probable maximum overburden gradient in clastic rocks (fragmental sedimentary rocks ie sandstone, shale) may be as high as 1.35 psi/ft. Onshore, with more compact sediments, the overburden pressure gradient may be assumed to be close to 1 psi/ft. Offshore however, overburden gradients at shallow depths will be much less than 1 psi/ft due to the effect of the depth of sea water and large thickness of unconsolidated sediment. Figure 1.1 shows average overburden gradient for various areas.

PRESSURE

AL

RM

NO OS

VE

R

TA

B

U

TIC

R

D

EN

GR

DEPTH

DR

HY

O

G

AD

R

A

T

IEN

SUBNORMAL PRESSURES (Subpressures)

D

IE

N

T

ABNORMALLY HIGH PRESSURES (Surpressures)

Formation Pressure, Pf

Matrix Stress, M

Overburden Pressure, S = Pf + M

WEOX02.064

Figure 1.2 Schematic Diagram of Subsurface Pressure Concepts

1-5 March 1995

BP WELL CONTROL MANUAL

(c) Pore Pressure Pore pressure is the pressure acting on the fluids contained in the pore space of the rock. This is the strict meaning of what is generally referred to as formation pressure. Formation pressure is related to overburden pressure as follows: S = Pf + M

(1-8)

where S = overburden pressure (total vertical stress) Pf = formation pressure (pore pressure) M = grain-to-grain pressure (matrix stress) All sedimentary rocks have porosity to some extent. If the pore spaces of the rocks are freely connected from surface, then the formation pressure at any depth will be equal to the hydrostatic pressure exerted by the fluid occupying the pore spaces. In this ‘normal’ pressure situation, the matrix stress (grain-to-grain contact pressure) supports the overburden load. Any departure from this situation will give rise to ‘abnormal’ formation pressures. Formation pressures less than hydrostatic are called subnormal (subpressures) and formation pressures greater than hydrostatic are termed abnormally high formation pressures (surpressures) (See Figure 1.2).

3 Pressure Seals For abnormal pressures to exist, there must be a permeability barrier which acts as a pressure seal. This seal restricts or prevents the movement of pore fluids and thus separates normally pressured formations from abnormally pressured formations. The origins of a pressure seal may be physical, chemical or a combination of the two. The types of formation pressure seals are listed below in Table 1.1.

Type of Seal

Nature of Seal

Examples

Vertical

Massive siltstones Shales Massive salts Anhydrite Gypsum Limestone, marl, chalk Dolomite

Gulf Coast, USA, Zechstein in North Germany, North Sea, Middle East, USA, USSR.

Transverse

Faults Salt and shale diapirs

Worldwide

Combination

Table 1.1

Worldwide

Types of Formation Pressure Seals

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BP WELL CONTROL MANUAL

4 Pressure Gradients As indicated previously in Paragraph 2(b) under ‘Overburden Pressure’, it is common practice to express subsurface pressures in terms of pressure gradients, or pressure per unit depth, psi/ft or psi/m. It should be realised that densities such as mud weights in lb/gal or␣SG, also express pressure gradients. These units can easily be converted to psi/ft or psi/m using the conversion constants derived earlier in Paragraph 2(a). Rearranging equation 1-3 gives: PG = P D

= 0.052 X MW

(1-9)

where PG = pressure gradient (psi/ft) at depth D (ft), and rearranging equation 1-6 gives: PG = P D

= 1.421 X SG

(1-10)

where PG = pressure gradient (psi/m) at depth D (m). Or, PG = P D

= 0.433 X SG

(1-11)

where PG = pressure gradient (psi/ft) at depth D (ft). By converting subsurface pressures to gradients relative to a fixed datum, it is possible to directly compare formation pressures, fracture pressures, overburden pressures, mud weights and equivalent circulating densities (ECDs) on the same basis (See Chapter 3). The datum chosen is usually sea/ground level for initial planning purposes. Once a rig has been allocated for the well, then the datum chosen for final well planning and whilst drilling is the rotary table level (since mud hydrostatic pressure starts from just below this level). During drilling operations, it is standard practice to express all pressure gradients in terms of equivalent mud weight (EMW) either in lb/gal or SG. This allows direct comparison of downhole pressures to the weight (density) of the mud in use. EMWs can be calculated from rearrangements of equations 1-9 to 1-11: EMW (lb/gal) =

P (psi) 0.052 X D (ft)

(1-12)

EMW (SG)

=

P (psi) 1.421 X D (m)

(1-13)

EMW (SG)

=

P (psi) 0.433 X D (ft)

(1-14)

NOTE: From this point on ppg will be used instead of lb/gal as the abbreviated version of pounds per gallon. Example:

For a formation pressure of 5970 psi at 3500m BRT, what is the formation␣pressure gradient in psi/ft? What is the equivalent mud weight in ppg and SG?

1-7 March 1995

BP WELL CONTROL MANUAL

Formation pressure gradient, FPG = FPG =

5970 3500 X 3.2808

pressure depth

= 0.52 psi/ft

Equivalent mud weight from equation 1-12 EMW =

5970 (ppg) 0.052 X 3500 X 3.2808

EMW = 10.0 ppg From equation 1-13 EMW =

5970 1.421 X 3500

= 1.20 SG

1-8 March 1995

BP WELL CONTROL MANUAL

1.2

NORMAL FORMATION PRESSURE

Paragraph

Page

1

General

1-10

2

Magnitude and Examples

1-10

Average Normal Formation Pressure Gradients

1-10

Tables 1.2

1-9 March 1995

BP WELL CONTROL MANUAL

1 General Normal formation pressure is equal to the hydrostatic pressure of water extending from the surface to the subsurface formation. Thus, the normal formation pressure gradient in any area will be equal to the hydrostatic pressure gradient of the water occupying the pore spaces of the subsurface formations in that area.

2 Magnitude and Examples The magnitude of the hydrostatic pressure gradient is affected by the concentration of dissolved solids (salts) and gases in the formation water. Increasing the dissolved solids (higher salt concentration) increases the formation pressure gradient whilst an increase in the level of gases in solution will decrease the pressure gradient. For example, formation water with a salinity of 80,000 ppm sodium chloride (salt) at a temperature of 25°C, has a pressure gradient of 0.465 psi/ft. Freshwater (zero salinity) has a pressure gradient of 0.433 psi/ft. Temperature also has an effect as hydrostatic pressure gradients will decrease at higher temperatures due to fluid expansion. In formations deposited in an offshore environment, formation water density may vary from slightly saline (1.02 SG, 0.44 psi/ft) to saturated saline (1.19 SG, 0.515 psi/ft). Salinity varies with depth and formation type. Therefore, the average value of normal formation pressure gradient may not be valid for all depths. For instance, it is possible that local normal pressure gradients as high as 0.515 psi/ft may exist in formations adjacent to salt formations where the formation water is completely salt saturated. The following table gives examples of the magnitude of the normal formation pressure gradient for various areas. However, in the absence of accurate data, 0.465 psi/ft is often taken to be the normal pressure gradient. Formation Water

Pressure (psi/ft)

Gradient (SG)

Example Area

Fresh water

0.433

1.00

Rocky Mountains and Mid-continent, USA

Brackish water

0.438

1.01

Salt water

0.442

1.02

Most sedimentary basins worldwide

Salt water

0.452

1.04

North Sea, South China Sea

Salt water

0.465

1.07

Gulf of Mexico, USA

Salt water

0.478

1.10

Some areas of Gulf of Mexico

Table 1.2

Average Normal Formation Pressure Gradients

1-10 March 1995

BP WELL CONTROL MANUAL

1.3

SUBNORMAL FORMATION PRESSURE

Paragraph

Page

1

General

1-12

2

Causes of Subnormal Formation Pressure

1-12

3

Magnitude of Subnormal Formation Pressures

1-15

4

Summary

1-16

Illustrations 1.3 1.4

1.5

Relationship between Piezometric Surface and Ground Level for an Aquifer System

1-13

Temperature-pressure-density diagram for Water illustrating Subnormal Pressures caused by Cooling an Isolated Fluid

1-14

Formation Foreshortening

1-15

1-11 March 1995

BP WELL CONTROL MANUAL

1 General Subnormal formation pressure is defined as any formation pressure that is less than the corresponding pore fluid hydrostatic pressure. A subnormal formation pressure gradient is thus any gradient less than the pore fluid hydrostatic gradient. Subnormal formation pressures are often termed subpressures.

2 Causes of Subnormal Formation Pressure Subnormal formation pressures occur less frequently than abnormally high formation pressures. They may have natural causes related to the stratigraphic, tectonic and geochemical history of an area, or may be caused artificially by producing reservoir fluids.

(a) Depleted Reservoirs Producing large volumes of reservoir fluids causes a decline in pore fluid pressure unless compensated for by a strong water drive. Depleted reservoirs may thus have pore pressures less than hydrostatic. For example, the original reservoir formation pressure in BP’s Forties Field was 3215␣psi at a depth of 2175m subsea. This equates to a formation pressure gradient of 0.451␣psi/ft, which is the normal hydrostatic gradient. After twelve years production from the field and even with pressure boosting by water injection, the reservoir formation pressure dropped to approximately 2750 psi. This gives a subnormal pressure gradient of 0.385␣psi/ft.

(b) Piezometric Surface A piezometric or potentiometric surface is an imaginary surface that represents the static head of ground water and is defined by the level to which the ground water will rise in a well. For example, the water table is a particular potentiometric surface. In very arid areas such as the Middle East, the water table may be deep. The hydrostatic pressure gradient commences at the water table giving a subnormal pressure gradient from the surface. A piezometric surface is dependent on the structural relief of a formation and can result in subnormal or abnormally high formation pressures. The piezometric surface for an aquifer system is shown in Figure 1.3. Drilling in mountainous areas may thus encounter subnormal pressure gradients due to the surface elevation being higher than the water table elevation or formation water potentiometric surface.

(c) Temperature Reduction A reduction in subsurface temperature will reduce the pore pressure in an isolated fluid system where the pore volumes (and thus fluid density) remains constant. This may cause subnormal pressures.

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BP WELL CONTROL MANUAL

INTAKE AREA

ABNORMALLY HIGH PRESSURES

SUBNORMAL PRESSURES

PIEZOMETRIC SURFACE

GROUND LEVEL

HYDROSTATIC HEAD

AQUIFER DISCHARGE AREA

RESERVOIRS WEOX02.065

Figure 1.3 Relationship between Piezometric Surface and Ground Level for an Aquifer System The temperature-pressure-density diagram for water shown in Figure 1.4 illustrates this concept. Both temperature and pressure are dependent on depth. For a normal fluid (non-isolated) which is allowed to expand and contract freely, a temperature reduction associated with a depth change would follow the path indicated (which in this example corresponds to a temperature gradient of 2.5°C/100m). A lower pressure would result but it would still be equal to the normal hydrostatic pressure. In an isolated fluid system (ie/completely sealed shales), cooling must take place along a constant density path as shown. The pressure corresponding to the lower temperature is thus subnormal. If gas is present in the pores, the effects of temperature reduction will be greater as gas pressure is much more sensitive to temperature changes than water. Mechanisms which may create a reduction in subsurface temperature include uplift, erosion or a combination of uplift and erosion.

(d) Decompressional Expansion Decompressional expansion is the term used to describe the combined effects of uplift and erosion. In shales, uplift and overburden removal by erosion may cause a reduction in pore fluid pressure. This reduction may be due to an increase in pore volume and removal of free water from the pore space by adsorption in clay minerals as the overburden pressure decreases. Water adsorption due to mineral transformations (eg/illite to montmorillonite) may also occur due to the decrease in temperature. (This is the reverse of ‘Clay diagenesis’ as described in Section 1.4 of this Chapter.)

1-13 March 1995

BP WELL CONTROL MANUAL

DENSITY

0.98

1.0gm/cc

11

0.877

= Conditions at depth 2

0.909

= Initial conditions at depth 1

2

0.933

1

0.962

Figure 1.4 Temperature-pressure-density diagram for Water illustrating Subnormal Pressures caused by Cooling an Isolated Fluid

10

2.5

°C/

100

m

9

8

PRESSURE 1000psi

7

6

PRESSURE AT DEPTH 1

1

5

PRESSURE AT DEPTH 2 FOR NORMAL FLUIDS

2

4

3 NORMAL FLUIDS

ISOLATED FLUIDS

2

PRESSURE AT DEPTH 2 FOR ISOLATED FLUIDS

1

2

T2 0

50

T1

100

150

200

250

TEMPERATURE °C WEOX02.066

1-14 March 1995

BP WELL CONTROL MANUAL

OVERPRESSURED A SUBNORMAL PRESSURE

BED A

P

BED B

P

P

B

P

OVERPRESSURED

BED C C

WEOX02.067

Figure 1.5 Formation Foreshortening This pressure reduction may be sufficient to cause subnormal pressures which would be transmitted to any reservoir rocks associated with the shales.

(e) Formation Foreshortening This is a tectonic compression mechanism. It is suggested that during a lateral compression process acting on sedimentary beds, upwarping of the upper beds and downwarping of the lower beds may occur. The intermediate beds must expand to fill the voids left by this process, as shown in Figure 1.5. It is then possible for more competent intermediate beds, such as shales, to have subnormal pressures due to the increase in pore volume. This mechanism is thought to occur in areas of recent tectonic activity, such as along the flanks of the Rocky Mountains.

(f) Osmosis Osmosis is the spontaneous flow of water from a more dilute to a more concentrated solution when the two are separated by a semi-permeable membrane. In the subsurface environment, clays and clayey siltstones can act as semi-permeable membranes. If salinity differences exist between the fluids in the sediments on either side of clay beds, then osmotic flow can occur. If the flow is from a closed volume, the pressure will decrease and may become subnormal. Likewise, if the flow is into a closed volume, abnormally high pressures may result. Osmosis is discussed in more detail in Section 1.4 of this Chapter.

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BP WELL CONTROL MANUAL

3 Magnitude of Subnormal Formation Pressures By definition, subnormal formation pressures must be lower than the normal hydrostatic pressure for the location. In terms of pressure gradients, subnormal pressures will have gradients less than normal (0.433 to 0.465 psi/ft depending on the particular area). As previously discussed, the Forties Field reservoir is now subnormally pressured at 0.385␣psi/ft. Subnormal gradients of 0.36 to 0.39 psi/ft have been quoted for areas of the Texas Panhandle (NW Texas) with one case as low as about 0.23 psi/ft thought to be the result of a low piezometric surface. One of the lowest formation pressure gradients encountered is 0.188 psi/ft which was recorded in the Keyes gas field in Oklahoma.

4 Summary The various suggested causes of subnormal formation pressures can be classed as ‘artifically caused’ or ‘naturally caused’. ‘Depleted reservoirs’ and ‘piezometric surface’ (where pressure regime depends on the surface location of the well) may be classed as artificial causes, since these subnormal pressures do not originate in the subsurface formation, but are externally influenced. Conversely, the other causes of subnormal pressure discussed have origins in the formations themselves and can be thought of as being naturally caused. It is unlikely that any one of these processes may be the sole cause of subnormal pressures in any particular area. It is probable that a number of processes have contributed to produce the subnormal pressures, particularly in the light of the dependency of the processes on depth and temperature.

1-16 March 1995

BP WELL CONTROL MANUAL

1.4

ABNORMALLY HIGH FORMATION PRESSURE

Paragraph

Page

1

General

1-18

2

Causes of Abnormally High Formation Pressure

1-18

3

Magnitude of Abnormally High Formation Pressures

1-30

4

Summary

1-31

Illustrations 1.6

Typical Formation Pressures caused by Compaction Disequilibrium

1-19

1.7

Interlayer Water and Cations between Clay Platelets

1-20

1.8

Schematic of Reaction of Montmorillonite to Illite

1-21

1.9

Water Distribution Curves for Shale Dehydration

1-23

1.10 Diagenetic Stages in the alteration of Montmorillonite to Illite

1-23

1.11 Abnormal Formation Pressures caused by Tectonic Compressional Folding

1-24

1.12 Abnormal Pressure Distribution around a Piercement Salt Dome

1-26

1.13 Schematic Diagram of a Mud Volcano

1-26

1.14 Abnormally High Pressure due to Reservoir Structure

1-28

1.15 Schematic Diagram illustrating Osmotic Flow

1-30

1-17 March 1995

BP WELL CONTROL MANUAL

1 General Abnormally high formation pressure is defined as any formation pressure that is greater than the hydrostatic pressure of the water occupying the formation pore spaces. Abnormally high formation pressure gradients are thus any formation pressure gradient higher than the pore fluid hydrostatic pressure gradient. Abnormally high formation pressures are also termed surpressures, overpressures and sometimes geopressures. More often, they are simply called abnormal pressures.

2 Causes of Abnormally High Formation Pressure Abnormally high formation pressures are found worldwide in formations ranging in age␣from the Pleistocene age (approximately 1 million years) to the Cambrian age (500 to 600␣million years). They may occur at depths as shallow as only a few hundred feet or exceeding 20,000␣ft (6100m) and may be present in shale/sand sequences and/or massive evaporite-carbonate sequences. The causes of abnormally high formation pressures are related to a combination of geological, physical, geochemical and mechanical processes, as discussed in the following paragraphs.

(a) Depositional Causes •

Compaction Disequilibrium Compaction disequilibrium is also known as ‘undercompaction’ or ‘sedimentary loading’. It is the process whereby abnormal formation pressures are caused by a disruption in the balance between the rate of sedimentation of clays and the rate of expulsion of the pore fluids, as the clays compact with burial. Freshly deposited clays have adsorbed water layers and the solid clay particles do not have direct physical contact. The pore pressure is hydrostatic as the pore fluid is continuous with the overlying sea water. As sedimentation proceeds, a gradual compaction occurs and as the clay particles are pressed closer together, pore water is expelled. The clay sediment has high porosity and is permeable in this initial state. So as long as the expelled water can escape to surface or through a porous sand layer, pore pressures will remain hydrostatic. For this equilibrium to be maintained, a balance is required between the rate of sedimentation and burial, and the rate of expulsion and removal of pore fluids. If the rate of sedimentation is very slow, then hydrostatic pressures will be maintained. The initial porosity of clays is 60 to 90%, depending on the type of clay, whereas compacted clay/shale has a porosity of less than 15%. Thus a vast amount of water must be removed from clay sediments during burial. If the equilibrium between rate of sedimentation and rate of fluid expulsion is disrupted, such that fluid removal is impeded, then an increase in pore pressure will result. This could occur either by an increase in the rate of sedimentation or by a reduction in the rate of fluid removal (caused by a reduction in permeability or by the deposition of a permeability barrier such as limestone).

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BP WELL CONTROL MANUAL

The ‘excess’ pore fluids help support the increasing overburden load, thereby retarding compaction further, and resulting in abnormally high pressured formations. Abnormal pressures resulting from this process will have a gradient no greater than the overburden gradient. This is because these pressures are produced by the excess overburden load being supported by the pore fluids. If beds of permeable sandstone that are hydraulically connected to zones of lower fluid pressure are present within an overpressured zone, adjacent clays will dewater to the sand bed. The adjacent clays will compact and decrease in permeability and porosity thus restricting further dewatering of the clay beds. The local pressure gradient across these clay/sand boundaries will be significantly higher than the overall pressure gradient, but are caused purely by ‘leakage’ from the clays to the sand. Figure 1.6 illustrates typical overpressures caused by compaction disequilibrium. Areas in which abnormal formation pressures associated with high sedimentation rates have been encountered include the North Sea, the Gulf of Mexico, and the Gulf of Papua.

Hydrostatic pore pressure Overburden pressure

Actual formation pressure

DEPTH

Very high local pressure gradient adjacent to permeable zones due to low permeability of the clays

CLAY Overall formation pressure parallels the overburden pressure gradient, but may not reach extrapolated pressure gradient due to leakage from the clays

SAND CLAY SAND

Extrapolated initial formation pressure (parallel to overburden pressure gradient)

CLAY SAND

Overpressured sandstone (hydrostatic gradient within sandstone)

CLAY

SAND

PRESSURE WEOX02.068

Figure 1.6 Typical Formation Pressures caused by Compaction Disequilibrium

1-19 March 1995

BP WELL CONTROL MANUAL

•

Rock Salt Deposition Continuous rock salt deposition over large areas can cause abnormal pressures that may approach overburden pressure. Salt is totally impermeable to fluids and behaves plastically at relatively low temperatures and pressures, thereby exerting pressures equal to the overburden load in all directions. The fluids in the underlying formations can not escape as there is no communication to the surface and thus the formations become overpressured. Massive rock salt deposits are commonly found in the southern North Sea with abnormally high formation pressures sometimes being encountered in formations below or within these massive salts. For instance, one BP southern North Sea well required mud weights up to 1.94 SG (0.84 psi/ft) to control a saturated salt water flow from an anhydrite formation at the boundary between the Z2 and Z3 Units of the Zechstein halite formation.

(b) Diagenesis Diagenesis is the alteration of sediments and their constituent minerals during burial after deposition. Diagenetic processes include the formation of new minerals, the redistribution and recrystallisation of the substances within the sediments, and lithification (sediments turning into rocks).

Negative Charge Imbalance

CLAY SHEET

H

H

H

H

H

H

O

H

H H

H

H

Na +

O

O

O

H

H

H

O

O

H

H

O

Na +

Ca + +

O O H

Ca + +

H O

H O

About 4 Layers of Structured Water

O

O

Na +

H

1 or 2 Layers of Adsorbed Water

H

H

H

H

H

H O H

O

O H

H

H

H

O

O

Ca + +

H

H

H

H

H

CLAY SHEET

WEOX02.069

Figure 1.7 Interlayer Water and Cations between Clay Platelets

1-20 March 1995

BP WELL CONTROL MANUAL

• Clay Diagenesis The major constituents of marine shales are bentonitic clays of which montmorillonite is by far the most common. Montmorillonite has a swelling (expanded) lattice structure and contains approximately 70 to 85% water at initial burial in sea floor sediments. This water is present in the form of at least four layers of molecules adsorbed between clay platelets and up to ten layers held on the outside of the platelets. The clay platelets have a negative charge imbalance due to their structure. This causes the adsorption of interlayer water together with various cations (positively charged ions), principally sodium (Na +) and calcium (Ca++). The interlayer water is shown schematically in Figure 1.7. The environment at this initial burial stage would be alkaline, rich in calcium and magnesium (and of course sodium from salt water), but poor in potassium. After further burial, compaction expels most of the free pore water (non-adsorbed) and the water content of the sediment is reduced to about 30%. As burial progresses and the temperature increases, eventually all but the last layer of structured (adsorbed) water will be desorbed to the pore spaces. This causes the clay lattice to collapse and with the availability of potassium, montmorillonite diagenesis to illite occurs. This reaction is shown schematically in Figure 1.8. It involves adsorption of potassium at the interlayer and surface sites as well as the release of a small amount of silica.

O

O M

A

O

O A

A W

+

W

W

W

W

W

+

W W

3 LAYER SHEET

W

W W

W +

W

W

Add K Substitute Al for Si and Mg

K

INTERLAYER SITES

A

Charge Satisfied

O 3 LAYER SHEET

A A

O

O

A

A O

ILLITE Ky AL4 (Si8-y, Aly) O20 (OH)4 = Oxygen

M

= Magnesium

= Silicon

W

= Water

O = Hydroxyl (OH)

K

= Potassium

A = Aluminium

+

= Cation eg Ca ++, Na+

MONTMORILLONITE (Al4-x Mgx)(Si8-y, Aly) O20 (OH)4 Negatively charged plates satisfied by interlayer water and cation adsorption

WEOX02.070

Figure 1.8 Schematic of Reaction of Montmorillonite to Illite

1-21 March 1995

BP WELL CONTROL MANUAL

The reaction is temperature (and hence depth) dependent. Initial dehydration may occur at temperatures as low as 6°C. Most of the interlayer water is liberated between 100°C and 250°C, but some of the more structured water remains to about 300°C. Water distribution curves showing the various shale dehydration stages are shown in Figure 1.9. At the second dehydration stage (See Figure 1.9), the water that is released expands due to a density reduction from the highly structured phase to the pore phase. Thus abnormally high pressures may result, particularly if the rate of expulsion of free pore water from the clay body is less than the rate of water release from the clay interlayers. Figure 1.10 is a schematic diagram showing the stages of alteration of montmorillonite to illite. If water escape from the clay body is restricted, the silica released in the diagenetic process will precipitate in the pore spaces. This may further reduce permeability and so assist in developing abnormal pressures. •

Sulphate Diagenesis Diagenesis in sulphate formations (gypsum, anhydrite) may cause abnormal pressures by creating permeability barriers, a fluid source and/or a rock volume change. Carbonate reservoirs are commonly overlain by evaporite sections (salt, anhydrite). Anhydrite (calcium sulphate, CaSO4) is formed by the dehydration of gypsum (CaSO4.2 H 2O) which liberates large amounts of water. There is a 30% to 40% shrinkage in formation thickness associated with this process. If this occurs at depth and in the presence of a permeability barrier, abnormal formation pressures may result. (The anhydrite itself is totally impermeable and may act as a vertical permeability barrier.) This process may have been the cause of the high pressure salt water flow discussed under ‘Rock Salt Deposition’ in (a) ‘Depositional Causes’. Here, a mud weight of 1.94 SG (0.84 psi/ft) was required to control a saturated salt water flow from an anhydrite section sandwiched between massive salt sections. The process is, however, reversible. Anhydrite can take on water to form gypsum. There is an intermediate semi-hydrate stage (CaSO4.1/2 H2O) in which the rock volume would increase by 15 to 25%. If such rehydration was to occur at depth in a closed system, very high abnormal pressures could be developed.

•

Diagenesis of Volcanic Ash Diagenesis of volcanic ash results in three main products: clay minerals, methane and carbon dioxide. Thus formations that originally contained large amounts of volcanic ash may become overpressured due to the production of gases from the volcanic ash. Areas in which this process has occurred include the NW coast of the USA and areas of the South China Sea region (Java, etc).

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BP WELL CONTROL MANUAL

WATER ESCAPE CURVE (SCHEMATIC)

WATER CONTENT OF SHALES

WATER AVAILABLE

% WATER

FOR MIGRATION 0

10 20 30 40 50 60 70 80

SEDIMENT SURFACE

PORE WATER

BURIAL DEPTH (SCHEMATIC)

PORE AND INTERLAYER WATER EXPULSION

1st DEHYDRATION AND LATTICE WATER STABILITY ZONE LATTICE WATER STABILITY ZONE

INTERLAYER WATER

2nd DEHYD'N STAGE

INTERLAYER WATER ISOPLETH

3rd DEHYDRATION STAGE

DEEP BURIAL WATER LOSS 'NO MIGRATION LEVEL' WEOX02.071

Figure 1.9 Water Distribution Curves for Shale Dehydration

STAGE 1 Before diagenesis (about 3000 – 6000ft, below 60°C) porosity = 20 to 35% clay is 70% montmorillonite 10 mixed layer 20% other

MOST WATER IS BOUND WATER LOW POROSITY

STAGE 2 FREE PORE WATER FROM DESORBED INTERLAYER WATER

During alteration to illite (100 – 200°C) high porosity = 30 to 40% clay is 20% montmorillonite 60% illite 20% other

CLAY RELEASES SILICA, ADSORBS POTASSIUM

NOTE PARTICLE COLLAPSE STAGE 3 After diagenesis and compaction (over 200°C) porosity = 10 to 20% clay is 70% illite 10% montmorillonite 20% other

LOW POROSITY VERY LITTLE BOUND WATER

VOLUME LOST

WEOX02.072

Figure 1.10 Diagenetic Stages in the alteration of Montmorillonite to Illite

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BP WELL CONTROL MANUAL

(c) Tectonic Causes •

Compressional Folding Tectonic compression is a compacting force that is applied horizontally in subsurface formations. In normal pressure environments, clays compact and dewater in equilibrium with increasing overburden pressures. However, in a tectonic environment, the additional horizontal compacting force (tectonic stress) squeezes the clays laterally. If conditions are such that the pore fluids can still escape, then pore fluid pressures will remain normal. However, it is more likely that the increase in stress will cause disequilibrium. The pore fluids will not be able to escape at a rate equal to the reduction in pore volume, resulting in an increase in pore pressure. Abnormal pressure distribution within a series of compressional folds is shown in Figure 1.11. Abnormally high pressures occur initially within the hinge portion of each compressional fold in a thick clay sequence.

EXTENSION EXTENSION

COMPRESSION

COMPRESSION

COMPRESSION COMPRESSION AMOUNT OF SHORTENING

POSSIBLE OVERPRESSURED ZONES WEOX02.073

Figure 1.11 Abnormal Formation Pressures caused by Tectonic Compressional Folding An example of overpressures associated with steep tectonic folding is the oilfields of Southern Iran where local pressure gradients as high as 1.00 psi/ft can be encountered. Also, one of the highest formation pressures reported of 1.3 psi/ft was recorded in the tectonically folded Himalayan foothills in Pakistan.

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•

Faulting Faults may cause abnormally high formation pressures in the following ways: – Slippage of formations along a fault may bring a permeable formation, eg a sand bed, laterally against an impermeable formation such as a clay. Thus, the flow of pore fluids through the permeable zone will be inhibited and abnormally high formation pressures may result. – Non-sealing faults may transmit fluids from a deeper permeable formation to a␣ s hallower formation. If this shallower formation is sealed, then it will be␣ p ressured up by the deeper formation. (See ‘Char ged Formations’ in (d) ‘Structural Courses’).

•

Uplift If a normally pressured formation is suddently uplifted, abnormally high pressures may be generated. Uplift is not a unique cause of abnormal pressure as the process that uplifts a buried formation will also uplift the overburden. For abnormal pressures to occur, there must be a concurrent geological process that reduces the relief between the buried formation and the surface. Such processes may be piercement salt domes, shale diapirs, faulting or erosion. Note that uplift and erosion may also cause subnormal formation pressures, depending on the type of formation and the amount of cooling that the formation undergoes. (See ‘Temperature Reduction’ and ‘Decompressional Expansion’ in Section 1.3 of this Chapter.)

•

Salt Diapirism Diapirism is the piercement of a formation by a less dense underlying formation. Salt will behave plastically at elevated temperatures and pressures and due to its lower density, will move upwards to form piercement salt domes in overlying formations. This upward movement disturbs the normal layering of sediments and overpressures can often occur due to the associated faulting and folding action. Additionally, the salt may act as an impermeable seal and inhibit lateral dewatering of clays thereby further contributing to the generation of abnormal pressures. The typical distribution of abnormal pressure zones around a piercement salt dome is shown in Figure 1.12. Abnormally high formation pressures associated with salt domes have been encountered worldwide, both onshore and offshore.

•

Shale Diapirism As with salt diapirism, this mechanism refers to the upward movement of a less dense plastic formation. In this case, high porosity (high water content) shales behave␣plastically causing the formation of shale diapirs called ‘mud volcanoes’ (See Figure 1.13). In practice, wherever mud volcanoes occur, there has been rapid Tertiary and/or late Cretaceous sedimentation. This rapidly loads underlying shales of low shear strength causing the formation of mud volcanoes. Formation pressures are abnormally high. For example, pressure gradients of 0.9 psi/ft have been measured around mud volcanoes on Aspsheron Peninsula in Azerbaidzhan, USSR.

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BP WELL CONTROL MANUAL

SAND

HORIZON

BASIN WARD

A

A

B

C

HORIZON

B

C

D

E

D

E SALT

ABNORMAL PRESSURE

WEOX02.074

Figure 1.12 Abnormal Pressure Distribution around a Piercement Salt Dome

MUD VOLCANO

UPPER MIOCENE

SEA LEVEL

MIDDLE MIOCENE

LOWER MIOCENE

0

Mile

5000ft

1

WEOX02.075

Figure 1.13 Schematic Diagram of a Mud Volcano

1-26 March 1995

BP WELL CONTROL MANUAL

•

Earthquakes Earthquakes may cause compression in subsurface formations which causes a sudden increase in pore fluid pressures. For example, the 1953 earthquake in California caused production in the nearby Mountain View oil field to double over a period of several weeks after the earthquake.

(d) Structural Causes •

Piezometric Surface This is defined in Section 1.3. A regionally high piezometric surface, such as that caused by artesian water systems, will result in abnormally high pressures as shown in Figure 1.3. Artesian systems require a porous and permeable aquifer sandwiched between impermeable beds. The aquifer intake area must be high enough for the abnormal pressure to be caused by the hydrostatic head. Examples of areas where abnormally high pressures are caused by artesian systems are the Artesian Basin in Florida and the Great Artesian Basin in Queensland, Australia.

•

Reservoir Structure In sealed reservoir formations containing fluids of differing densities (ie water, oil, gas), formation pressures which are normal for the deepest part of the zone will be transmitted to the shallower end where they will cause abnormally high pressures. Examples of such formation are lenticular reservoirs, dipping formations and anticlines. Abnormal formation pressures will only be generated if fluids less dense than the pore water are present, such as in oil/gas reservoirs. The pressure at the top of a fluid zone is given by: P fT = PfB – [Gf X (DB where P fT P fB Gf DT DB

= = = = =

X

D T)]

(1-15)

formation pressure at top of zone (psi) formation pressure at bottom of zone (psi) pressure gradient of fluid in zone (psi/ft or psi/m) vertical depth to top of zone (ft or m) vertical depth to bottom of zone (ft or m)

In the example shown in Figure 1.14, the formation pressure at the oil/water contact is normal hydrostatic pressure with a gradient of 0.452 psi/ft. Using equation 1-15, the pressure at the gas/oil contact is 4850 psi which gives an abnormally high formation pressure gradient of 0.462 psi/ft. Similarly, the pressure at the top of the reservoir is 4784 psi giving an abnormal gradient of 0.486 psi/ft. Obviously, in very large structures, especially in gas/water systems with long gas columns, the overpressures developed at the top of the gas column may be very high. Indeed one documented example in Iran quotes a pressure gradient of 0.9 psi/ft (approaching overburden gradient) at a depth of only 640 ft (195m).

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BP WELL CONTROL MANUAL

DEPTH

CAP ROCK TOP OF GAS CAP D = 3000m (D = 9842ft)

GAS (Gf = 0.1psi/ft)

GAS/OIL CONTACT D = 3200m (D = 10500ft)

OIL (Gf = 0.325psi/ft)

OIL/WATER CONTACT D = 3450m (D = 11319ft)

WATER (Gf = 0.452psi/ft)

At top of reservoir: Pf = 4850 – 0.1 x (10500 – 9842) Pf = 4784psi . . . FPG = 4784 = 0.486psi/ft 9842 At gas/oil contact: Pf = 5116 – 0.325 x (11319 – 10500) Pf = 4850psi . . . FPG = 4850 = 0.462psi/ft 10500 At oil/water contact: NORMAL HYDROSTATIC PRESSURE GRADIENT OF 0.452psi/ft Pf = 11319 x 0.452 Pf = 5116psi

WEOX02.076

Figure 1.14 Abnormally High Pressure due to Reservoir Structure

•

Charged Formations Normally pressured, or low pressured porous and permeable formations at shallow depths, may be pressured up by communication with deeper higher pressured formations. This ‘charging’ of the shallower formations may take place by fluid communication along non-sealing faults behind casing in old wells, or wells with faulty cement jobs, and whilst drilling a sequence of permeable formations with very large differences in pore fluid pressures (causing recharge salt water flows). Abnormal pressures caused by recharge can be very high, especially if gas is the medium that transmits the pressure (same mechanics as gas reservoir in ‘Reservoir Structure’, but over greater depth differences). Mud weights as high as 19 ppg (2.28␣SG, 0.988 psi/ft) have been quoted as sometimes required for drilling through shallow charged zones.

(e) Thermodynamic Effects Thermodynamic processes may be considered as contributing factors in most of the causes of abnormally high formation pressure already discussed. Formation temperature increases with depth in any geological system and if the system is essentially closed, thermodynamic effects will add to the build up of abnormal pressures. •

Aquathermal Pressuring Referring to the temperature-pressure-density diagram for water (Figure 1.4), a temperature increase in an isolated fluid system must take place along a constant density path. The increase in pressure is thus very rapid and only small increases in temperature are required to produce large overpressures.

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BP WELL CONTROL MANUAL

However, shales are not totally impermeable and the time taken to heat the shales during burial should be sufficient to allow most of the excess pressures developed to leak away. The main effect of heating during burial is to retard compaction, and aquathermal pressuring is not thought to be a major cause of abnormally high formation pressures. •

Thermal Cracking At high temperatures and pressures caused by deep burial, complex hydrocarbon molecules will break down into simpler compounds. Thermal cracking of hydrocarbons will increase the volume of the hydrocarbons in the order of two to three times the original volume. If contained in an isolated system, this would result in high overpressures being developed. However, there is no conclusive evidence that thermal cracking is a significant cause of abnormal formation pressures.

•

Permafrost In arctic regions, drilling and production operations may cause extensive thawing of the permafrost. If this thawed permafrost refreezes later in the life of the well, ‘freezeback’ pressures, high enough to damage the casing, may result. Obviously, this situation may be avoided by proper well planning and casing design. Freezeback pressure gradients ranging from 0.66 psi/ft to as high as 1.44 psi/ft have been recorded in Alaska.

•

Osmosis As defined in Section 1.3, osmosis is the spontaneous flow of water from a more dilute to a more concentrated solution when the two are separated by a suitable semi-permeable membrane. This action is represented schematically in Figure 1.15. For a given solution, the osmotic pressure (differential pressure across the membrane) is almost directly proportional to the concentration differential; and for a␣given␣concentration dif ferential the osmotic pressure increases with temperature. Theoretically, osmotic pressures of up to 4500 psi can be produced across a semi-permeable membrane with solutions of 1.02 gm/cc NaCl in water and saturated NaCl␣brine. Clay and clayey siltstone beds can act as semi-permeable membranes. If salinity differences exist in the sediments above and below such beds, then osmotic flow can occur. If the flow is into an isolated system, then a pressure increase will occur in this system. Alternatively, the osmotic pressure developed across these beds may inhibit the vertical flow of water from compacting shales, thereby contributing to the development of abnormal pressures. However, the efficiency of clay beds as semi-permeable membranes in the sub-surface environment is unknown. It is thus currently believed that osmosis is a minor cause of abnormal formation pressures.

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BP WELL CONTROL MANUAL

LIQUID PRESSURE DECREASES

LIQUID PRESSURE INCREASES

0

0

3

1

3

2

1 2

H2O

H2O

H2O

Na+ H2O CINa+

SALINE WATER

H2O

CLAY MEMBRANE

FRESH WATER

CI-

H2O OSMOTIC H2O FLOW WEOX02.077

Figure 1.15 Schematic Diagram illustrating Osmotic Flow

3 Magnitude of Abnormally High Formation Pressures As defined, the magnitude of abnormally high formation pressures must be greater than the normal hydrostatic pressure for the location, and may be as high as the overburden pressure. Abnormally high pressure gradients will thus be between the normal hydrostatic gradient (0.433 to 0.465 psi/ft) and the overburden gradient (generally 1.0 psi/ft). However, locally confined pore pressure gradients exceeding the overburden gradient by up to 40% are known in areas such as Pakistan, Iran, Papua New Guinea, and the USSR. These superpressures can only exist because the internal strength of the rock overlying the superpressured zone assists the overburden load in containing the pressure. The overlying rock can be considered to be in tension. In the Himalayan foothills in Pakistan, formation pressure gradients of 1.3 psi/ft have been encountered. In Iran, gradients of 1.0 psi/ft are common and in Papua New Guinea, a gradient of 1.04 psi/ft has been reported. In one area of Russia, local formation pressures in the range of 5870 to 7350 psi at 5250 ft (1600m) were reported. This equates to a formation pressure gradient of 1.12 to 1.4 psi/ft.

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BP WELL CONTROL MANUAL

In the North Sea abnormal pressures occur with widely varying magnitudes in many geological formations. The Tertiary sediments are mainly clays and may be overpressured for much of their thickness. Pressure gradients of 0.52 psi/ft are common with locally occurring gradients of 0.8 psi/ft being encountered. An expandable clay (gumbo) also occurs which is of volcanic origin and is still undergoing compaction. The consequent decrease in clay density would normally indicate an abnormal pressure zone but this is not the case. However, in some areas, mud weights of the order of 0.62 psi/ft (1.43 SG) or higher are required to keep the wellbore open because of the swelling nature of these clays. This is almost equal to the low overburden gradients in these areas. In the Mesozoic clays of the Central Graben, overpressures of 0.9 psi/ft have been recorded. One BP well encountered a formation pressure gradient of 0.91 psi/ft in the Jurassic section. In the Jurassic of the Viking Graben, abnormal formation pressure gradients up to 0.69␣psi/ft have been recorded. In Triassic sediments, abnormally high formation pressures have been found in gas bearing zones of the Bunter Sandstone in the southern North Sea. Also in the southern North Sea, overpressures are often found in Permian carbonates, evaporates and sandstones sandwiched between massive Zechstein salts.

4 Summary Of all the processes that may be responsible for causing abnormally high formation pressures, it is unlikely that any one will be the sole cause in any particular area. The effects of several processes will probably combine to cause the observed abnormal pressure. Certain processes are thought to be either ineffective or uncommon as causes of abnormal pressures. These include uplift (as a sole mechanism), osmosis, thermal cracking, permafrost and earthquakes. A recent report(6) has found that the most significant cause of abnormally high formation pressures in depositional basins is compaction disequilibrium, with aquathermal pressuring contributing to a small extent. Clay dewatering (diagenesis) was found to have little effect. However conditions within clays during dewatering are very similar to these developed during undercompaction; and the two processes probably occur concurrently, while undercompaction is recognised as the primary mechanism. The significance of aquathermal pressuring as a cause of abnormal pressure is temperature and hence depth dependent. This is also true of the diagenetic process. With increasing depth aquathermal pressuring is thought to be a contributory factor in all cases of abnormal pressure generation.

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1.5

SHALLOW GAS

Paragraph

Page

1

General

1-34

2

Definition

1-34

3

Origins of Shallow Gas

1-34

4

Characteristics of Shallow Gas

1-35

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BP WELL CONTROL MANUAL

1 General Shallow gas accumulations present a major hazard to drilling operations. Gas influxes taken at shallow depths cannot generally be shut-in for fear that the pressures involved will fracture the formation at the previous casing shoe, thereby causing an underground blowout, or flow around the casing to the seabed.

2 Definition For the purposes of drilling operations, shallow gas can be defined as any gas accumulation encountered at any depth before the first pressure containment casing string is set. For well planning purposes, possible gas bearing zones at shallow depths may be identified from shallow seismic sections (‘bright spot’ technique – See Section 2.2 of Chapter 2). These are normally used down to a depth of about 1000m below surface or mudline.

3 Origins of Shallow Gas There are two potential origins of shallow gas:

(a) Biogenic Generation This is the production of gas at shallow depths of burial from the degradation of organic matter within the sediment. An example of this would be the Pleistocene section of the North Sea which contains some organic rich clays and occasional peat/lignite formations. Thus a biogenic origin is considered likely for shallow gas accumulations in the North␣Sea.

(b) Petrogenic Generation This is the thermocatalytic degradation of kerogen which occurs under conditions of elevated temperature and pressure at greater depths. (Kerogen is a complex hydrocarbon formed from the biogenic degradation of organic matter which also gives gas as stated above.) Sufficient depth of burial to produce the heat necessary for this process to operate is probably not reached in the shallow depths considered here ie down to 1000m. However, migration of gas from deeper petrogenic sources may be possible. This could occur naturally, along non-sealing faults for example, or even through the natural permeability of clays at shallow depths. Alternatively, artificial migration paths may be produced in poorly cemented casing annuli allowing gas from petrogenic sources to accumulate in shallower formations. This could result in shallow gas accumulations forming later in the life of a producing field when early wells showed no indication of shallow gas.

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4 Characteristics of Shallow Gas (a) Composition Shallow (biogenic) gas has the following typical composition (provided by BP/Sunbury): 99% + methane (CH 4) 0.5% carbon dioxide (CO2 ) less than 0.5% nitrogen (N2 ) less than 0.1% ethane (C 2H6 ) and higher hydrocarbons. Hydrogen sulphide (H 2S) may also be present. Petrogenic gas associated with the generation of oil should contain a larger proportion of ethane and higher hydrocarbons.

(b) Configuration of Shallow Gas Accumulations Shallow gas accumulations are commonly found in sand lenses which are inferred to have been deposited in a shallow marine shelf environment with tidal influence. In this environment, the sands would tend to be in the form of sand waves, sand patches and ridges resulting in a discontinuous and patchy distribution. These sand lenses could thus be sealed by the surrounding clay sediments. This patchy distribution of shallow gas is very important. It must not be assumed that because several wells have penetrated a potential shallow gas zone successfully, then all future wells will also be free of shallow gas hazards.

(c) Pressures and Volumes Most shallow gas accumulations tend to be normally pressured. However, the classic area where overpressured shallow gas sands are encountered is the Gulf of Mexico, USA. In this area, overpressuring is thought to be the result of undercompaction of shales due to rapid deposition (See ‘Compaction Disequilibrium’, Section 1.4 of this Chapter.) One instance of overpressured shallow gas in the North Sea was reported for a well in the SE Forties area where a gas kick from a sand at about 800m subsea gave a calculated formation pressure gradient of at least 1.20 SG (0.52 psi/ft). Shallow gas accumulations resulting from migration of petrogenic gas may well be overpressured (See ‘Charged Formations’, Section 1.4). Also, overpressured shallow gas may result from long ‘tilted’ sand lenses, in an identical manner to that described under ’Reservoir Structure’, also in Section 1.4. It is difficult to estimate the volumes of gas present in shallow gas accumulations. However, estimates have been made from shallow gas discharges. In one North Sea incident, it has been estimated that 8 mmscf of gas was vented. At a depth of about 410m subsea and 600 psi pressure, this corresponds to a bulk rock volume of 20,000 cubic metres, assuming a porosity of 30%. For a 5m thick sand, this corresponds to an area of only 70m in diameter. The flowrate of gas in the above incident was estimated at 40 to 50 mmscfd. Flowrates of over 100 mmscfd have been reported for shallow gas blowouts in the Gulf of Mexico. These high flowrates are as a result of the high porosity and permeability in shallow large grain sand deposits.

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Suggestions for further reading: 1. ‘EXLOG’, 1981. Theory and Evaluation of Formation Pressures. Exploration Logging Inc., USA. 2. ‘EXXON’, 1975 Abnormal Pressure Technology. Exxon Company, USA. 3. FERTL, W.H., 1976. Abnormal Formation Pressures. Elsevier Scientific Publishing Company, Amsterdam. 4. FERTL, W.H. and CHILINGARIAN, G.V., 1976. Importance of Abnormal Pressures to the Oil Industry. Soc. Petrol. Eng., Paper 5946. 5. ‘GEARHART’, 1986. Overpressure. Gearhart Geodata Services Ltd., Aberdeen. 6. MANN, D.M., 1985. The Generation of Overpressures During Sedimentation and Their Effects on the Primary Migration of Petroleum. Report GCB/156/85. BP Research Centre, Sunbury. 7. SELLEY, R.C., 1985. Elements of Petroleum Geology. W.H. Freeman and Company, New York. 8. SHEPHERD, M., 1984. Forties Field: Shallow Gas Hazards in the Main Field Area. Report GL/AB/1880. BPPD Aberdeen.

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2 FORMATION PRESSURE EVALUATION Section 2.1 INTRODUCTION

2-1

2.2 FORMATION PRESSURE EVALUATION DURING WELL PLANNING

2-5

2.3 FORMATION PRESSURE EVALUATION WHILST DRILLING

2-23

2.4 FORMATION PRESSURE EVALUATION AFTER DRILLING

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2.1

INTRODUCTION

Paragraph

Page

1

General

2-2

2

The Transition Zone

2-2

Techniques used to Predict, Detect and Evaluate Formation Pore Pressures

2-3

Table 2.1

2-1 March 1995

BP WELL CONTROL MANUAL

1 General Knowledge of formation pore pressure is of prime importance in the planning, drilling and evaluation of a well. Good estimates of formation pore pressures and fracture pressures are required to optimise casing and mud weight programmes, and to minimise the risk of well kicks, stuck pipe, lost circulation and other costly drilling problems. The following sections describe the techniques used to predict, detect and evaluate formation pore pressures at the various stages of drilling a well. Table 2.1 summarises these techniques. Methods for predicting and evaluating fracture pressure are covered separately in a later section of this Manual. Abnormally high pressured zones are by far the most common encountered, and the most important, in drilling operations. This Chapter is therefore mainly concerned with methods of predicting, detecting and evaluating abnormally high formation pressures.

2 The Transition Zone Formation pressure gradients are considered to be the normal hydrostatic gradient for the area until a depth is reached where various pressure indicators suggest the onset of either a subnormally or an abnormally high pressured zone. The zone in which the formation pressure gradient changes from normal to subnormal or abnormally high gradient is known as the transition zone. In shales, the transition zone is the equivalent of the pressure seal discussed in Section 1.1 of Chapter 1. Since perfect seals of zero permeability rarely occur (except, for example, salt and anhydrite), transition zones are normally present. The differential pressure across a transition zone causes pore fluid flow through the transition zone. However, the flow rate through the zone will be extremely low, due to the very low permeability within the zone. The thickness of the transition zone depends on the permeabilities within and adjacent to the overpressured formation and the age of the overpressure ie, the time available for fluid flow and pressure depletion since the overpressure developed. The presence of the transition zone is very important in formation pressure evaluation. Formation properties in this zone often show a change away from normally pressured depth related trends. The magnitude of the change in the trend can sometimes be used to estimate the change in the formation pressure gradient. The parameters used to monitor the trends in formation properties are listed in Table 2.1. It must be realised that the start of the transition zone marks the onset of abnormal pressures. Every effort must be made to recognise the start of this zone both in well planning and during drilling.

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Table 2.1

Techniques used to Predict, Detect and Evaluate Formation Pore Pressures

Data Source

Pressure Data/Indicators

Stage of Well

Offset wells

Mudloggers reports Mud weights used Kick data Wireline log data Wireline formation test data Drillstem test data

Planning (also used for comparisons whilst drilling)

Geophysics

Seismic (interval velocity)

Planning

Drilling parameters

Drilling rate Drilling exponents Other drilling rate methods Torque Drag MWD logs

While drilling

Drilling mud parameters

Gas levels Flowline mud weight Flowline temperature Resistivity, salinity and other mud properties Well kicks Pit levels Hole fill-up Mud flow rate

While drilling (delayed by the time required for mud return)

Cuttings parameters

Bulk density Shale factor Volume, shape and size Miscellaneous methods

While drilling (delayed by the time required for mud return)

Wireline logs

Sonic (int. transit time) Resistivity log Density log Other logs

After drilling

Direct pressure measurements

Wireline tests (RFT/FIT) Drillstem tests

Well testing or completion

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2.2

FORMATION PRESSURE EVALUATION DURING WELL PLANNING

Paragraph

Page

1

General

2-6

2

Offset Well Data

2-6

3

Seismic Data

2-8

3.1 Abnormal Pressure Evaluation from Seismic Data

2-9

4

3.2 Identifying Shallow Gas Hazards

2-20

Summary

2-21

Illustrations 2.1

Pressure/Depth Plot

2-7

2.2

Schematic Diagram illustrating Seismic Reflection System and Seismic Traces

2-9

2.3

Schematic Diagram showing Common Depth Point (CDP) Seismic Ray Paths

2-10

Schematic Plot of Offset versus Two Way Travel Time for Common Depth Point System

2-11

2.5

Example Seismic Velocity Analysis Plot

2-13

2.6

Example of Stacking Velocity Data on a Seismic Section

2-14

2.7

Seismic and Sonic ITT versus Depth Plots for Abnormally Pressured Well

2-17

2.8

Log-log Plot of Seismic Interval Transit Time

2-18

2.9

ITT Departure versus Formation Pressure Gradient

2-19

2.4

2.10 ITT Ratio versus Formation Pressure Gradient

2-20

2.11 Example of Drilling Hazard Log over Shallow Section

2-22

Table 2.2

Calculation of Depths and Interval Transit Times

2-16

2-5 March 1995

BP WELL CONTROL MANUAL

1 General At the planning stage of a well, several early decisions are made that are directly influenced by the predicted formation pore pressure profile for the well. The magnitude of the expected formation pressure influences the pressure rating of the casing and wellhead/BOP equipment to be used, and can ultimately influence drilling rig selection. Casing programme design and mud weight programmes should be tailored to the predicted formation pressures for the␣well. Other related aspects of well planning that are influenced include, cement programmes, completion equipment, contingency stocks of casing, and mud chemicals/baryte stocks to be held. Thus, accurate formation pressure predictions are required in order to optimise well planning. Good well planning will, in turn, help to minimise the risk of costly problems whilst drilling. There are normally (but not always) two sources of formation pressure information for the well location being considered. The first and most widely used is offset well data. However, in areas where there are no offset wells or they are considered to be too far away to give reasonable data, then seismic data may be used to predict formation pore pressures. Seismic analysis may also be useful in validating offset well data for the location being considered.

2 Offset Well Data Pressure data from nearby wells are commonly used to predict the pore pressure profile. The data are often direct measurements which will give accurate pressures for the particular offset well location. Pressures can also be calculated or inferred from other well data available in well reports. The most commonly used sources of pressure data from offset wells are listed at the top of Table 2.1. The methods used to calculate formation pressures from other well data, such as wireline logs, are described in Sections 2.3 and 2.4. The measured and calculated/inferred formation pressures are then applied to the same formations in the well being planned. Additional information, such as the pressure gradient of the expected reservoir fluid, is also used to finally arrive at a predicted formation pressure profile for the well. This information is presented as a pressure depth plot, an example of which is shown in Figure 2.1. (Fracture pressure information is also presented in the form of formation leak off tests from offset wells.) The accuracy of the pore pressure prediction from offset well data will depend on the type of well that is to be drilled. The following two cases can be considered: •

Appraisal/development wells The offset well data should usually be reliable as the offset wells will normally be fairly close to the proposed well location and usually drilled on the same structure. For development wells, the pore pressure profile should be accurately defined from data from the appraisal wells.

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BP WELL CONTROL MANUAL

Figure 2.1 Pressure/Depth Plot

WELL No: 3/10b-a AREA: UKCS North 0

Leak Off Test 30/4–1 Leak Off Test 30/4–2 500

Predicted Formation Pressure 3/10b-a

1500

TERTIARY TO RECENT

Holocene to Eocene

1000

Palaeocene

2000

SG EQUIVALENT

3500

psi ft

3000

Upper

4500

Lower JURASSIC

2.61 1.128 2.51 1.085 2.41 1.042 2.31 0.998 2.21 0.955 2.1 0.911

4000

5000

psi ft

0.477 0.434

0.564 0.521

1.6 1.7 1.8 1.9

0.651 0.607

0.738 0.694

0.781

5500 0

Middle Lower

SG EQUIVALENT 1.0 1.1 1.2 1.3 1.4 1.5

CRETACEOUS

Upper

DEPTH (m)

2500

1000 2000 3000 4000 5000 6000 7000 8000 9000 10000 11000 12000 13000 14000 15000 PRESSURE (psi)

WEOX02.078

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BP WELL CONTROL MANUAL

•

Exploration wells In well explored regions, such as certain areas of the North Sea, the offset well data should be reliable enough for a good estimate to be made of the pore pressure profile for the proposed exploration well. However, if the nearest offset wells are far away, then the pressure data should be treated with caution when applying it to the proposed well. If there are insufficient pressure data available for any one profile to be predicted, then the alternatives should be considered and the ‘worst case’ evaluated for each particular aspect of well planning. Analysis of seismic data may be required to back-up the pressure profile predicted from offset wells. In areas where there is no offset well information or they are too far away to be of any use, then seismic data analysis may be the only method available to predict the pore pressure profile (See Paragraph 3, ‘Seismic Data’).

In exploration areas where there is a well established Company office, the predicted pressure profile is usually compiled by the Designated Resident Geologist (DRG) for the well. The pressure depth plot should be obtained as soon as possible and the data must be checked immediately by the Drilling Engineer responsible for planning the well. The DE must ensure that the pressure data is the best available, whilst also accepting that the accuracy of the data will vary depending on the number and proximity of nearby wells. In areas where there is no established exploration office, or where the pressure profile is required prior to compilation by the DRG, then the well planning DE will have to predict the formation pressure profile. The DRG or Area Geology Group must be consulted. The DRG or Area Geology Group will determine which offset wells are most ‘geologically similar’ to the proposed well and hence the best source of formation pressure data. Also, geological features such as faults and unconformities in the area will be identified. These may affect the way in which the pressure data are applied to the proposed well. Notes on formation pressures from offset wells are often given in the ‘Drilling Proposal’ document, together with the lithological prognosis and other pertinent data (well location, target depths, total depth etc). Petroleum Engineers should also be consulted, as they may have additional pressure information, especially regarding expected reservoir pressures.

3 Seismic Data In hydrocarbon exploration, seismic data are mainly used to identify and map prospective reservoir traps and to estimate the depths of formation tops in the lithological column. Seismic data can also be used to predict formation pressures quantitatively, or at least to give an indication of the entrance into abnormally high pressures. In new or relatively unexplored areas, seismic data are often the only information available from which pore pressure data can be derived. Seismic data can also be used to indicate the possible presence of shallow gas bearing sands. This is done using data from high resolution shallow seismic surveys which are normally used down to a maximum depth of about 1000m below surface or the mudline.

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3.1

Abnormal Pressure Evaluation from Seismic Data

(a) Basic Theory A seismic wave is an acoustic wave propagated in a solid material - normally a rock. The velocity at which the wave travels depends upon the density and elasticity of the rock, and the type of fluid occupying the pore spaces of the rock. Thus the formation type, formation fluid type, and degree of compaction (ie depth) will determine the seismic velocity in an particular formation. Knowledge of seismic velocities in particular formations over a range of depths enables geophysicists to make fairly reliable formation lithology predictions from seismic data. It is also the seismic velocity of shale sequences that permits the use of seismic data for predicting the presence of overpressured formations, and to estimate the magnitude of the overpressure.

Time

Refl C

Refl B

1

2

3

4

5

6

Up hole time

Refl A

7

First breaks 8

9

10

11

12

Shot Moment Geophones

Shot Point

Geophones

V1

A V2 Interval Velocities

B

Reflecting Beds

V3

C

WEOX02.079

Figure 2.2 Schematic Diagram illustrating Seismic Reflection System and Seismic Traces

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BP WELL CONTROL MANUAL

With increasing depth and compaction, the density and elasticity of shales increases which results in increasing seismic velocity with depth. Overpressured shales are undercompacted. This results in lower density and elasticity for that depth. The seismic velocity in overpressured shales is thus lower than in normally pressured shales at similar depths. Thus we need formation interval seismic velocity data to detect and evaluate overpressured shales. These data are readily available from seismic surveys. Seismic data are acquired by creating acoustic waves, by some form of explosion (or␣implosion), and measuring the time taken for the wave to travel down to subsurface reflecting beds and back to the surface. The surface point of origin of the wave is called␣the shot point and the reflected waves are detected at surface by a series of geophone (or hydrophones if offshore) placed at known distances from the shot point. The system is shown schematically in Figure 2.2, together with the seismic traces recorded by the geophones. The whole system is moved across the surface and the measurements are repeated from a new shot point. The process is continued along a pre-determined ‘seismic line’. By using the geometric relationships between the shot points and geophone positions, it is possible to identify a series of seismic traces that have approximately the same reflection point on a reflecting bed. This point is known as a common depth point (CDP), and the seismic paths associated with this point are shown in Figure 2.3. For clarity, only the first reflecting bed is shown, but obviously the deeper reflecting beds will also have corresponding CDPs vertically below, the reflections from which will appear on the series of seismic traces. The distance between the shot point and any particular geophone is termed the ‘offset’.

Offset Shot Points

Geophones Surface

Reflecting bed A

COMMON DEPTH POINT (CDP)

Figure 2.3 Schematic Diagram showing Common Depth Point (CDP) Seismic Ray Paths

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Figure 2.4 Schematic Plot of Offset versus Two Way Travel Time for Common Depth Point System

Offset, x to

Time, t

A

C

Reflecting Beds

B

D

E

The equations of the dashed lines through the seismic reflections are of the form: x = V √ t2 - to2 where to = vertical two way reflection time to reflecting beds (ie offset, x = o) V = stacking velocity (average velocity) Thus the stacking velocity, V, is the variable defining the hyperbolae which best fit the seismic reflections. WEOX02.081

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In practice, the seismic traces from the same CDP are collected together to form a ‘gather’ in which seismic traces at the various offsets are plotted against the reflection time. A simplified schematic plot of offset versus reflection time is shown in Figure 2.4. With greater offset, the path length of the wave is longer (See Figure 2.3) and the reflection time for the same reflecting bed increases. Curves can be drawn through the peaks on the seismic traces, corresponding to the same reflecting beds, as shown by the dashed lines in Figure 2.4. The geometry of the CDP seismic system is such that the equation of the curve through the seismic peaks (known as a ‘seismic event’) from a horizontal reflector should be a hyperbola. The variable defining the shape of the hyperbola is called the ‘stacking velocity’ or the ‘normal moveout velocity’. In practice, the peaks on the seismic traces do not lie exactly on a hyperbola. Velocity analyses are performed to determine the velocity value that gives a ‘best fit’ hyperbola to the data. This is done by investigating the hyperbolic function with a range of stacking velocities at increasing time increments, and comparing the result to the actual data from the seismic traces on the gather. The results from the velocity analysis are output in the form of a plot of stacking velocity versus reflection times. A typical example plot from an actual analysis is shown in Figure 2.5. The plot appears as a series of ‘contours’ defining a number of ‘peaks’. Due to the mathematical computations involved in the analysis, the peaks represent the ‘best fit’ stacking velocity values and the corresponding vertical two-way reflection times for each reflecting bed. The stacking velocities obtained are not the true average velocities from the surface to the reflecting bed. However, the stacking velocity is usually considered to approximate to the root mean square (RMS) velocity (as indicated on the horizontal axis in Figure␣2.5). The RMS velocity is the average velocity along the actual path of the seismic wave. In many cases, this is also considered to be equal to the vertical average velocity from the surface to the subsurface reflecting bed. Thus, the velocity-time pairs (as they are called) from the velocity analysis can be used to calculate the depths of the reflecting beds. The stacking velocities are used to compute the vertical two-way reflection times for each of the seismic traces on the seismic gather. The seismic gather can then be ‘stacked’ to form one ‘complete’ seismic trace for that particular CDP. A seismic section is then produced by displaying the stacked traces for each CDP along a seismic line. The stacking or RMS velocities are also used to calculate the interval velocities between reflecting beds, which is the property that we require to detect and evaluate abnormal pressure.

(b) The Method Before attempting to predict a formation pore pressure profile from seismic data, the Drilling Engineer must discuss the seismic data and velocity analyses with the Area Geophysicist and Geologist. This will help to identify potential problems such as poor seismic data, lithology complications, errors introduced by formation dip, etc. The DE should then have a better understanding of the problems involved in predicting a pore pressure profile for the well being planned.

2-12 March 1995

0.0

0.2

0.4

0.6

0.8

1.0

1.2

1.4

1.6

1.8

2.0

2.2

4000

5000

6000

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7000

9000

10000

12000

13000

RMS VELOCITY (ft/sec)

8000

2-13

11000

Figure 2.5 Example Seismic Velocity Analysis Plot

TWO-WAY TRAVEL TIME (millisecs)

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Figure 2.6 Example of Stacking Velocity Data on a Seismic Section

SP 561 VINT

1470 1470 1527 1685 1986 2218 2368 2668 2750 2850 2851 2930 3150

1470 1635 1809 2320 2942 3098 4923 3416 3972 2866 3165 3479

LINE CB-82-41

VRMS

0 200 300 650 1150 1450 1700 1850 2050 2200 2350 3100 5000

LINE CB-82-39 SP 870 202

TIME

140 550

146 600

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The first step in the method is to obtain the stacking velocity data for a range of CDPs near to the proposed well location. The stacking velocities used for these CDPs should be given in panels displayed above the surface line on the seismic section. An example is shown in Figure 2.6. At this point, it is worth checking the stacking velocities given in the panels against the velocities obtained from the CDP velocity analyses. This is because stacking velocities are chosen to produce a good CDP stack (‘clean’ appearance) and may not be equal to the values that would be obtained from a velocity analysis such as that in Figure 2.5. A geophysicist should be consulted to decide which stacking velocities should be used, although more often than not, the velocities given in the panel on the seismic section will suffice. The interval velocities are then calculated from the two-way time and stacking velocity (average velocity) using Dix’s formula: (V i12)2 = where Vi12 t1 t2 V1 V2

t 2(V 2)2 – t 1(V 1)2 t 2 – t1 = = = = =

(2-1)

interval velocity between reflecting beds 1 and 2 (m/s) two-way travel time for reflecting bed 1 (s) two-way travel time for reflecting bed 2 (s) average velocity to reflecting bed 1 (m/s) average velocity to reflecting bed 2 (m/s)

In the example shown in Figure 2.6, the interval velocities have already been computed using Dix’s formula. The depths to the reflecting beds are calculated from: D = t.V 2

(2-2)

where D = depth of the reflecting bed (m) t = two-way travel time for the reflecting bed (s) V = average velocity to reflecting bed (m/s) Note that the two-way time in the panel in Figure 2.6 is given in milliseconds (ms). This needs to be converted to seconds for use in equation (2-2) (1ms = 10 3 sec). A table should be drawn up as shown in Table 2.2. The final step in the calculations is to convert interval velocities, a term used by geophysicists, into interval transit times which is a term more familiar to drilling engineers. This is done by simply taking the reciprocal of the interval velocity. Note that interval transit times are expressed in micro-seconds per metre (µsec/m) (1µsec = 10-6 sec). A plot of interval transit time (ITT) versus depth can then be constructed. The interval transit time is plotted as a vertical line over the depth interval, for which it was calculated. This results in a plot similar to a sonic log plot but in which the data are averaged over long sections and not, as with the wireline sonic log, over a few feet only. A plot of the data from Table 2.2 is shown in Figure 2.7. The corresponding wireline sonic log plot is also shown for comparison. Note that ITT is plotted on a logarithmic scale and depth on a linear scale. The types of scales that are used are discussed further in (c) ‘Interpretation’.

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BP WELL CONTROL MANUAL

Two-way time

Depth

Int. velocity (Dix’s formula)

Int. transit time

t (millisecs)

Average (stacking) velocity V (m/s)

D (m)

Vi (m/s)

∆ti (µsec/m)

0

1470

0

1470

680

200

1470

147

1635

612

300

1527

229

1809

553

650

1685

548

2320

431

1150

1986

1142

2942

340

1450

2218

1608

3098

324

1700

2368

2013

4923

203

1850

2668

2468

3416

293

2050

2750

2819

3972

252

2200

2850

3135

2866

349

2350

2851

3350

3165

316

3100

2930

4542

3479

287

5000

3150

7875

Table 2.2

Calculation of Depths and Interval Transit Times

(c) Interpretation As stated, overpressured shales have lower interval velocities, and therefore higher interval transit times than normally pressured shales at the same depth. The normal shale compaction trend line on the ITT depth plot decreases with depth. Thus an increase in interval transit time away from the normal trend line indicates the presence of abnormal pressures. This is shown by the shaded section in Figure 2.7. From the seismic ITT plot (‘stepped’ profile), the top of the abnormal pressures would probably be estimated to be at 2300m to 2500m. When the well was drilled the top of the abnormal pressures was found to be at about 2000m. There is a certain amount of conflict surrounding the types of scale that should be used for plotting ITT data. The format used in Figure 2.7 assumes that the normal compaction trend is a straight line on semi-logarithmic scales. This method is recommended by Fertl(17), as it enables ITT data to be directly compared with other pressure indicators that are plotted using the same linear depth scale (composite plots). Alternatively, Pennebaker(25) suggested that the normal compaction trend should be a straight line on log-log scales. An example plot of this format is shown in Figure 2.8.

2-16 March 1995

BP WELL CONTROL MANUAL

Figure 2.7 Seismic and Sonic ITT versus Depth Plots for Abnormally Pressured Well

LITHOLOGY 500

SEISMIC DATA siltstone with mudstone

1000

SONIC LOG 1500

calcareous mudstone and siltstone

Overpressure Top: Actual

sandstone limestone Predicted

2500

3000

mudstone and siltstone

com

pac

tion

tren

d lin

e

3500

mal

4000

sandstone

Nor

DEPTH (metres)

2000

mudstone and siltstone

4500

100

200

300

400

500

600

800

INTERVAL TRANSIT TIME (µsec/m)

WEOX02.084

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NORMAL TREND

DEPTH

TOP OF OVERPRESSURE

T, Interval Transit Time WEOX02.085

Figure 2.8 Log-log Plot of Seismic Interval Transit Time Both the semi-log and log-log plots of ITT versus depth will show approximately the same top of abnormal pressures. However, a major difference between the two methods arises when the plots are used to estimate the magnitude of the abnormal pressures. Charts relating the magnitude of formation pressures to some function of the ‘departure’ of the observed ITT values from the extrapolated normal ITT values are available for both methods. For the semi-log plot, the difference between the observed and normal ITT values is used to estimate formation pressures from a chart such as the one shown in Figure 2.9. For the log-log plot, Pennebaker(25) presented a chart that required the ratio of observed ITT to normal ITT in order to estimate the magnitude of the abnormal pressures, as shown in Figure 2.10. Thus, the two methods of plotting ITT data require entirely separate empirically derived charts to estimate the magnitude of abnormal pressures. It is most important that the correct chart is used when estimating formation pressures. The chart from one method should never be used with an ITT plot from the other method. It should also be noted that different geological areas have vastly different correlations between ITT departure and formation pressure (See Figure 2.9). Hence, it is most important to obtain the correct correlation for the area that is being investigated. It may be necessary to determine a new correlation for the area of interest. This can only be done using actual well data on a regional basis and with the assistance of the geologists and geophysicists. In completely unexplored areas, this may not be possible at all.

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BP WELL CONTROL MANUAL

Another major problem in interpreting seismic ITT plots is the placing of the normal compaction trend line. Referring to Figure 2.7, it would be most difficult to determine the exact position and gradient of the normal compaction trend line from the seismic data alone. The various non-shale lithologies affect the data quite considerably and even with the actual sonic log from the well overplotted, the correct position of the normal compaction trend line is still open to debate. One possible solution to this problem is to make numerous seismic ITT (and sonic log ITT, if available) plots for the region being investigated. It may then be possible to determine the position and gradient of an average normal compaction trend line for the region. A full discussion of other problems associated with the interpretation of seismic ITT␣plots is given by Barr (2) and are further discussed in relation to sonic log plots in Section 2.4 of this Chapter.

1.0

0.9

2.25

ST

COA

OX

ILC

XAS ST TE

WARE

DELA

BASIN

2.00

WE

0.8 RG

T

2

BU

FR

VI

AS

0.7

1.75

IO

S CK

EA

CO

NA

LF

H

1.50

A

SO

0.6

S

I CH

UT

GU

PRESSURE GRADIENT psi/ft

W

H RT

SE

(FRIO, VICKSBURG, AND WILCOX – SOUTH TEXAS GULF COAST AREAS)

NO

1.25

EQUIVALENT MUD WEIGHT SG

GULF

0.5 1.00 0.4 0

10

20

30

SONIC LOG DEPARTURE

40

50

abnormal t pressured – shale

60

70

80

normal t pressured , u sec/ft shale WEOX02.086

Figure 2.9 ITT Departure versus Formation Pressure Gradient To summarise, seismic ITT data may be of use in determining the possible existence of overpressures at the planned well location. Depending on the degree of knowledge of compaction trends/formation pressure relationships for the area, it may be possible to use the seismic ITT data to estimate the magnitude of formation pressures. However, it must not be assumed that abnormal pressures do not exist because of a lack of indications from the seismic ITT data. The construction and interpretation of seismic ITT plots should always be done in conjunction with the local geophysicists and geologists.

2-19 March 1995

BP WELL CONTROL MANUAL

0.4

0.5

1.25 0.6

PORE PRESSURE GRADIENT psi/ft

1.50 0.7

EQUIVALENT MUD DENSITY SG

1.75 0.8

2.00 0.9

2.25

1.0

1.2

1.4 T/

1.6

Tn

Note: See warning in (c) Interpretation.

WEOX02.087

Figure 2.10 ITT Ratio versus Formation Pressure Gradient 3.2

Identifying Shallow Gas Hazards

Detailed high resolution seismic surveys as well as conventional seismic data are used to identify potential gas bearing zones at shallow depths by using a technique known as ‘bright spot’ analysis. The high resolution seismic data are acquired over a survey grid with perhaps only 150m between seismic lines, the grid covering an area of only a few square kilometres around a proposed well location. The data are processed to produce detailed seismic sections usually down to a maximum depth of about 1000m.

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BP WELL CONTROL MANUAL

Gas bearing formations may produce high amplitude ‘anomalies’ on the seismic reflection traces of the seismic section. These high amplitudes (relative to the other seismic reflections) are caused by strong seismic reflections due to the velocity impedance contrast between the gas bearing formation and the overlying formations. These amplitude anomalies appear visually on the seismic section as bright areas. The lateral extent of the bright spots can be mapped on a horizontal section, or sections, and the area of the proposed well location examined in detail. It may be necessary to move the well location to avoid drilling into a possible shallow gas zone as indicated by a bright spot. It must be noted that the high resolution seismic technique cannot usually detect a gas sand that is less than 2 to 3 metres thick, although such a thickness of gas accumulation may be enough to cause a shallow gas blowout. Also, the absence of bright spots does not mean that there will be no shallow gas and conversely, bright spots do not always contain gas. However, it is wise to avoid drilling through any bright spots if possible. Ideally, the Geophysicists must be responsible for analysing the shallow seismic data at the proposed well location. Once the well location has been finalised, the Drilling Engineer should liaise closely with the Geophysicists and Geologists to produce a drilling engineering hazard log over the depths covered by the shallow seismic survey. An example hazard log is shown in Figure 2.11. It will not be possible to predict formation pressures for shallow gas formations from the seismic data. However, drilling personnel should always be aware that shallow gas bearing formations may be overpressured, though this is not normally the case.

4 Summary The importance of reliable formation pressure data must be stressed. It is the responsibility of the well planning DE to ensure that the pressure data used are the most accurate available. Whenever possible, pressure data from offset wells should be used to predict the pore pressure profile for well planning. Direct pressure measurements such as those from RFTs, drillstem tests and well kicks should give more accurate data than pressures derived from well logs. Seismic methods of pressure prediction should only be used in the absence of offset well data. Occasionally, seismic analysis may be necessary to endorse the data from offset wells, although there is no guarantee that this will be successful. A recent development by Geochemistry Branch at Company Research Centre, Sunbury is worthy of note. A compaction model has been developed that may have an application for predicting formation pressures. This model may be useful for pressure prediction in areas with very few or no offset wells, especially if used in conjunction with seismic data. At present, the model is being validated against actual well data.

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BP WELL CONTROL MANUAL

Figure 2.11 Example of Drilling Hazard Log over Shallow Section CASING

DEPTH (m)

RTE

0

SEABED

100

DRILLING HAZARD

200 210 230

BASE OF NEAR SURFACE SEDIMENT POSSIBLE SHALLOW GAS

350

FAULT

30in (320m)

400 SAND, LENSES, POSSIBLE GAS 470

18 5/8in (580m)

600 620

SAND AND SHALE

800

850

1000

FAULT

BASE OF SHALLOW SURVEY

2-22 March 1995

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2.3

FORMATION PRESSURE EVALUATION WHILST DRILLING

Paragraph

Page

1

General

2-25

2

Drilling Parameters 2.1 Rate of Penetration 2.2 Drilling Exponents 2.3 Other Drilling Rate Methods 2.4 Hole Characteristics

2-25 2-25 2-27 2-38 2-42

3

Drilling Mud Parameters 3.1 Gas Levels 3.2 Temperature 3.3 Resistivity/Conductivity/Chlorides 3.4 Flowline Mud Weight

2-43 2-43 2-52 2-53 2-53

4

Cutting Parameters

2-53

5

Measurement While Drilling (MWD) Techniques

2-60

6

Mud Logging Service

2-61

7

Summary

2-64

Illustrations 2.12 Example showing Increase in Penetration Rate on Entering an Abnormally High Pressure Zone

2-26

2.13 Effect of Lithology Variation on Penetration Rate

2-27

2.14 Effect of Bit Condition on Penetration Rate when Drilling into an Overpressured Zone

2-28

2.15 Schematic Diagram showing Typical response of Corrected d-exponent in Transition and Overpressured Zones

2-30

2.16 Schematic Diagrams showing Various Typical d c-exponent Responses

2-31

2.17 Schematic Diagram showing dc-exponent Response to Overcompaction caused by Ice Sheet Loading

2-33

2.18 Example of Formation Pressure Determination from the d c-exponent plot using the ‘Ratio Method’

2-34

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Illustrations 2.19 Example showing the ‘Equivalent Depth Method’ for Formation Pressure Determination from dc-exponent Plots

2-36

2.20 Example showing Formation Pressure Determination from the dc-exponent Plot using Lines Constructed from the ‘Eaton Equation’

2-49

2.21 Example showing the ‘Normalized Penetration Rate’ Method for Determination of Formation Pressures

2-40

2.22 Schematic Diagram showing Mud Gas Levels as an Indicator of Formation Pressures

2-45

2.23 Example of Mud Gas Levels showing Trip Gas, Kelly Gas (Kelly Cut), and Recycled Trip Gas

2-46

2.24 Schematic Diagram showing Theoretical Geothermal Gradients and Temperature Profile through an Overpressured Zone

2-49

2.25 Schematic Diagram showing Expected Flowline Temperature Response on Drilling through an Overpressured Zone

2-49

2.26 Example Flowline Temperature Plots showing Raw Data Plot, End-to-end Plot and Trend-to-trend Plot

2-50

2.27 Example ‘Horner’ Temperature Plot for Estimation of True Bottomhole Temperature (BHT)

2-51

2.28 Example of Typical Response of Differential Mud Conductivity/Delta Chlorides

2-53

2.29 Schematic Shale Bulk Density/Depth Plot

2-54

2.30 Variable Density Column for Measuring Shale Bulk Density

2-55

2.31 Response of Shale Bulk Density/Depth Plots in Overpressures caused by Various Mechanisms

2-56

2.32 Shale Factor/Depth Response to Overpressure caused by Compaction Disequilibrium and Clay Diagenesis

2-58

2.33 Characterisation of Shale Cavings Caused by Underbalanced Conditions and Stress Relief

2-59

2.34 Mud Logging Unit Functions and Information Flow Diagram

2-62

Table 2.3

General Mud Logging Sensor Specifications

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1 General The aim of formation pressure evaluation whilst drilling is to determine the optimum mud weight to contain any formation pore pressures encountered, whilst maximising rates of penetration and minimising the hazards of lost circulation and drillstring differential sticking. To achieve this, formation properties have to be closely monitored in order to detect any changes that may indicate the transition from a normally pressured zone to an abnormally pressured zone or vice versa. Abnormally pressured zones may exhibit several of the following properties when compared to normally pressured zones at the same depths. •

Higher porosities

•

Higher temperatures

•

Lower formation water salinity

•

Lower bulk densities

•

Lower shale resistivities

•

Higher interval velocities

•

Hydrocarbon saturations may be different (ie higher saturation)

Any measureable parameter which reflects the changes in these properties may be used as a means of evaluating formation pressures. The parameters commonly used to evaluate formation pressures while drilling are listed in Table 2.1. It should be remembered however, that the above properties also vary with differing lithologies. Lithological variations should always be taken into account when interpreting changes in drilling and mud parameters. As the aim of formation pressure evaluation whilst drilling is to reduce the risk of taking well kicks, this section concentrates on the techniques used to achieve this. The pressure evaluation techniques in Table 2.1 that are associated with kicks are not discussed here.

2 Drilling Parameters 2.1

Rate of Penetration

Rate of penetration varies with the weight on the bit, rotary speed, bit type and size, hydraulics, drilling fluid properties and formation characteristics. If the weight on bit, rotary speed, bit type, mud density and hydraulics are held constant, then the rate of penetration (ROP) in shales will decrease uniformly with depth. This is due to the normal compaction increase in shales with depth. However, the undercompaction present in transition and abnormally pressured zones, together with the reduction in differential pressures across the bottom of the hole, result in an increase in penetration rate. It should also be noted that slower penetration rates have often been observed in the ‘cap rock’ (pressure seal) overlying transition zones.

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The increase in ROP on drilling into a transition zone can be best seen on a plot of ROP versus depth. The average ROP over 0.5 to 2m depth increments (depending on whether the␣drilling is slow or fast) is plotted as shown in Figure 2.12. A normal compaction trend can be established in shales as shown. A new trendline must be established for each new bit␣ r un. An increase in penetration rate away from the normal compaction trend may indicate␣abnormal pressures provided that the drilling and mud parameters, and lithology , remain constant.

ROP

DEPTH

NORMAL SHALE TREND LINE

NEW BIT

TOP OF OVERPRESSURES

WEOX02.089

Figure 2.12 Example showing Increase in Penetration Rate on Entering an Abnormally High Pressure Zone Complications arise due to lithology changes and bit dulling. Sandstone usually drills much faster than shales. This is normally shown by a sharp increase in ROP as the sandstone is penetrated. This effect, known as a ‘drilling break’ is shown schematically in Figure 2.13. The normal compaction trend must be established over the shale sections only. Drilling breaks must always be flow checked regardless of whether the current estimated pore pressure gradient is less that the mud weight. Occasionally, the transition zone may be only a few metres thick if there is a very good pressure seal. This may make it very difficult to identify an increase in ROP as being one due to increased pore pressure, because it may be masked by a drilling break.

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ROP

sand shale

DEPTH

NORMAL SHALE COMPACTION TREND LINE

WEOX02.090

Figure 2.13 Effect of Lithology Variation on Penetration Rate Bit dulling can also mask penetration rate changes due to pore pressure increases. A comparison of ROP curves in an overpressured section for a dull bit and a sharp bit are shown in Figure 2.14. The dull bit continues to show the normal compaction trend in the transition zone whilst the sharp bit clearly shows a gradual increase in ROP. The dull bit ROP may even show a decrease in the overpressured zone if the bit is very worn and close to being pulled. In practice, drilling parameters are rarely held constant, as they are purposefully varied in order to maximise the penetration rate. Thus, ROP curves alone tend to be of limited use in identifying overpressured zones. They may, however, provide additional information when used in conjunction with other abnormal pressure indicators.

2.2

Drilling Exponents

From the preceding discussion on ROP curves, it is clear that a method of accounting for the effect of drilling parameters is desirable in order to make ROP a better indicator of abnormal pressures. The ‘d-exponent’ attempts to achieve this.

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SHARP BIT ROP

DULL BIT ROP

sand

DEPTH

shale

TOP TRANSITION ZONE

WEOX02.091

Figure 2.14 Effect of Bit Condition on Penetration Rate when Drilling into an Overpressured Zone (a) d-Exponent In 1965, Bingham(4) proposed a generalised drilling rate equation to relate all the relevant drilling parameters:

ROP = a WOB N B where ROP N B WOB a d

= = = = = =

d

(2-3)

penetration rate (ft/min) rotary speed (rpm) bit diameter (ft) weight on bit (lb) rock matrix strength constant (dimensionless) formation drillability exponent (dimensionless)

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Jorden and Shirley (21) rewrote equation 2-3 for ‘d’, the drillability exponent. They inserted constants to allow the use of more common oilfield units and let the matrix strength constant, ‘a’, equal 1. This removed the need to derive values for the matrix strength constant, but made d-exponent lithology dependent: log ROP 60N d= 12WOB log 106 B

where d ROP N B WOB

= = = = =

drillability exponent (d-exponent) (dimensionless) penetration rate (ft/hr) rotary speed (rpm) bit diameter (in.) weight on bit (lb)

NOTE: The constant 106 is simply a scaling factor inserted in the equation in order to give values of d in a convenient workable range, normally about 1.0 to 3.0. In constant lithology, d-exponent will increase with depth as the ROP decreases due to the increased compaction and differential pressures across the bottom of the hole. However, when an overpressured zone is penetrated, compaction and differential pressure will decrease and will result in a decrease in d-exponent. Hence d-exponent is, in general, related to the differential pressure at the bottom of the hole which in turn is dependent on pore pressure.

(b) Corrected d-Exponent Since the differential pressure across the bottom of the hole is affected by the mud␣weight also, then changes in the mud weight will produce unwanted changes in d-exponent. Hence Rehm and McClendon (27) proposed the following correction to the d-exponent to account for mud weight variations: dc = d

X

FPG N ECD

(2-5)

where dc = corrected or modified d-exponent (dimensionless) FPGN = normal formation pressure gradient (ppg, SG) ECD = equivalent circulating density (ppg, SG) This correction has no theoretical basis but has been successfully used worldwide. ECD should be used whenever possible but use of the actual mud density has been found to be acceptable. The response of d-exponent in overpressure is shown schematically in Figure 2.15. The dc-exponent may be plotted with either semi-log or linear co-ordinate axes. Either system will produce an approximately linear, normal compaction trendline, as indicated in Figure 2.15. In practice, the semi-log co-ordinate system gives a more efficient data display (values of dc are normally in the range 0.5 to 2.0) and is a more suitable format for making formation pressure estimates from dc-exponent. A d c-exponent plot should be commenced as soon as drilling begins. Values should be calculated at 0.5 to 2m intervals, depending on penetration rate. This is normally done automatically by the Mud Logger’s computer and displayed as required. The values may also be plotted up automatically to enable trends to be spotted as early as possible.

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NORMAL CONCEPTION TREND UNE

DEPTH

NORMAL PRESSURE

TRANSITION ZONE

OVERPRESSURED ZONE

WEOX02.092

dc

Figure 2.15 Schematic Diagram showing Typical response of Corrected d-exponent in Transition and Overpressured Zones The ‘normal’ dc trendline should be established as soon as possible in order that transition zones to abnormal pressures can be recognised as they are being drilled. However, it is often difficult to precisely establish the normal dc trendline due to scatter in the dc values calculated. This variation in d c values is mainly caused by: •

Lithology As previously stated, d-exponent increases with depth and compaction in constant lithology. This implies that d-exponent is mainly applicable to shales. Changes in␣lithology will thus cause changes in the value of d c. If the lithology change is relatively minor, such as silty shales, then a slight decrease in dc values may be observed which may not affect the overall trend significantly. Cuttings analysis should help to identify ‘true’ shale points for use in establishing the normal trend if the dc values show a large␣scatter .

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Figure 2.16 Schematic Diagrams showing Various Typical dc-exponent Responses (a)

(b)

MUDSTONE

SILTY MUDSTONE

DEPTH

CALCITIC MUDSTONE

MUDSTONE

NORMAL PRESSURE

NORMAL PRESSURE

DEPTH

SOFT CLAY

SAND

MUDSTONE SAND

MUDSTONE

OVERPRESSURE

OVERPRESSURE

CALCITIC MUDSTONE

MUDSTONE

CALCITIC MUDSTONE

MUDSTONE SAND

MUDSTONE

dc

dc

(c)

(d)

ROCK BIT 12 1/4in / 25 000 lb W/B = 2040 lb/in SMOOTHED CURVE

SMOOTHED CURVE

DEPTH

DEPTH

RAW DATA

INSERT BIT

12 1/2in / 10 000 lb W/B = 1178 lb/in

ROCK BIT

RAW DATA

dc

dc

(e)

(f)

OVERPRESSURE

NEW BIT

NORMAL PRESSURE

DEPTH

DEPTH

NEW BIT

NEW BIT

dc

FRESH BIT

DULL BIT

dc

WEOX02.093

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For major lithological variations, such as interbedded sandstone/shale, the normal trend must be developed through the shale sections only. The increased ROP in sand sections will give sharply decreased dc values. (It may be possible to develop normal trendlines for the various other lithologies but these are of little use in overpressure evaluation and may only serve to confuse matters.) The important message here is that lithology variations must be taken into account when interpreting dc-exponent plots. The response of d c in various lithologies is shown schematically in Figure␣2.16 (a) and (b). •

Hydraulics Changes in drilling hydraulics may produce changes in dc-exponent. This also applies to formations that are susceptible to jetting. Therefore, it is often impossible to establish a normal dc trend in soft, unconsolidated sediments, such as those commonly drilled in offshore top hole sections.

•

Bits The different drilling actions of different types of bits, ie mill tooth or insert, can cause variations and trend shifts in dc. It is sometimes necessary to plot a ‘smoothed’ curve to account for trend shifts as shown schematically in Figures 2.16 (c) and (d). Changes in hole size will also produce a trend shift in dc. The effect of bit wear is to produce an increase in dc values towards the end of the bit run, as indicated in Figure 2.16(e). The new bit should give a new dc trend that continues along the previous trend provided that it is the same type of bit and none of the other parameters have varied significantly. The effect of drilling into an overpressured zone as the bit dulls is shown schematically in Figure 2.16 (f). A dull bit may mask the decrease in dc which would be expected if the bit was fresh. In extreme cases, bit dulling may totally mask or even produce an increase in dc values even though an overpressured zone has been penetrated.

Thus it can be seen that the position of normal trends should be established with great care, as should the practice of shifting trends from raw data to produce smoothed curves. Two further noteworthy phenomena that may cause difficulty in interpreting the plots␣are: •

Unconformities/Disconformities The presence of an unconformity/disconformity in the geological age of formations being drilled will often change the character of the normal trendline. The different compaction histories and sedimentary conditions of the formations above and below an unconformity/disconformity may result in not only a shifted normal dc trendline, but also a change in slope. A new trendline should be established after drilling through an unconformity/disconformity.

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dc – EXPONENT 0.5

SG

1.3

1.5

2.0

G 1S 1.

1.2

1.0

SG

DEPTH

OVERCOMPACTED

NORMAL COMPACTION TREND NORMALLY COMPACTED

OVERPRESSURED WEOX02.094

Figure 2.17 Schematic Diagram showing dc-exponent Response to Overcompaction caused by Ice Sheet Loading •

Ice Sheet Compaction Ice sheet compaction can often cause a good normal compaction trend to be established at shallow depths in top hole sections. This is due to the increased compaction of the near surface sediments caused by the weight of a once present overlying ice sheet. This may lead to a normal d c trend being developed through dc values that are too high. The compacting influence of the ice sheet is often dissipated after the first few hundred metres and the d c-exponent then appears to decrease to a new normal trend, falsely indicating an increase in pore pressure. This effect is shown schematically in Figure 2.17.

(c) The Calculation of Formation Pressures using dc Once the normal compaction trend has been firmly established on the dc-exponent plot, then d c values that decrease away from this line may indicate abnormal formation pressures. This is, of course, provided that there have been no significant changes in lithology or in any of the other relevant parameters.

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• The ratio method The magnitude of the formation pressure can be related to the dc deviation on the semi-log plot using the ‘ratio method’: FPG O = FPGN X

dcN dcO

(2-6)

where FPG O = actual formation pressure gradient at depth of interest (psi/ft, SG or ppg) FPG N = normal formation pressure gradient (psi/ft, SG or ppg) dcO = observed corrected d-exponent at depth of interest dcN = expected corrected d-exponent on normal trendline at depth of interest

Normal shale trend line Normal formation pressure Gradient is 1.08 SG SANDS

DEPTH

2.04 SG

1.80 1.56 1.44 1.32 1.20 1.08 SG

TYPICAL TRANSITION ZONE

Maximum formation press gradient is 1.43 SG

Maximum formation press gradient is 1.66 SG

dc – EXPONENT (SEMI-LOG SCALE)

WEOX02.095

Figure 2.18 Example of Formation Pressure Determination from the dc-exponent plot using the ‘Ratio Method’ Equation 2-6 is only valid for the semi-log dc plots as it is assumed that dc is an exponential function of depth. By rearranging the above equation into: dcO = d cN X FPG N FPG O

(2-7)

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and substituting known values of FPG N and dc at various depths, it is possible to calculate a series of values of dcO , equivalent to various values of formation pressure gradient, FPGO. These series of values of dcO can be plotted on the semi-log dc plot as lines parallel to the normal d c trendline. The formation pressure gradient at any desired depth can then be estimated directly from the dc plot. Figure 2.18 shows an example d c plot with equivalent formation pressure gradient lines drawn in. NOTE: Transparent overlays ready marked with equivalent formation pressure gradient lines are sometimes available for reading formation pressures directly off the dc plot. As it is never certain exactly what depth and dc scales were used to construct these overlays, their use should be avoided in making formation pressure gradient estimates. The ratio method is a very simple method of making formation pressure estimates from dc-exponent. However, it ignores the effect of the variable overburden gradient (See ‘Overburden Pressure’ in Chapter 1, Section 1.1), which controls compaction trends. This effect is reflected in the d c-exponent trend, but is considered not accurately defined by it. An alternative method of calculating formation pressures from the dc plot is the equivalent depth method. •

Equivalent Depth Method Due to the increase in compaction with depth, the formation matrix stress also increases, and the formation becomes harder to drill. In overpressured formations the compaction and matrix stresses are less than would be normally expected at that depth. The equivalent depth method attempts to relate these values to the depth at which they would be normal. The method assumes that the matrix stress (grain to grain contact pressure) is equal at all depths having the same value of dc. Matrix stress (M) is related to pore pressure (P f) and the overburden pressure (S) as shown by equation 1-8 (See Chapter 1, Section 1.1). This equation can be rearranged to give: Pf = S – M

(2-8)

This equation holds at any depth. Therefore, referring to the example dc plot in Figure 2.19, the actual formation pressure gradient (FPG O) at the depth of interest (D O) is given by: FPGO =

PfO = DO

SO – M O D O DO

FPGO = OPGO – MO DO where OPG O MO

(2-9)

= overburden pressure gradient at depth of interest (psi/ft) = matrix stress at depth of interest (psi)

The overburden pressure gradient is known because it is continually estimated by the Mud Loggers and updated from wireline formation density or sonic logs. (The␣overburden gradient is required for estimating fracture pressures as well as for making pore pressure estimates.) However, the value of the matrix stress at the depth of interest is unknown.

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A line is then constructed vertically upwards from the value of dc at the depth of interest until it crosses the normal dc trendline at ‘the equivalent depth’ (DE), as shown in Figure 2.19. At this equivalent depth, both the pore pressure and the overburden pressure are known. Thus, equation 2-8 can be solved for the matrix stress (ME) at the equivalent depth (DE): ME = SE – PfE

(2-10)

In terms of gradients: ME = SE = PfE = OPG E – FPG E DE DE DE ME = DE (OPGE – FPG E)

(2-11)

where OPGE = overburden gradient at equivalent depth (psi/ft) FPGE = formation pressure gradient at equivalent depth (psi/ft) which also equals the normal formation pressure gradient at the equivalent depth FPGNE (psi/ft)

dc – EXPONENT 0.5

1.0

1.5

2.0

DEPTH

DE

NORMAL COMPACTION TREND

DO

WEOX02.096

Figure 2.19 Example showing the ‘Equivalent Depth Method’ for Formation Pressure Determination from dc-exponent Plots

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Since the matrix stress at the depth of interest and equivalent depth are considered equal (equal d c values), then substituting equation 2-11 into equation 2-9 gives: FPGO = OPGO – D E (OPGE – FPG NE) DO where FPG O OPG O OPG E FPG NE DO DE

= = = = = =

(2-12)

formation pressure gradient at depth of interest (psi/ft) overburden pressure gradient at depth of interest (psi/ft) overburden pressure gradient at equivalent depth (psi/ft) normal formation pressure gradient at equivalent depth (psi/ft) depth of interest (ft) equivalent depth (depth at which dc is equal to value at DO) (ft)

NOTE: Equation 2-12 can be used directly with gradients in SG, lb/gal or psi/ft and depths in metres or ft. The equivalent depth method has been successfully used to estimate formation pressures from both semi-log and linear scale d c plots. However a major flaw in the theory occurs when the equivalent depth of a particular overpressured formation is found to be above the rig floor. This will be the case if high overpressures are developed at relatively shallow depths. Also, the method relies on determining the intersection point of a vertical line with the normal compaction trendline. It therefore becomes inaccurate when the normal compaction trendline is very steep, as is usually the case on the semi-log dc plot. •

The Eaton Method The most accurate estimates of formation pressure from dc-exponent are considered to be obtained from the Eaton equation. This empirical equation was again developed from the basic relationship between pore pressure, overburden pressure, and matrix stress (equation 2-8). For normal pressure conditions: MN = S O – PfN

(2-13)

Eaton then introduced a term to relate the dc-exponent (drilling rate) response in overpressures to the reduction in matrix stress: MO = MN DcO d cN

1.20

(2-14)

Combining equations (2-13) and (2-14) gives: MO = (SO – PfN) dcO d cN

1.20

(2-15)

Rewriting equation 2-13 for an abnormally pressured situation gives: MO = S O – PfO

(2-16)

Substituting equation 2-16 into equation 2-15 then gives the Eaton equation: PfO = SO – (SO – PfN) DcO d cN

1.20

(2-17)

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Dividing through by the depth (D), gives the equation in terms of gradients: PfO = SO – SO – PfN DO DO DO DO

dcO d cN

1.20

FPGO = OPGO (OPGO – FPGN) dcO d cN

1.20

where FPGO, FPGN, OPGO, dcO and dcN are the same terms as explained for equations 2-6 and 2-12. By rearranging equation 2-18 and substituting known values of FPGN, d cN and OPG, it is possible to plot a series of d cO lines equivalent to various values of FPG O (in a similar manner to that previously explained for the Ratio method). An example of this construction is shown schematically in Figure 2.20. Formation pressure gradients can then be read directly from the dc plot. Eaton originally developed the equation for use in estimating formation pressures from shale resistivity plots (See Section 2.4), but found that it applied equally to␣corrected d-exponent. The value of the exponent, 1.20, was derived from actual well data. All the methods for estimating formation pressures from dc-exponent plots rely on correct placement of the normal compaction trend. The difficulties in achieving this have previously been discussed and highlight the fact that identification of overpressured zones should not be based on dc-exponent calculations alone. Other abnormal pressure indicators, which are often more basic in nature than dc-exponent calculations, should always be checked. These indicators must support, as far as possible, any formation pressure conclusions drawn from the dc plot. Drilling factors that are not accounted for by dc-exponent are drilling hydraulics, bit tooth efficiency (bit wear) and matrix strength (lithology dependent). Also, the relationship between ROP and the various drilling parameters is not so simple as is implied by the dc-exponent equation. These factors have led to the development of more refined drilling exponents in which attempts have been made to model the various drilling/formation interactions more closely. In particular, mud logging companies have developed their own drilling exponents from which they make formation pressure estimates. Exlog’s ‘Nx’ (normalised exponent) and ‘Nxb’, and Anadrill’s ‘A’ exponent are examples of these more refined drilling exponents. The theory of these drilling exponent methods will not be discussed in detail here as their formulae are of a proprietary nature and are not generally available. Suffice it to say that the methods still rely on estimating a normal compaction trend and spotting deviations from it caused by pore pressure changes and not by lithology or drilling changes.

2.3

Other Drilling Rate Methods

There are a number of other drilling rate methods for estimating formation pressures that are worthy of note. As these methods are generally more complex than d-exponent methods, they have not gained wide acceptance and thus tend only to be used by their originators.

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Figure 2.20 Example showing Formation Pressure Determination from the dc-exponent Plot using Lines Constructed from the ‘Eaton Equation’

dc – EXPONENT 0.5

1.80

1.68

1.56

1.44

1.0

1.33 1.20 1.08

1.5

SG

DEPTH

NORMAL TREND

TOP OF OVERPRESSURE

WEOX02.097

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(a) Normalised Penetration Rate This method was developed in 1980 by Prentice(26) from work done originally by Vidrine and Benit(32). The method uses a drilling rate equation to ‘normalise’ the effects of the variables controlling ROP. The only variable not normalised is differential pressure across the bottom of the hole. If the ECD is then considered to be fairly constant over short intervals of the hole, a change in ‘normalised’ penetration rate reflects a change in formation pressure.

2960 NEW BIT 1.08 SG

ECD = 1.25 SG

2990

ECD = 1.25 SG

3020

1.08 SG

8.53m/hr

4.11m/hr

DEPTH (metres)

NEW BIT

3050 1.28 SG

CIRCULATED 1.38 ECD ALL AROUND NEW BIT

ECD = 1.38 SG 1.28 SG

8.23m/hr

3080

6.1m/hr 1.37 SG CIRCULATED 1.5 ECD ALL AROUND

12

8

4

4100

0

NORMALIZED PENETRATION RATE (m/hr) WEOX02.098

Figure 2.21 Example showing ‘Normalized Penetration Rate’ Method for Determination of Formation Pressures

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As drilling proceeds, a plot of normalised penetration rate against depth is constructed. The observed penetration rate is mathematically corrected to the normalised penetration rate by applying arbitrarily chosen normal parameters according to the equation:

ROPN = ROPO where ROP W N ∆Pbit Q m λ

= = = = = = =

WN – m WO – m

X

X

NN NO

λ

X

∆PbitN QN ∆PbitO QO

(2-19)

penetration rate (ft/hr or m/hr) weight on bit (lb) rotary speed (rpm) bit pressure drop (psi) mud flow rate (gpm) ‘threshold’ bit weight (weight necessary to initiate formation failure) (lb) rotary exponent

and the subscripts N O

= ‘normal’ values = observed values

Values of λ and m are given by Prentice(26). If the ‘normal’ conditions are chosen so that most of a bit run can be drilled at these conditions, then no corrections will be necessary and ROPN will equal ROPO. Each bit run is treated as an individual unit and is plotted up as shown in the example in Figure 2.21. Changes in mud weight are also plotted separately. Drilling trends are fitted to each bit run, or part bit run, at constant ECD, as shown in the example. Provided that the ECD and formation pressure remain constant, the bit will dull and the ROPN will follow the dulling trend. If a deviation from the dulling trend is noted at constant ECD, this then indicates either a lithology change or a change in formation pressure. Lithology changes are generally abrupt, and easily identified. Formation pressure changes show a more gradual deviation from the dulling trend, as shown in the example plot at about 9950 ft and 10,100 ft. Vidrine and Benit (32) developed a graphical relationship between differential pressure across the bottom of the hole and the percentage decrease in ROP caused by this overbalance. Using this relationship, the extrapolated dulling trend ROP N and the observed ROPN at a particular depth are used to estimate the actual formation pressure at that depth. The method is detailed in full by Prentice(26) together with worked examples and a comprehensive discussion of the theory behind the method. The method is quoted as being the most responsive of all methods used to indicate the changes in formation pressure, but no data are presented to support this claim.

(b) Sigmalog This method was developed by AGIP and Geoservices(3). Basically, it is a plot of a calculated rock strength parameter versus depth. The method is based on the following drilling rate equation (developed by AGIP): 0.5

0.25

√σ t = WOB . N B . ROP0.25

(2-20)

where √σt = ‘raw’ rock strength parameter and WOB, N, B and ROP are as previously defined. The ‘raw’ rock strength is then corrected to the rock strength parameter, √σo, using experimentally derived relationships to account for depth and bottomhole differential pressure (assuming a normal formation pressure gradient). The Sigmalog is then constructed by plotting √σo versus depth.

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In normally pressured formations, √σo will increase with increasing depth and compaction. A normal compaction trend can be established and a decrease in √σo away from the normal trend will indicate an increase in formation pressure. When this occurs, the relationship used to correct √σt to √σo is reworked to determine the true bottomhole differential pressure (not the assumed one). The formation pressure can then be calculated from the differential pressure and the ECD for the mud weight in use. Various factors such as faults, unconformities/disconformities, poor bit efficiency, coring etc, cause ‘shifts’ in the normal trend. However all the normal trends have the same slope, and the shifts of the trendlines are proportional to the shifts in the values of √σo. Correct shifting of the normal trendlines is thus of prime importance in calculating formation pressures from the Sigmalog. Despite this problem, it is claimed that the Sigmalog is an excellent formation pressure evaluation tool and can be applied both in shale and non-shale lithologies. The Sigmalog is commonly used by Geoservices to estimate formation pressures.

(c) Other Methods Several other methods of formation pressure evaluation from drilling rate equations have been put forward. These include methods by Combs (10) , Zoeller (33) , and Bourgoyne (5). These are not discussed here but are referenced in case of interest to the␣reader .

2.4

Hole Characteristics

(a) Drag and Torque Drag is the excess hook load over the free hanging load required to move the drillstring up the hole. Drag may be caused by bit and stabiliser balling, dog legs, insufficient hole cleaning, etc, and also by overpressure effects in shales. Overpressured shales often behave plastically and creep into the borehole. This reduces the wellbore diameter and will cause an increase in drag as the bit/stabilisers are moved up through the section. In an underbalanced drilling situation, an increased volume of cuttings may come into the wellbore. This may result in an increase in drag when picking up the drillstring to make a connection, especially if the cuttings are not circulated above the drillcollars prior to picking up. Normal drag after drilling new hole is usually of the order of 10,000 to 20,000 lb, depending on the hole and BHA geometries. Consistent drag values much higher than this may indicate borehole instability caused by abnormal pressures. In deviated holes however, consistently higher drag will invariably be seen. Torque usually increases gradually with depth due to the increase in wall-to-wall contact between the drillstring and borehole. If underbalanced conditions exist then an increase in torque may be observed due to excess cuttings entering the hole. A reduced wellbore diameter caused by overpressured shales may also result in an increased torque, especially if full gauge stabilisers are being used. However, increased torque resulting from underbalanced conditions is virtually unseen when the pressure differential into the wellbore is less than 1 ppg (0.12 SG) equivalent pressure gradient. If an increase in torque is taken to indicate underbalanced conditions, then concurrent increases in drag and hole fill (see below) should also be expected.

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Torque can be useful in detecting large increases in pore pressures, for example when crossing a fault line into overpressured formations. However, sudden large increases in torque can also be caused by a locked cone on the bit, a sudden change in formation type, and by stabilisers ‘hanging up’ on hard stringers. Both torque and drag are not considered to be valid overpressure indicators when drilling high angle deviated holes. Also, increases in torque due to abnormal pressures are difficult to distinguish from the normal torque increase with depth. When drilling from a floating rig the vessel motion and varying offset from the wellhead tend to produce significant torque fluctuations that make interpretation very difficult.

(b) Hole Fill Hole fill after making a connection or after a trip out of the hole may indicate abnormal pressures. As discussed above, overpressured shales may squeeze into the wellbore and reduce its diameter. Then, as the bit is run in the hole to bottom after a connection or trip, it removes the shale which is pushed to the bottom of the hole. Cavings caused by underbalance conditions may also enter the wellbore during a connection or a trip and cause hole fill. Hole fill may also be the result of insufficient hole cleaning caused by poor mud properties, or by not circulating all the cuttings out of the hole prior to tripping. However, any excessive hole fill after making a connection or a trip should be noted and other abnormal pressure indicators evaluated to determine if overpressures are actually being encountered.

3 Drilling Mud Parameters 3.1

Gas Levels

Hydrocarbon gases enter the mud system from various sources during the drilling of a well. The gases in the return mud stream are extracted from the mud for analysis in the mud logging unit. There is no quantitative correlation between measured gas levels and formation pressure. However, changes in gas levels can be accounted for by relating them to the actual drilling operation in progress (drilling, tripping etc) and the mud weight in use. Tentative pore pressure estimates may then be made. The main sources of gas in the mud system are: •

Gas liberated from drilled cuttings.

•

Gas flowing into the wellbore due to underbalanced conditions.

The gas levels from these sources are dependent upon the formation gas saturations, the mud weight and the particular drilling operation.

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Gas levels are categorised as follows:

(a) Background Gas (BGG) This is the total level of gas extracted from the return mud stream whilst drilling ahead. It originates primarily from the unit volume of formation cut by the bit. Hydrocarbons are often generated within shales and migrate to more porous formations such as sandstones where they may be trapped. Gas in shale cuttings is released into the mud stream due to the reduction in pressure as the cuttings are circulated up the hole. If hydrocarbons are present in any porous formations drilled, there will be relatively high levels of background gas in the mud stream. However, if the mud weight in use causes a high overbalance, there may be little, if any, entry of gas into the mud. The high overbalance will cause the mud filtrate to ‘flush’ the gas away from the wellbore. In underbalanced drilling conditions, gas may enter the mud at a rate that depends on the permeability of the formations being drilled. Shales may shown an increase in background gas levels, due to an increase in cavings caused by the underbalanced conditions. Background gas levels normally show a gradual increase as a transition zone to abnormal pressures is drilled. Background gas can not be used quantitatively to estimate formation pressures since the levels depend on mud circulation rate, efficiency of gas extraction from the return mud stream (gas trap efficiency) and also on the gas composition. However, if mud properties, drilling conditions, and lithology remain fairly constant, then increasing background gas levels may well indicate that the formation pressure gradient is approaching, or possibly exceeding the mud weight gradient.

(b) Connection Gas (CG) When circulation is stopped to make a connection, the bottomhole pressure of the mud column is reduced by an amount equal to the annulus pressure loss i.e. the effective mud weight is reduced from the ECD to the static mud weight. This reduction in pressure may be enough to allow a small amount of gas to be produced into the mud column. This is known as connection gas. Also, connection gas may also be caused by ‘swabbing’ when picking up the drillstring to make a connection. When this gas reaches the surface, it appears as a peak above the background gas level on the total gas trace recorded in the mud logging unit. Connection gas peaks are generally short and sharp depending on the ‘bottoms up’ time, i.e. the longer the bottoms up time, the wider the peak will be. It is possible to correlate connection and background gas levels with the mud weight to give a fairly accurate estimate of the formation pressure. This is shown schematically in Figure 2.22. As the pore pressure approaches the bottomhole dynamic pressure, connection gas peaks begin to appear, probably due to swabbing. As the pore pressure increases further, the background gas level also begins to increase and the connection gas peaks become higher. It is reasonable to assume at this point that the pore pressure slightly exceeds the dynamic bottomhole pressure (ECD). A slight increase in the mud weight at this point then causes a sudden decrease in the background gas and the connection gas peaks disappear, indicating that a slight static overbalance has been established.

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PRESSURE PROFILES

MUD WEIGHT

GAS LEVELS

C Connection C Bottomhole Dynamic Pressure

DEPTH

C C

Background Gas

Pore Pressure Connection Gases

C C

Increase in BGG Level C C C C C C – Indicates connection WEOX02.099

Figure 2.22 Schematic Diagram showing Mud Gas Levels as an Indicator of Formation Pressures

One major problem with this type of interpretation is to distinguish connection gas peaks caused by effective mud weight reduction due to stopping circulating, from gas swabbed into the wellbore when the drillstring is picked up. Swabbing effects are much more difficult to quantify than simple reductions from the ECD to static mud weight. This may result in higher than actual pore pressure estimates being made, especially if the connection gases observed are entirely due to swabbing. Clearly, it is good practice to use connection procedures that minimise swabbing. If used consistently, this will aid in the interpretation of connection gas levels.

(c) Trip Gas (TG) This gas is produced by the same mechanism as connection gas, but the effect of swabbing due to pulling the drillstring from the hole will generally be greater. This is because the cuttings will have been circulated from the annulus and pipe speeds will be greater. A trip gas peak will be observed on circulating bottoms up after a round trip or non-drilling operation. Swabbing, due to pulling the drillstring out of the hole, may cause the whole of the openhole section to be underbalanced. Thus the observed trip gas may not come from the bottom of the hole but from somewhere higher in the openhole section, and two or more gas peaks may be observed. This effect may also appear for connections if there is a high degree of swabbing or the hole is underbalanced. Lag time calculations should locate the depths/formations causing the gas peaks.

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Due to the complex causes of trip gas, it may only be used qualitatively in estimating formation pressures. The early onset of trip gas after circulation is resumed may indicate that much of the openhole is slightly underbalanced. Other abnormal pressure indicators must be consulted to confirm this.

(d) Miscellaneous Gases These are mainly ‘kelly gas’, recirculated trip gas and carbide gas.

GAS LEVEL

TOTAL GAS

10

20

MUD WEIGHT

30

40

50

60

70

60

70

60

70

RECYCLED TRIP GAS

20

30

40

50

TIME

10

KELLY CUT TRIP GAS 10

20

30

40

50

CIRCULATION STARTED

WEOX02.100

Figure 2.23 Example of Mud Gas Levels showing Trip Gas, Kelly Gas (Kelly Cut), and Recycled Trip Gas

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Kelly gas (also known as ‘kelly cut’) is caused by air being circulated around the system from a partly empty drillstring or kelly after a trip or connection. The air is pumped into the borehole as a slug of mud aerated with compressed air. This enhances any gas diffusion effects from formations to the borehole and may result in enrichment of the aerated mud with the hydrocarbon gases. A gas peak will thus be recorded when this mud is circulated back to the surface. Kelly gas due to connections is rarely seen as the kelly is usually kept full of mud during connections by closing the lower kelly cock. Kelly gas after a trip is sometimes observed (as shown in Figure 2.23) but should be easily distinguishable from other gas peaks by experienced Mud Loggers. Although indicating the presence of hydrocarbon gases, kelly gas is of no value for formation pressure evaluation. Recirculated trip gas (or any other recirculated gas) behaves in a similar way to kelly gas, and should be anticipated by the Mud Loggers from knowledge of the mud system total circulation time. An example is shown in Figure 2.23. Carbide gas is used to check the calculated total circulation time and is caused by the Mud Loggers putting calcium carbide down the drillpipe at a connection. The carbide reacts with the water in the mud to produce acetylene, a hydrocarbon gas that is detected as a large sharp gas peak when circulated round to surface. The circulation time can then be used to back calculate the openhole volume and thus to check for hole enlargement. It must be noted that evaluation of formation pressures from gas levels relies entirely on hydrocarbon gases being present to some extent in the well being drilled. Occasionally, very ‘dry’ holes are drilled which may be overpressured, but show very low background gas levels. In these wells, it is very difficult to use gas levels as a reliable formation pressure indicator.

3.2

Temperature

Due to the radial flow of heat from the earth’s core to the surface, the subsurface temperature increases with increasing depth. The geothermal gradient is the rate at which the temperature increases with depth and is usually assumed to be constant for any given area. However, it has been found that the temperature gradient across abnormally pressured formations is generally higher than that found across normally pressured formations in the same area. This phenomenon can be explained by considering the thermal conductivity of the formations. Since water has a thermal conductivity of about one-third to one-sixth that of most formation matrix materials, then formations with a higher water content (higher porosity) will have a lower thermal conductivity. These formations will thus have a higher geothermal gradient across them. Overpressured shales usually have a higher water content than normal and will thus have higher than normal geothermal gradients across them. The top of an overpressured shale should therefore be marked by a sharp increase in geothermal gradient. This may often be reflected by an increase in the temperature of the return mud in the flowline. Also, the caprock immediately above a pressure transition zone often shows a reduced geothermal gradient due to increased compaction (higher thermal conductivity) and a lower than normal temperature at the top of the transition zone. This effect is shown schematically in Figure 2.24. Again, this may be reflected in the flowline mud temperature by a reduced flowline temperature gradient. In some cases, the flowline temperature may even fall (negative gradient) and be then followed by a large increase as the overpressured zone is penetrated, as shown schematically in the plot of flowline temperature versus depth in Figure 2.25.

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The example in Figure 2.25 is, of course, an idealised case. The flowline temperature very clearly reflects the changes in formation temperature and there are no other influences on the mud temperature. In practice, there are many other factors that affect the flowline temperature and make the interpretation of flowline temperature plots very difficult, especially offshore. Such factors include: •

Circulation rate.

•

Rate of penetration.

•

Time elapsed since the last trip (the mud in the hole heats up during a trip).

•

Volume of the mud system.

•

Surface treatments such as adding water, mud chemicals or weighting material.

•

Ambient temperature (diurnal temperature changes, such as those encountered in desert regions, may cause large fluctuations in flowline temperatures).

•

Lithology effects (sandstones and limestones generally have higher thermal conductivities than shales).

•

Cooling effect of the sea around long marine risers.

Various methods are used to improve the interpretation of temperature-depth plots. Surface effects can be minimised by measuring the temperature of the mud in both the flowline and the suction pit (mud temperature into the hole), and then plotting lagged differential temperature. A sharp increase in differential pressures may then indicate entry into a pressure transition zone. However, the temperature trends (flowline and differential) are still found to be obscured by discontinuities at bit trips, wiper trips and other periods with no circulation. These discontinuities split the temperature depth plot into a series of unconnected depth segments, as shown in the left hand curve in Figure 2.26. Since overpressure indications are based on temperature gradient changes rather than on the magnitude of the flowline temperature, each depth segment on the temperature-depth plot can be investigated separately for gradient changes. It may, however, be helpful to plot the segments end to end, disregarding the absolute temperatures, to produce a ‘smoothed curve’. Also, end to end plotting of the individual segment trendlines may be of value, but care is required to ensure that this technique does not smooth out obvious gradient changes within an individual segment. The three techniques for plotting flowline temperature are shown in Figure 2.26.

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GEOTHERMAL GRADIENT

DEPTH

GEOTEMPERATURE

OVERPRESSURE

WEOX02.101

DEPTH

Figure 2.24 Schematic Diagram showing Theoretical Geothermal Gradients and Temperature Profile through an Overpressured Zone

TOP OF OVERPRESSURED ZONE

WEOX02.102 FLOWLINE TEMPERATURE

Figure 2.25 Schematic Diagram showing Expected Flowline Temperature Response on Drilling through an Overpressured Zone

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NEW BITS

NB

NB

DEPTH

NB NB NB NB NB NOTE TEMPERATURE REDUCTION

GRADIENT

NB NB NB NB

TOP OF OVERPRESSURE

NB RAW DATA END-TO-END PLOT

FLOWLINE TEMPERATURE

TREND-TO-TREND PLOT

WEOX02.103

Figure 2.26 Example Flowline Temperature Plots showing Raw Data Plot, End-to-end Plot and Trend-to-trend Plot

Due to the many factors affecting the flowline mud temperature, it is very difficult to interpret temperature-depth plots to evaluate formation pressures. At least, changes in the gradient of the plots may suggest that an overpressured zone has been penetrated. It is unlikely that flowline temperature will be the primary indication of abnormal pressures, though it may well be useful to support other pressure indicators.

(a) Bottomhole Formation Temperature (BHT) The actual formation geothermal gradient can not be estimated from surface mud temperature measurements. Downhole formation temperatures are required. However, it is only possible to measure the downhole mud temperature. This is normally done during wireline logging runs as most logging tools contain a maximum recording thermometer. Mud temperatures recorded from consecutive logging runs are used to predict the actual bottomhole formation temperature, assuming that the maximum temperature is at the bottom of the hole.

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T

tL

LOG tc + tL tL

241 257 262

4.25 7.00 9.50

0.260 0.178 0.133

300

290

RECORDED TEMPERATURE, T (°F)

TRUE BHT IS 288°F

280

270

260

250

240

230 0

0.1

0.2

0.3

0.4

0.5

LOG tc + tL tL

WEOX02.104

Figure 2.27 Example ‘Horner’ Temperature Plot for Estimation of True Bottomhole Temperature (BHT)

When drilling, the formations in the lower section of the hole are cooled by the mud in circulation. When circulation stops, the mud temperature begins to rise and gradually approaches the formation temperature. It is estimated that about four days are required for the mud temperature to reach equilibrium with the formation temperature. A modified Horner expression is used to model the temperature increase with time. By extrapolating

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the temperature increases to infinite time, it is possible to estimate the formation temperature. The Horner temperature expression is:

T = Tf – c.log where T Tf c tC tL

tC + t L tL

(2-21)

= measured temperature (°F or °C) (from each wireline logging run) = actual formation temperature (°F or °C) = constant = circulation time at TD = time since circulation stopped

A plot of T versus log ((tC + tL)/tL) should thus give a straight line, as shown in Figure␣2.27. At ‘infinite time’ after circulation was stopped (i.e. tL = infinity), the value of log (t C ␣+␣t L)/tL) equals zero. Hence, extrapolating the plot to intercept the temperature axis gives the estimated actual formation temperature, as shown in Figure 2.27. The geothermal gradients between the logging run end points can then be calculated. Increases in the geothermal gradient may indicate the presence of abnormal pressures. Unfortunately the actual formation temperature can only be estimated at logging points. Thus, only three or four formation temperatures can be estimated from which geothermal gradients can be established. These gradients are thus average gradients over significant depth intervals and they can only be established after each hole section has been drilled. Hence, they are generally of little use in pressure evaluation while drilling, but may confirm any flowline temperature trends that were noticed earlier.

3.3

Resistivity/Conductivity/Chlorides

The resistivity of a formation depends on the porosity and the dissolved salts concentration in the formation pore water. Due to their higher pore water content, overpressured shales generally have lower resistivities than normally pressured shales at the same depths. When using water base muds, an attempt can be made to monitor this formation property by measuring the mud conductivity (conductivity is simply the inverse of resistivity). The mud conductivity at the flowline and suction pit can be measured and a conversion made to chlorides. An increase in the differential chlorides, known as ‘delta-chlorides’, may then indicate abnormal pressures. It is doubtful whether an increase in mud conductivity due to the release of pore water from drilled cuttings would be measurable. This is due to the volume of pore water released being minute compared to the volume of mud. However, pore water influxes from more permeable formations may be seen as changes in mud conductivity or delta-cholrides. Hence, a warning of underbalanced conditions may be given. The system is best suited to situations where there is a large difference between pore water and mud salinity. In these situations, the response of differential mud conductivity is similar to that of mud gas levels showing influx peaks at connections or a gradual increase due to underbalanced conditions. This is shown schematically in Figure 2.28. Obviously, mud conductivity as an abnormal pressure indicator has many limitations. A large salinity contrast between mud filtrate and formation fluids is required. Thus, the method is of little use in saline mud systems, unless of course, the mud filtrate salinity is much greater than the formation water salinity. This could be the case with saturated salt and potassium chloride (KCl) mud systems, and may well result in a mirror image plot to that shown in Figure 2.28.

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ZERO LOSS

GAIN MUD CONDUCTIVITY

DEPTH

MUD CHLORIDE

INFLUX AT CONNECTION

CONTINUOUS INFLUX

INCREASE MUD DENSITY

MUD CONDUCTIVITY MUD CHLORIDE WEOX02.105

Figure 2.28 Example of Typical Response of Differential Mud Conductivity/Delta Chlorides

3.4

Flowline Mud Weight

Continuous recording of the flowline mud weight will show mud density changes due to gas cutting or formation influxes. Some influxes are not always picked up by an increase in return mud flow or by an increase in mud pit level, especially if the influx occurs gradually due to a very low permeability formation. Thus, an underbalanced situation due to abnormal pressures may be indicated by a slight reduction in the flowline mud weight.

4 Cuttings Parameters (a) Shale Bulk Density The bulk density of normally compacted shales increases with depth. Overpressured shales are generally undercompacted and thus have higher porosities and lower bulk densities than would be expected. If shale bulk density is plotted against depth as drilling progresses, then a normal compaction trendline can be established. A decrease in shale bulk density away from the normal compaction trendline may then indicate the presence of an overpressured zone. A schematic shale bulk density plot is shown in Figure 2.29.

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The magnitude of abnormal pressures can be calculated from shale bulk density plots using the equivalent depth method (as described previously for d-exponent plots).

DEPTH

NORMAL SHALE TREND LINE

TOP OF OVERPRESSURES

2.4

2.5 SHALE DENSITY (gm/cc)

2.6

WEOX02.106

Figure 2.29 Schematic Shale Bulk Density/Depth Plot

Alternatively empirical curves, relating observed bulk density deviation from the normal trend to formation pressure gradient, can be used. However, such curves are area dependent, so can only be used if the appropriate area curve is available. Hence it will usually be necessary to use the equivalent depth method if formation pressure magnitudes are required from shale bulk density plots.

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The most common methods of measuring shale bulk density at the rigsite are: •

Mud Balance Shale cuttings are added to the mud balance cup until the balance reads 1.0 SG (8.33␣ppg) with the cap on. The cup is then topped up with fresh water and re-weighed (W). The shale bulk density is then given by: Bulk density (SG) =

•

1 2–W

(2-22)

Density Column A graduated column of fluid is prepared from a mixture of two fluids of different densities such that the density of the mixture varies with column height. The column is calibrated using beads of known density which settle at different heights in the column. Selected shale cuttings are then dropped into the column and the height at which they settle is converted to shale density using the calibration curve. The method is illustrated in Figure 2.30.

250

200

SG 2.2

150 2.3 Shale

2.65

100 Shale Density

2.48

FLUID LEVEL cc

2.38

50

0 2.2

2.3

2.4

2.5

2.6

2.7

2.8

DENSITY (gm/cc or SG) WEOX02.107

Figure 2.30 Variable Density Column for Measuring Shale Bulk Density

The mud balance method has the advantage of being fast and simple and uses a good quantity of cuttings to obtain a good average bulk density. The density column, however, requires selection of individual cuttings and multiple determinations to obtain an average density value. The mud balance method is probably the more representative method.

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Use of shale bulk densities for the detection and evaluation of formation pressures frequently has the following limitations: •

Presence of shale gas in the cuttings decreases the bulk density values determined.

•

Cavings from higher up the hole may be part of the sample.

•

The reliability of the data depends on the consistency and care taken by personnel, when carrying out the density determinations.

•

Formation age boundaries and unconformities may cause shifts in the normal compaction trendline. It may be necessary to determine individual normal compaction trends for each geological age unit.

•

Variations in the lithology, such as high carbonate content, silty/sandy shales etc, may cause significant variations in the bulk density determinations. Only good clean shales should be plotted. The presence of high density minerals, such as pyrite, will increase bulk density values and may mask the onset of abnormal pressures.

•

Density measurements on cuttings from water base muds are usually low due to the absorption of water by the cuttings. Less reactive muds, such as oil base muds and highly inhibited water base muds, will give more accurate cuttings densities.

SHALE DENSITY

DEPTH

NORMAL PRESSURE

OVERPRESSURE

COMPACTION DISEQUILIBRIUM

CLAY DIAGENESIS

AQUATHERMAL PRESSURING

TECTONIC PRESSURING WEOX02.108

Figure 2.31 Response of Shale Bulk Density/Depth Plots in Overpressures caused by Various Mechanisms

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•

The response of shale bulk density values in abnormal pressured zones will vary with the type of mechanism that caused the overpressure. This is illustrated by the idealised plots shown in Figure 2.31. However, as most overpressures in shales are caused by compaction disequilibrium and aquathermal pressuring, the most common response will be a decrease in shale bulk density at the top of an overpressured zone. (See Chapter 1 Section 1.4 for explanations of the various causes of abnormal formation pressures.)

Despite the above limitations, shale bulk density plots can be a very valuable indicator of abnormal pressures. They should be constructed during the drilling of all exploration and appraisal wells, and are most useful when long shale sections are encountered.

(b) Shale Factor Shale factor is a measure of the cation exchange capacity (CEC) of shales. The CEC of a shale is dependent on the montmorillonite content. This in turn depends on the degree to which montmorillonite conversion to illite has progressed in the shale since montmorillonite has a much higher CEC than illite (See ‘Clay Diagenesis’, in Chapter␣1 Section 1.4). The CEC is expressed in milli equivalents per 100 grams of sample (meq/100gm), and is termed the shale factor. The shale factor of a sample of shale cuttings is determined using the methylene blue test. Basically, a suspension of powdered sample (in water) is titrated against a solution of methylene blue dye of known concentration. The end point of the titration is when the sample suspension water first turns blue. The shale factor is then calculated from: shale = 100 factor sample wt (meq/100gm) (gm)

X

titrant vol (ml)

X

titrant normality

(2-23)

Pure montmorillonite clays have a high shale factor of about 100 meq/100gm. This is due to the presence of many loosely bound cations (Na+ , Ca++) between the clay platelets. However, pure illite clays, due to their tightly bound cation (K+ ) between clay patelets, have low shale factors of 10 to 40 meq/100gm. Thus, shale factor can be used to identify the montmorillonite/illite content of shale samples. For abnormal pressure evaluation, however, the use of shale factor is limited as it is dependent on the various mechanisms that may cause overpressures. Generally, shale factor decreases with depth as montmorillonite is converted to illite. In␣ o verpressured intervals caused by compaction disequilibrium (see Chapter 1 Section␣1.4 ) clay dewatering has been restricted, which in turn restricts montmorillonite diagenesis to illite. Thus a larger proportion of montmorillonite will be present in the overpressured zone, resulting in an increase in shale factor. This is shown schematically in Figure 2.32␣(a). However, overpressures caused by clay diagenesis (montmorillonite dehydration) will show a decrease in shale factor on entering the overpressured zone. The proportion of montmorillonite has been reduced by conversion to illite, with the release of large amounts of water. This causes increased pore pressure if water escape is restricted. This shale factor response is shown schematically in Figure 2.32 (b).

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Since compaction disequilibrium is thought to be the major contributing mechanism to overpressure development in shales, the shale factor response of Figure 2.32 (a) will probably be the most dominant. However, the contribution of other overpressure mechanisms will complicate the interpretation of shale factor plots. This often results in shale factor being of little use in the detection of abnormal pressures.

DEPTH

SHALE FACTOR

DEPTH

SHALE FACTOR

MONTMORILLONITE CONTENT INCREASE

MONTMORILLONITE CONTENT DECREASE

OVER PRESSURES

(a) COMPACTION DISEQUILIBRIUM

OVERPRESSURES

(b) CLAY DIAGENESIS WEOX02.109

Figure 2.32 Shale Factor/Depth Response to Overpressure caused by Compaction Disequilibrium and Clay Diagenesis (c) Cuttings Character The presence of cavings in drilled cuttings samples is an indication that the borehole wall is unstable. Cavings are much larger than normal drilled cuttings and are readily seen at the shale shakers. They are thought to be produced by two different mechanisms which result in cavings of different shapes and sizes, these two mechanisms are: •

Underbalanced drilling

•

Borehole stress relief

In underbalanced drilling conditions, the pore pressure in the formation adjacent to the borehole is greater than the pressure in the borehole. In impermeable formations, such as shales, the pressure differential due to an underbalance may be high enough to exceed the tensile strength of the shales. The shale will thus fail in tension and form cavings which fall into the borehole. These cavings are usually long, splintery, concave and delicate, as illustrated in Figure 2.33 (a).

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The natural stresses that are present in the earth’s crust vary regionally and with depth, lithology etc. Drilling a hole through formations will relieve some of these stresses depending on the hole angle and direction in relation to the principal formation stresses. The result may be that the formation stress at the borehole wall is greater than the stress (pressure) due to the mud column. The borehole wall may then fail either in compression from vertical stresses or in tension due to horizontal stresses, or a combination of both. Cavings produced in this manner tend to be blocky and rectangular in shape, as shown in Figure 2.33 (b). Thus, the presence of cavings in cuttings samples will not necessarily mean that the hole is underbalanced. However, other overpressure indicators should always be examined in detail to confirm whether abnormal pressures are being encountered. Even if it can not be confirmed that the hole is underbalanced, it may still be necessary to increase the mud weight to regain hole stability, and avoid the problems caused by excessive amounts of cuttings/cavings being present in the hole.

FRONT

SIDE

MAY BE STRIATED

FRONT

SIDE

SCALE

0.5in to 1.5in

TYPICALLY CRACKED

DELICATE SPIKY SHAPE

BLOCKY RECTANGULAR SHAPES PLAN

PLAN

CONCAVE SURFACE

(a) Typical shale caving produced by underbalanced conditions

(b) Typical shale caving produced by stress relief

WEOX02.110

Figure 2.33 Characterisation of Shale Cavings Caused by Underbalanced Conditions and Stress Relief (d) Other Methods Several other methods of formation pressure evaluation based on measurements on shale cuttings have been developed. These include shale cuttings resistivity, filtration rate of shale cuttings slurry, filtrate (shale water) colour index, shale cuttings moisture index, redox and pH potential of cuttings slurry and slurry filtrate. These methods are fairly complex and time consuming and thus have not gained wide acceptance as rigsite techniques. A more detailed discussion of these techniques is given by Fertl(17).

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5 Measurement While Drilling (MWD) Techniques Measurement While Drilling (MWD) tools are now able to provide continuous downhole drilling parameter data and electric log data whilst drilling is in progress. The use of MWD data in formation pressure evaluation follows the same principles as previously discussed for surface measured drilling parameters, as outlined for wireline log data in Section 2.4 of this Chapter. The advantage of MWD data is that actual downhole drilling parameters (weight-on-bit, torque) are measured and the formation log data are obtained very shortly after the formation has been drilled. Thus, formation log data and conventional ‘whilst drilling’ techniques can be combined to evaluate formation pressures as drilling progresses. The downhole drilling parameters of most relevance are: •

Weight-on-bit The actual downhole weight-on-bit (WOB) is usually less than recorded at surface due to the drag in the hole. Using the actual downhole WOB will give more accurate values for d-exponent or the drilling rate method that is being used as a formation pressure indicator.

•

Downhole Torque Variations in torque at the bit may be used to indicate bit wear. This in turn may be used to account for bit wear in more complex drilling rate methods for estimating formation pressures.

•

Downhole Temperature The difference between downhole annulus temperature and flowline temperatures will give an indication of the amount of heat transferred from the formation to the mud. A similar effect to that described in ‘Differential Temperature’ on Page 2-50, should be observed on drilling into an overpressured zone.

The MWD formation logs presently available for formation pressure evaluation are gamma ray, resistivity and most recently, porosity. The gamma ray log is used to identify lithology. Shales show a high level of radioactivity, whereas sands and evaporites (except for complex salts) show a low level. Hence the gamma ray log can be used to pick clean shale sections for overpressure determination by any of the shale related parameters previously discussed. In particular, the gamma ray log can be used in conjunction with the MWD resistivity log to plot shale resistivities whilst drilling. The theory and method of formation pressure evaluation from shale resistivities is discussed further under ‘Wireline Logs’ in Section 2.4 of this Chapter. The gamma ray log itself has been used as a formation pressure indicator. A normal depth related compaction trend was established with departures from this trend indicating the magnitude of overpressures. However, it would appear that this method may only be valid for US Gulf Coast shales. More recently, an MWD porosity log has become available. Thus shale porosities may be measured whilst drilling and a normal compaction trend established. Again, overpressured shales will show an increase in porosity away from the decreasing normal trend. The MWD gamma ray log will also be required to pick clean shales, from which the porosity values can be plotted.

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The combination of MWD logging techniques and downhole/surface measured drilling parameter techniques should enhance the ability to detect and evaluate formation pressures whilst drilling is in progress. Developing MWD technology is continually assessed by Drilling Division, and reports periodically issued.

6 Mud Logging Service The function of the wellsite mud logging service is twofold: •

Sampling and description of drilled cuttings, and hydrocarbons detection and evaluation.

•

Monitoring and interpretation of drilling data for drilling optimisation and formation pressure evaluation.

These functions, and their relation to information flow through a typical mud logging unit,␣are illustrated in Figure 2.34. The level to which the latter function is required depends on the␣ t ype of well being drilled. Usually exploration and appraisal wells require mud logging␣ s ervices capable of a higher level of formation pressure evaluation than for development wells.

(a) Pressure Evaluation Service In most mud logging services, there is a Pressure Evaluation Geologist or Engineer permanently on duty in the mud logging unit. It is this individual’s responsibility to closely monitor all the available formation pressure indicators and to communicate this information to the Company supervisory personnel at the rigsite. He should also make formation pressure estimates based on all the available pressure indicators (and discussions with Company personnel), and be able to support these estimates with sound reasoning. The Pressure Evaluation Geologist/Engineer holds a very responsible position amongst the various rigsite personnel and should have many years experience in rigsite mud logging work. It is important that a good level of communication is established and maintained with the person(s) concerned in order that reliable formation pressure estimates are obtained and their implications speedily acted upon.

(b) Composite Logs As part of the pressure evaluation service, the Pressure Evaluation Geologist/Engineer will prepare ‘composite logs’ showing well depth versus various selected overpressure␣indicators. These logs are potentially most useful as they show graphically the response of the various overpressure indicators to differing lithologies and formation␣pressure regimes. It is most important that these logs are kept up to date to enable up-to-the-minute pressure estimates to be made based on the information given by the logs.

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Figure 2.34 Mud Logging Unit Functions and Information Flow Diagram

KELLY POSITION

DEPTH

GAS FROM MUDSTREAM

PENETRATION RATE

CARBON DIOXIDE

H2S PUMP RATE

MICRO GAS

MUD FLOW

TOTAL GAS

HYDROCARBONS

UV BOX

CHROMATOGRAPH

COMPUTATION DISPLAY

DATA STORAGE MUD pH/PHS REMOTE DATA DISPLAY MUD RESISTIVITY EVALUATION MUD WEIGHT FORMATION CUTTINGS

MUD TEMPERATURE

PIT LEVEL/PVT

DENSITY

GEOCHEMICAL ANALYSIS

DRILLING PARAMETERS KELLY HEIGHT

HOOK LOAD

BIT REVOLUTIONS

DRILL RATE

WEIGHT ON BIT

ROTARY SPEED TORQUE

TOTAL DEPTH

STANDPIPE PRESSURE

CASING PRESSURE

CEC

MUD PRESS

FORMATION LOG

MISC ENGINEERING DATA

PRESSURE LOG

WIRELINE LOG DATA

GEOCHEMICAL LOG

BASIC ADDITIONAL

REMOTE DATA TRANSMISSION

WEOX02.111

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(c) Mud Logging Equipment The equipment contained within a modern mud logging unit is very complex, and there are numerous differrent types of sensors available for measuring the various drilling parameters. Different methods are also employed to relay the measured data to the mud logging unit. It is not the intention of this manual to discuss the equipment used by the individual mud logging service companies. General sensor specifications are however given in Table 2.3. Parameter to be Measured

Required Accuracy

Preferred Sensor Type

+/- 0.1% +/- 1ppm +/- 0.5%

Flame ionisation Solid state semi-conductor instrument Flame ionisation

+/+/+/+/+/+/+/+/+/+/+/+/+/+/+/-

Heave and tide compensation independent of kelly, for trip monitoring Pressure transducer (strain gauge) Proximity switch Hall effect current sensor Gamma ray Strain gauge Strain gauge Non-intrusive flow meter Paddle type flow meter Non-intrusive flow meter Proximity switches Platinum resistance Ultrasonics Ultrasonics

Mud Logging Service Total gas Hydrogen sulphide Constituent gases Drilling Data Service Depth Kelly position Hookload Rotary speed Rotary torque Mud weight Standpipe pressure Choke pressure Flow rate in Flow rate out Flow rate out Pump rate Mud temperatures Pit volumes Trip tank volume

Table 2.3

10 cm 10 cm 200 lb 1 rpm 5 amp 0.01 SG 10 psi 10 psi 20 gpm 50 gpm 20 gpm 1 SPM 1°C 5 bbl 0.5 bbl

General Mud Logging Sensor Specifications

(d) Mud Logging Unit Suitability The suitability of a mud logging unit for a Company drilling operation depends essentially on the level of pressure evaluation service required, which in turn depends on the type of well that is to be drilled. The basic geological sampling and mud logging service should not vary significantly with the well type. Once the required levels of mud logging and pressure evaluation services have been defined, then the suitability of individual mud logging units can be evaluated. The current specifications against which the mud logging units/services should be evaluated, are contained in BP report DTG/D/4/86 (24).These specifications cover the basic mud logging service (sampling, cuttings description etc), drilling data service (including pressure evaluation and drilling optimisation), reporting, software, data storage and personnel requirements.

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7 Summary The majority of the ‘whilst drilling’ formation pressure indicators discussed are only applicable to massive shale sections interbedded with sandstone/siltstones. However, as most of our drilling occurs in sedimentary basins containing such sections, then the techniques discussed are of direct relevance to our drilling operations. The most reliable abnormal pressure indicators in shales are probably d-exponent (or other drilling rate method) in combination with gas levels and cuttings character (cavings). Occasionally, one indicator may be particularly effective in showing the onset of abnormal pressures, but this will probably not be apparent until drilling has progressed well into the overpressured zone. It is stressed that all formation pressure indicators must be carefully examined to confirm the possible abnormal pressures that may be implied by a particular overpressure indicator. Also, the possibility of lithological changes should always be borne in mind when sharp changes in abnormal pressure indicators are observed.

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2.4

FORMATION PRESSURE EVALUATION AFTER DRILLING

Paragraph

Page

1

General

2-66

2

Formation Pressures from Wireline Logs 2.1 Sonic Log 2.2 Resistivity Log 2.3 Density Log 2.4 Other Logs

2-66 2-66 2-70 2-75 2-77

3

Direct Pressure Measurements 3.1 RFT/FIT Data 3.2 Drillstem Test Data

2-77 2-77 2-82

4

Summary

2-84

Illustrations 2.35 Schematic diagram showing the Operating Principle of the Sonic (BHC) Logging Tool

2-67

2.36 Schematic diagram showing Shale Sonic Interval Travel Time Response in Overpressures

2-68

2.37 Schematic Shale Resistivity/Depth Plot showing Response in Overpressures

2-71

2.38 Shale Resistivity/Depth Plot illustrating the Problems Associated with Formation Pressure Interpretation

2-73

2.39 Empirical Correlations for Estimation of Formation Pressures from Shale Resistivity Ratio

2-74

2.40 Log-derived Shale Bulk Density Plot on Semi-logarithmic Scales 2-76 2.41 Schematic diagram showing the RFT Pre-test and Sampling Principle

2-78

2.42 Diagram showing the Operation of the RFT Sample Probe

2-79

2.43 Example of an RFT Analogue Pressure Recording

2-79

2.44 Example of a Typical Drillstem Test String (for high pressure gas well) showing Position of Gauges

2-81

2.45 Example of a Typical Pressure Chart from a Mechanical Gauge placed below the Tester Valve in the DST String

2-83

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1 General After each intermediate and reservoir hole section has been drilled, the formations are electrically logged to evaluate their physical characteristics and hydrocarbon potential. Some of these logs can be used to estimate formation pressures to confirm (or otherwise) the estimates made whilst the hole sections were being drilled. Formation pressures calculated from wireline logs are estimates only. Direct formation pressure measurements are normally taken in the reservoir hole section(s) using a wireline repeat formation test (RFT) tool. Also, formation pressures are directly measured in the ‘shut-in’ (pressure build-up) periods during drillstem testing (DST) of potential reservoir formations.

2 Formation Pressures from Wireline Logs 2.1

Sonic Log

The sonic logging tool measures the time, ∆t, required for a compressional sonic wave to travel through one foot (or metre) of formation. This is known as the interval transit time (ITT) and is the reciprocal of formation interval velocity. The principle of operation of the sonic tool (borehole compensated (BHC) tool) is shown in Figure 2.35. Sonic pulses from two transmitters travel through the formation, and are picked up by two pairs of receivers. The time difference between sonic arrivals at each pair of receivers is measured. The average time difference is then recorded to compensate for borehole geometry and tool tilt. As discussed in Section 2.2 of this Chapter, overpressured shales show a higher sonic ITT than normally pressured shales at the same depth. Thus, a plot of sonic ITT in shales versus depth on semi-logarithmic axes should show a straight line compaction trend in normally pressured shales. Departures from this line towards higher shale ITT values indicates abnormal pressures. The normal compaction trend and sonic log departure in overpressures are shown in the schematic sonic log plot in Figure 2.36. A discussion of the problems associated with the interpretation of ITT depth plots, is given in relation to seismic ITT data in Section 2.2 of this Chapter. The main problem areas are: •

Scales Two types of formats have been proposed for plotting ITT-depth data. These are log-log plots (as suggested by Pennebaker(25)), and semi-log plots, as suggested above. The semi-log format is recommended as the linear depth scale enables direct comparison of sonic ITT data with other overpressure indicator plots.

•

Normal Trend Line It is sometimes very difficult to confidently establish the position of the normal shale␣compaction trend line. The depth interval over which the sonic log data are obtained in normally pressured upper hole sections is often too small to reliably establish the normal compaction trend. This is because logs are normally only obtained from below surface casing.

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T

UPPER TRANSMITTER

R1 R2

t1

PAIRED RECEIVERS R1 + R3/R2 + R4

t = t2 – t1 R3

t2

MUD CAKE

R4

T

LOWER TRANSMITTER

WEOX02.112

Figure 2.35 Schematic diagram showing the Operating Principle of the Sonic (BHC) Logging Tool Different lithologies frequently have vastly different sonic ITTs. Care should be taken to ensure that the normal compaction trend line is established through ITT values in good clean shale sections only. It may be necessary to make sonic log plots from several wells (if data are available) in the area of interest. These may then be used to determine the position and gradient of an average regional normal compaction trend line. •

The BHC sonic tool has a ‘depth of investigation’ of only a few inches into the borehole wall. Hence, reactive shales that absorb water from the drilling mud, may exhibit higher ITT values (higher porosity) than would be recorded if the shales were non-reactive. These higher ITT values may falsely indicate the presence of abnormal formation pressures. A deeper reading ‘long spacing sonic’ (SLS) tool is sometimes run. When available, the sonic log data from this deeper reading tool should be used in preference to those from the BHC sonic tool.

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Figure 2.36 Schematic diagram showing Shale Sonic Interval Travel Time Response in Overpressures

DEPTH

NORMAL COMPACTION TREND LINE

TOP OF OVERPRESSURES

SHALE INTERVAL TRAVEL TIME,

t WEOX02.113

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•

Unconformities/disconformities may produce a marked sudden shift in sonic ITT values and may require a second separate normal compaction trend line to be established.

Once the position of the normal compaction trend lines has been firmly established on the semi-log sonic ITT-depth plot, then the depths and magnitudes of suspected abnormal pressures may be calculated. Several methods are available for estimating the magnitude of abnormal pressures from sonic log plots:

(a) Empirical Correlations Charts relating the magnitude of formation pressures to the difference between the observed shale ITT value and the extrapolated normal ITT value are available. These empirical correlations are area dependent, as shown by the examples in Figure 2.9. Note that the correlation developed by Pennebaker (25) (Figure 2.10) should not be used with semi-log ITT plots. This was developed for use in conjunction with log-log seismic ITT plots and is probably only valid for the US Gulf Coast. The empirical correlations are quick and easy to use as formation pressure gradients are read directly from the charts. However, the correlations are area dependent, so their use is limited to areas for which correlations are available.

(b) Equivalent Depth Method When no empirical correlation is available, the equivalent depth method may be used. A full discussion of the method is given in connection with d c-exponent plots, in Section␣ 2 .3 of this Chapter. Equation 2-12 is also used for formation pressure calculations from sonic ITT plots:

FPGO = OPGO – DE (OPGE – FPGNE) DO where FPG O OPG O OPG E FPG NE DO DE

(2-12)

= formation pressure gradient at depth of interest (psi/ft) = overburden pressure gradient at depth of interest (psi/ft) = overburden pressure gradient at equivalent depth (psi/ft) = normal formation pressure gradient at equivalent depth (psi/ft) = depth of interest (ft) = equivalent depth (depth at which sonic ITT is equal to value at DO) (ft)

NOTE: Equation 2-12 can be used directly with gradients in SG, ppg or psi/ft and depths in metres or feet. It is necessary to obtain overburden pressure gradient data for the well being investigated in order to use the equivalent depth method. These data should be available in the form of an overburden gradient-depth plot in the Mud Logger’s report for the well. The advantages and disadvantages of this method are discussed in Section 2.3 of this␣Chapter .

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(c)

Eaton Equation The following equation was presented by Eaton(12) for calculation of formation pressures from sonic ITT plots, the derivation of which is exactly analogous to equation 2-18, which was developed for dc-exponent plots:

FPGO = OPGO – (OPGO – FPGN)

∆t N ∆t O

3.0

(2-24)

where FPGO and OPGO are as defined above and, FPG N = normal formation pressure gradient (psi/ft) ∆t N = extrapolated normal trend sonic ITT at depth of interest (µsec/ft) ∆t O = observed sonic ITT at depth of interest (µsec/ft) The value of the ITT ratio exponent, 3.0, was derived from actual well data. Despite the problems outlined earlier, it is considered that the use of sonic ITT data provides the most reliable method of formation pressure evaluation from well logs. The use of an empirical correlation provides the quickest method of estimating the magnitude of abnormal pressures from sonic ITT plots. However, if a correlation is not available for the area of interest, it will be necessary to use either the equivalent depth method or the Eaton equation (or both). These latter methods require overburden pressure gradient data which should be readily available in Mud Loggers’ reports for the well(s) under investigation.

2.2

Resistivity Log

The resistivity of shales depends on the following factors: •

Porosity

•

Salinity of pore water

•

Temperature

Temperature varies approximately linearly with depth and hence formation resistivities can be corrected for temperature. Also, the salinity of the pore water should not vary significantly with depth. Porosity is thus the major factor controlling shale resistivity. Under normal compaction (i.e. in normal pressure environments), shale resistivity increases with depth since porosity decreases. A plot of shale resistivity versus depth will thus show an increasing trend with depth. In clean shale sections, any departure from this normal trend towards lower shale resistivities may indicate an increase in porosity and hence overpressures. Shale resistivity (Rsh) is plotted on a log scale versus depth on a linear scale. The shape and slope of the normal trend line will vary with the age and type of shales present. This will lead to individual normal compaction trends being developed for each area investigated. It is unlikely that any two areas will have identical normal compaction trends. A schematic shale resistivity-depth plot is shown in Figure 2.37. The normal compaction trend line may be a curve or may approximate to a straight line over certain depth intervals, depending on the area under investigation.

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Figure 2.37 Schematic Shale Resistivity/Depth Plot showing Response in Overpressures

DEPTH

NORMAL COMPACTION TREND LINE

CAP ROCK

TOP OF OVERPRESSURE

0.4

0.6

0.8

1.0

1.5

2.0

3.0

SHALE RESISTIVITY, Rsh (ohm-m) WEOX02.114

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Originally, shale resistivities were plotted from the amplified short normal (ASN) curve of the now absolute ES (electrical survey) logging suite. Today, a variety of resistivity logging tools are run, from which shale resistivity plots may be made. The tools are designed for various depths of investigation from shallow to very deep. The deep reading tools record the true resistivity of virgin formation and thus near borehole effects (shale hydration, mud filtrate invasion in permeable zones) do not affect the resistivity values recorded. The deep reading logs that should be used for resistivity plots are the ILd curve from the dual induction laterolog (DIL) tool and the LLd curve from the dual laterolog (DLL) tool. The dual laterolog tool requires a conductive mud, so it will not work in oil base muds. The dual induction laterolog will work in oil base or water base muds and tends to be the resistivity log that is normally run. Possible problems that may be encountered with shale resistivity plots are: •

Only shale resistivities in thick clean shales must be plotted. It may be necessary to consult a geologist in order to pick good clean shales from the well logs. Use the deepest reading resistivity curve available to plot true shale resistivities.

•

It may be very difficult to firmly establish the shape and position of the normal compaction trend line from the resistivity plot for just one well. An average regional trend may have to be established from the resistivity plots of many wells in the area of interest. Unconformities/disconformities and variations in geological age may show sudden changes in shale resistivities which will affect the position of the normal trend line.

•

Changes in formation water salinity may give false pressure indications. For example, shales in the proximity of large salt masses (e.g. salt domes) have very low resistivities due to increased pore water salinity. This may indicate higher-than-actual formation pressures. Also, shales at depths less than 1000m below surface or the mudline, usually contain formation water fresher than sea water. This results in high resistivity values that may indicate lower-than-actual formation pressures.

The problems associated with interpreting shale resistivity plots are illustrated in Figure␣2.38. Once the normal compaction trend has been firmly established, it is possible to estimate the magnitude of any abnormal formation pressures indicated by the shale resistivity plot. Again, there are several methods available:

(a) Empirical Correlations At depths where the observed shale resistivity values (Rsh(O)) diverge from the normal trend value (Rsh(N) ), the ratio of normal to observed shale resistivity (Rsh(O)/R sh(N)) is calculated. The corresponding formation pressure gradient is then read from a chart such as the one shown in Figure 2.39. As can be seen from this chart, the correlations are area-dependent and the appropriate chart is required for the particular area under investigation.

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Fresh water shales

Normal pressure environment Region 'A' limey shales

DEPTH

ne

o Err s tr

ou

Pressure top

d

en

nd l tre rma No

Abnormally high pressure environment

Region 'B' Lithology, not pressure, change 0.1

0.5

1.0

5.0

Rsh (ohm-m) WEOX02.115

Figure 2.38 Shale Resistivity/Depth Plot illustrating the Problems Associated with Formation Pressure Interpretation (b) Equivalent Depth Method This method is identical to that previously discussed for dc-exponent plots (Section␣2.3 ) and sonic log plots (earlier this Section). Again, equation 2-12 is valid for use with shale resistivity plots:

FPGO = OPGO – DE (OPGE – FPGNE) DO

(2-12)

where DE = equivalent depth (depth at which shale resistivity is equal to the value at the depth of interest, DO) (ft) and FPG O, OPG O, DO, OPGE, and FPGNE are as previously defined in connection with dc-exponent plots and sonic ITT plots. As explained previously, overburden gradient data must be obtained (from Mud Loggers’ report) in order to use this method.

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0.4

0.5

Reservoir FPG, psi/ft

1.25 0.6

North Sea (limited data) (Timko, 1972) 1.50

0.7

HottmanJohnson, 1965

South China Sea (Limited data) Timko, 1972 1.75

0.8 East Cameron Timko-Fertl, 1970

Equivalent mud weight, SG

E Riverton area, Wyo (Timko, 1972)

2.00

0.9 Eaton, 1972 (Range)

2.25

1.0 10

15

20 30 Normal R(sh)/observed R(sh)

40

50

WEOX02.116

Figure 2.39 Empirical Correlations for Estimation of Formation Pressures from Shale Resistivity Ratio (c) Eaton equation Equation 2-25 was proposed by Eaton (12) for calculating formation pressures from␣ s hale resistivity plots (derivation analogous to equation 2-18, developed for dc-exponent plots):

FPG O = OPGO – (OPG O – FPGN)

Rsh(N)

1.20

R sh(O)

where FPGO, OPGO and FPGN are as defined for equation 2-24 (sonic log plots), and Rsh(N) = extrapolated normal trend shale resistivity at depth of interest (ohm-m) Rsh(O) = observed shale resistivity at depth of interest (ohm-m) Again, the value of the shale resistivity ratio exponent, 1.20, was derived from actual well data. Overburden pressure gradients for the well are also required (from Mud Loggers’ well report) in order to use equation 2-25.

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(d) Formation Factor Method This method was proposed by Foster and Whalen,(18) and is based on the equation: Fsh =

Rsh Rw

(2-26)

where F sh = shale formation factor (dimensionless) Rsh = shale resistivity (ohm-m) Rw = formation water resistivity (ohm-m) Basically, the method involves computing a formation water resistivity (Rw) depth profile from the SP (spontaneous potential) curve in clean, shale free water sands. Values of Rsh are then obtained from thick, clean shales from whichever resistivity log is available (ILd or LLd curve). Values of Fsh at depths corresponding to the Rsh values are then calculated from equation 2-26. A plot of Fsh versus depth on semi-log scales (linear depth scale) then shows a straight line trend in normally pressured formations, F sh increasing with depth. Departure from the normal trend towards decreasing Fsh values then indicates abnormal pressures. The magnitude of any abnormal pressures can then be calculated using the equivalent depth method (as discussed in (b) above). The major drawback with this method is the calculation of R w values from the SP curve. The method is subject to inaccuracies, is difficult and is very time consuming. The advantage of this method is that it takes into account changes in formation water resistivity, R w. Other methods rely on the assumption that formation water resistivity remains relatively constant with depth. The method is detailed in full by Foster and Whalen(18) and Fertl(17). All the pressure evaluation methods using resistivity logs were developed for the US Gulf Coast and would appear to work quite well for this region. However, they have been found to be of limited use in the North Sea. Formation water salinity variations cause erratic tool responses which make it virtually impossible to construct a normal compaction trend.

2.3

Density Log

The formation density logging tool consists of a radioactive source which bombards the formations with medium-energy gamma rays. The gamma rays collide with electrons in the formation which cause the gamma rays to scatter. The degree of scattering is directly related to the electron density and therefore the bulk density of the formation. The scattered gamma rays that return to the borehole are picked up by detectors in the logging tool. In the FDC (formation density compensated) logging tool, the gamma ray source and two detectors are mounted on a skid that is pushed against the borehole wall by an eccentering arm. The skid has a plough shaped leading edge to cut through any mud cake present on the borehall wall. Any mud cake that is not removed will effect the tool reading. The dual detectors of the FDC tool automatically compensate for mud cake effects. The corrected bulk density (Pb) and the correction made (∆ρ) are recorded on the FDC log.

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Figure 2.40 Log-derived Shale Bulk Density Plot on Semi-logarithmic Scales

DEPTH

NORMAL COMPACTION TREND LINE

CAP ROCK

TOP OF OVERPRESSURES

2.0

2.1

2.2

2.3

2.4

2.5

2.7

SHALE BULK DENSITY (gm/cc)

WEOX02.117

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A plot of shale bulk density versus depth on either linear or semi-log scales will show a straight line normal compaction trend. Since the bulk density of shales is inversely proportional to porosity, and an increase in shale porosity indicates abnormal pressures, then a decrease in shale bulk density from the normal compaction trend line will indicate abnormal pressures. The semi-log type plot is shown schematically in Figure 2.40. The densities from non-washed-out pure shale sections should be plotted. After the normal compaction trend line has been established, the equivalent depth method (See ‘Sonic’ and ‘Resistivity Logs’) may be used to estimate the magnitude of formation pressures. The use of shale bulk density trends from the formation density log should be a fairly reliable overpressure indicator. However, it has been found that unless borehole conditions are ideal (uniform gauge hole), the formation density log will not be as accurate or reliable for pressure evaluation as other techniques based on sonic or resistivity logs.

2.4

Other Logs

Other wireline logs that have been used to evaluate formation pressures include the spontaneous potential (SP) log, the neutron porosity log (CNL), the thermal neutron decay time log (TDT), and also downhole gravity and nuclear magnetic resonance (NMR) logs. These techniques are discussed further by Fertl(17). Also, the use of an MWD gamma ray log for formation pressure evaluation of US Gulf Coast shales, has been discussed by Zoeller(34).

3 Direct Pressure Measurements 3.1

RFT/FIT Data

The repeat formation tester (RFT) is an electric wireline tool designed to measure formation pressures and to obtain fluid samples from permeable formations. After it has been run in the hole, the tool can be ‘set’ any number of times. This enables a series of pressure readings to be taken and permits the Logging Engineer to ‘pre-test’, or ‘probe’ the formation for permeable zones before attempting to take a fluid sample or a pressure recording. The RFT was developed from the formation interval tester (FIT) which is only able to take one, less accurate, pressure measurement whilst taking a sample. However, the FIT is able to take a pressure measurement/sample in cased hole by using a shaped charge to perforate the casing. A schematic diagram of the RFT pre-test and sampling principle is shown in Figure 2.41.

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FILTER PROBE PACKER

FLOWLINE PRESSURE GAUGE

EQUALIZING VALVE (TO MUD COLUMN)

CHAMBER No 1

CHAMBER No 2 PRETEST CHAMBER

SEAL VALVE (TO LOWER SAMPLE CHAMBER)

SEAL VALVE (TO UPPER SAMPLE CHAMBER) WEOX02.118

Figure 2.41 Schematic diagram showing the RFT Pre-test and Sampling Principle When the tool is set, a packer moves out on one side and back-up pistons move out on the opposite side. This forces the packer against the borehole wall and holds the body of the tool away from the wall to reduce the chances of differential sticking. The probe is then forced into the formation and opened by retracting the filter probe piston. This operation is shown in Figure 2.42. The two pre-test chambers are then operated sequentially, each sampling a small volume (10cc) of the formation fluid at different rates (assuming that the formation is permeable). A filter in the flowline probe prevents sand entry into the tool and the piston cleans the filter when the tool is retracted. A strain gauge pressure transducer monitors the pressure during the pre-test. The pressure is continuously recorded at surface in both analogue and digital form. An analogue pressure recording from a typical pre-test is shown in Figure 2.43.

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MUD CAKE PACKER

UNCONSOLIDATED SAND

PROBE PISTON

FLOWLINE FILTER

PROBE CLOSED DURING INITIAL SET

PROBE OPEN AND SAMPLING

WEOX02.119

Figure 2.42 Diagram showing the Operation of the RFT Sample Probe FLOWRATE, Q

q2 SHUT-IN

q1

TIME, t

PRESSURE, P

t=0

t1

t2

HYDROSTATIC PRESSURE

FORMATION PRESSURE P1 P2

TIME, t

WEOX02.120

Figure 2.43 Example of an RFT Analogue Pressure Recording

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The initial pressure (See Figure 2.43) before the tool is set is the hydrostatic pressure of the mud column. When the tool is set, the pressure rises slightly due to the compression of the mud cake by the packer. The probe piston then retracts giving a drop in pressure due to the flowline volume expansion and communication with the formation. When the piston stops retracting, there is a slight pressure rise because the packer continues to compress the mud cake until the tool is fully set. The pressure then drops again as the first 10cc pre-test piston starts to retract (at time tO). After about 15 seconds, the first pre-test chamber is full (at time t1) and the second piston begins moving at a rate 2.5 times faster than the first piston. The pressure thus drops further until the second pre-test chamber is full (at time t2 ). The pressure then builds up towards a final pressure, which is usually that of the original formation pressure(30). Finally, the probe and packer are retracted and the mud hydrostatic pressure is again measured. Thus, the RFT provides three distinct pieces of pressure data: •

The mud column hydrostatic pressure (two readings).

•

The formation pressure.

•

The pressure transient induced by the withdrawal of a small sample of formation fluid (2 x 10cc).

The two mud hydrostatic pressure readings are compared to verify the stability of the tool’s recording system. The two values should be within a few psi of each other. The formation pressure is used to verify estimates made whilst drilling the well and to construct a reservoir pressure profile. This will yield data on the pressure gradients and nature of the reservoir fluids. The pressure/flowrate/time data from the pre-test sample withdrawal can be used to calculate reservoir characteristics, such as permeability. Hence, the RFT provides accurate data on formation pressures. However, formation pressure data can only be obtained from permeable formations such as reservoir sandstones. These formations may or may not be at the same pressure as adjacent shales. RFTs are normally run at the request of the Geologists/Petroleum Engineers to seek information on potential reservoir formations. However, in deep high pressure wells, the RFT is being increasingly run to obtain accurate formation pressures before potentially troublesome drilling operations (such as coring) are commenced. Accurate knowledge of formation pressures in such wells allows fine mud weight adjustments to be made to minimise the risk of swab/surge pressure problems.

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Figure 2.44 Example of a Typical Drillstem Test String (for a high pressure gas well) showing Position of Gauges DESCRIPTION

Flowhead

Tubing

Lubricator Valve Tubing 5in PIPE RAMS

5in Slick Joint Tubing 5in Slick Joint

MUD LINE

Tubing Downhole Safety Valve (surface controlled) Tubing Annulus pressure operated Downhole Shut-in Tool (including tubing reverse-out facilities) Tubing Nipple Tubing (2 joints) Crossover Pressure Gauge Carrier + 2 Gauges Drill Collar (1 joint) Pressure Gauge Carrier + 2 Gauges Drill Collar (1 joint) Pressure Gauge Carrier + 2 Gauges No-Go Shoulder of Seal Assembly

Permanent Packer Millout Extension Seal Assembly Seal Bore Extension Liner

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BP WELL CONTROL MANUAL

3.2

Drillstem Test Data

Whenever drillstem tests are carried out on potential reservoir formations, various pressure gauges are run in the hole with the test string. The purpose of these pressure gauges is to record the downhole pressure during the sequence of flow and shut-in periods that comprise the drillstem test (DST). The pressures recorded during the test are used to calculate reservoir characteristics such as formation pressure, permeability, skin damage and productivity index. Various types of pressure gauges are available. These are run in conjunction with clocks and recorders, and include: •

Mechanical gauges – normally bourdon tube (BT) type pressure gauges with mechanical clocks and recorders.

•

Electronic gauges – strain gauge, quartz crystal or bourdon tube type pressure gauges with electronic clocks. Data are recorded on various types of electronic memories and read from the gauge on surface after the test by a special reader.

•

Electronic surface read out (SRO) gauges – strain gauge or quartz crystal type pressure gauges linked by cable to the surface where downhole pressures are continuously monitored and recorded.

The mechanical and electronic gauges can be run in various ways/positions in the test string: •

Set in a wireline nipple (hence retrievable during or after a test).

•

Hung off in the tailpipe (below the packer) using a DST hanging kit.

•

Placed in a ‘bundle carrier ’ or ‘gauge carrier’ in various positions in the string.

The SRO gauges are always placed above the tester valve (above the packer) as they are connected to surface equipment by a cable. A typical DST string is shown in Figure 2.44 (for a gas well test). This illustrates the various positions of the pressure gauges in the DST␣string. After a DST has been successfully completed, the test string is pulled and the pressure gauges are retrieved for the pressure charts to be read. A typical valid pressure chart from a mechanical gauge placed below the tester valve is shown in Figure 2.45. Note that a linear plot of the pressures recorded by an electronic gauge should have the same general form, without the baseline. The significant events during the test (marked by capital letters) on Figure 2.45 are as follows: A:

Atmospheric pressure at surface.

A-B: The gauge is run in the hole with the test string and records increasing hydrostatic pressure. The early ‘steps’ effect is the result of pauses to pump the water cushion into the test string. B:

At test interval depth, the gauge records the hydrostatic pressure of the mud column.

C:

The packer is set, squeezing the sump below the packer and causing an increase in pressure.

D-E: The tester valve is opened and the gauge is suddenly subjected to the reduced hydrostatic pressure of the water cushion alone.

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C D B

N

M

G

PRESSURE

L

I E

F H

J K

A

TIME

O

BASE LINE

WEOX02.122

Figure 2.45 Example of a Typical Pressure Chart from a Mechanical Gauge placed below the Tester Valve in the DST String E-F:

The influx of reservoir fluid into the test string adds to the pressure of the partial water cushion.

F:

The tester valve is shut after an initial 5 to 10 minute short flow period.

F-G: The reservoir pressure slowly builds up. After 30 minutes, no more build up is seen. The gauge now gives an estimate of the virgin reservoir pressure (G). G-H: The tester valve is now opened again and the reservoir is exposed to hydrostatic pressure of the fluids in the test string. H-I:

The reservoir flows again and the gauge pressure increases until the water cushion reaches the surface.

I-J:

As the reservoir fluid replaces the water cushion in the test string, the gauge pressure decreases until all the water cushion has been unloaded (J).

J-K:

The pressure continues to fall due to wellbore effects before steadying out as the flow into the wellbore becomes radial.

K: The tester valve is closed at the end of the second flow period. K-L: The reservoir pressure starts to build up again as it returns to equilibrium. L-M: The packer is unset at the end of the second build up period and the pressure gauge again reads the pressure of the annulus mud column. N-O: The test string is pulled out of the hole and the gauge pressures reduces. O:

Finally, the gauge is back on surface and reads atmospheric pressure.

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Analysis of the pressure build up data from the shut-in periods can then give accurate estimates of the reservoir formation pressure. An example of this analysis is given in the BP Guide to Testing Operations. Thus, data from drillstem tests can give accurate estimates of formation pressures. However, the pressure data can only be obtained from permeable reservoir formations that are considered to have sufficient hydrocarbon potential to warrant the expense of a drillstem test. As with RFT pressure data, the reservoir pressure calculated from DST data may or may not be the same as the pressures in adjacent shales.

4 Summary The most accurate estimates of formation pressures are obtained from wireline RFT measurements and drillstem test pressure data. However, these direct measurements are only possible in permeable formations such as sandstones and limestones. These methods are clearly not applicable to impermeable shale sections (where the majority of overpressures are developed). Conversely, estimates of formation pressures from wireline logs are restricted to shale␣sections, with assumptions made as to the pressures in any adjacent permeable sections. The recognition of a normal shale compaction trend line is of vital importance when␣estimating formation pressures from log-derived shale properties. Of the various logs available, the sonic log is usually the best log for quantitative pressure evaluation as it is␣ r elatively unaf fected by changes in hole size, formation temperature, and formation water␣salinity .

Section 2 References 1. ANSTEY, N.A., 1976. the New Seismic Interpreter – Videotape Manual, International Human Resources Development Corporation, Boston, Massachusetts, USA. 2. BARR, M.V., 1983. An Appraisal of Seismic Reflection Techniques for the Recognition and Prediction of Abnormal Formation Pressures. Report PEB/55/83. BP Research Centre, Sunbury. 3. BELLOTTI, P. and GERARD, R.E., 1976. Instantaneous Log Indicates Porosity and Pore Pressure. World Oil, Oct. 1976. 4. BINGHAM, M.G., 1965. A New Approach to Interpreting Rock Drillability. Oil and Gas Journal, Nov. 2 1964?Apr. 5 1965. 5. BOURGOYNE, A.T., 1971. A Graphic Approach to Overpressure Detection While Drilling. Pet. Eng. 43(9): 76?78. 6. “BP”, 1985. A Guide to Testing Operations. BP Exploration Co. Ltd., Operations Support Division, London. June 1985. 7. “BP”, 1986. A Wellsite Guide to Logging Operations. BP Exploration Co.Ltd., Logging Operations Branch, London. January 1986. 8. “BP”, 1985. Resident Geologists Manual. BPPD Aberdeen. 2nd Edition, Sept. 1985. 9. COCHRANE, D.F. and HARDMAN, P., 1986. Shallow Gas Hazards in Drilling Operations. Report DTG/L/1/1986. BPPD London.

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10. COMBS, G.D., 1968. Prediction of Pore Pressure from Penetration Rate. SPE Paper␣2162. 11. DIX, C.H., 1955. Seismic Velocities from Surface Measurements. Geophysics, 20: 68?86. 12. EATON, B.A., 1975. The Equation of Geopressure Prediction from Well Logs. SPE␣Paper␣5544. 13. “EXLOG”, 1980. Field Geologist’s Training Guide. Exploration Logging Inc., USA. 14. “EXLOG”, 1979. Mud Logging: Principles and Interpretations. Exploration Logging Inc., USA. 15. “EXLOG”, 1981. Theory and Evaluation of Formation Pressures. Exploration Logging Inc., USA. 16. “EXXON”, 1975. Abnormal Pressure Technology, Exxon Company, USA. 17. FERTL, W.H., 1976. Abnormal Formation Pressures. Elsevier Scientific Publishing Company, Amsterdam. 18. FOSTER, J.B., amd WHALEN, H.E., 1966. Estimation of Formation Pressures from Electrical Surveys – Offshore Louisiana. SPE Paper 1200. 19. “GEARHART”, 1986. Overpressure. Gearhart Geodata Services Ltd., Aberdeen. 20. HOTTMAN, C.E., and JOHNSON, R.K., 1965. Estimation of Formation Pressures from Log-derived Shale Properties. Journal of Petroleum Technology, 17: 717-723. 21. JORDEN, J.R., and SHIRLEY, O.J., 1966. Application of Drilling Performance Data to Overpressure Detection. Journal of Petroleum Technology, 18: 1387-1394. 22. LESSO, W.G. and BURGESS, T.M., 1986. Pore Pressure and Porosity from MWD Measurements. IADC/SPE Paper 14801. 23. MANN, D.M., 1985. The Generation of Overpressures During Sedimentation and their␣Ef fects on the Primary Migration of Petroleum. Report GCB/156/85. BP Research Centre, Sunbury. 24. MINTON, R.C., 1986. Technical Specification for Drilling Mud Logging Service. Report␣DTG/D/4/86. BPPD Aberdeen. 25. PENNEBAKER, E.S., 1968. An Engineering Interpretation of Seismic Data. SPE Paper␣2165. 26. PRENTICE, C.M., 1980. Formation Pressures from Normalized Penetration Rate Plots. Prentice and Records Enterprises, Inc., Lafayette, Louisiana, USA. 27. REHM, W.A., and McCLENDON, R., 1971. Measurement of Formation Pressure from Drilling Data. SPE Paper 3601. 28. ROESLER, R.F., BARNETT, W.C., and PASKE, W.C., 1986. Theory and Applications of an MWD Neutron Porosity Sensor. SPE/IADC Paper 16057. 29. “SCHLUMBERGER”, 1972. Log Interpretation Volume 1 – Principles. Schlumberger Ltd., New York, USA. 30. “SCHLUMBERGER”, 1981. RFT – Essentials of Pressure Test Interpretation. Schlumberger Ltd.,

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31. SINGH, J., 1987. A Review of Measurement-While-Drilling Systems. Report DTG/L3. BPPD London. 32. VIDRINE, D.J., and BENIT, E.J., 1967. Field Verification of the Effect of Differential Pressure on Drilling Rate. SPE Paper 1859. 33. ZOELLER, W.A., 1970. The Drilling Porosity Log “DPL”. SPE Paper 3066. 34. ZOELLER, W.A., 1983. Pore Pressure Detection from the MWD Gamma Ray. SPE␣Paper␣12166.

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3 PRIMARY WELL CONTROL Paragraph

Page

1

General

3-2

2

Hydrostatic Pressure

3-2

3

Equivalent Mud Weight, EMW

3-2

4

Circulating Pressures and ECD

3-4

5

Calculating the Circulating Pressure Losses

3-7

6

Swab and Surge Pressures

3-10

7

Swab and Surge Calculations

3-12

Illustrations 3.1

Hydrostatic Pressure

3-3

3.2

The Effect of Flowline Elevation – shown in relation to calculation of formation pressure

3-5

Example Calculation of the Equivalent Circulating Density (ECD)

3-6

3.3 3.4 3.5

Theoretical Variation in Swab/Surge Pressure – when tripping pipe at constant speed

3-11

Pressure Surges associated with Lowering Pipe into a Borehole

3-12

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BP WELL CONTROL MANUAL

1 General Primary well control is maintained by controlling formation pore pressures with the hydrostatic pressure of the drilling fluid. Primary well control is exercised between two distinct limits; these being the maximum formation pore pressure gradient and the minimum fracture pressure gradient in a section of openhole. This Chapter is intended to outline the various factors that can influence the actual pressure exerted by the drilling fluid in the wellbore during routine drilling operations. The effect of the following is considered: •

Flowline elevation.

•

Circulation.

•

Tripping pipe.

Easy to use formulae are presented to predict the effects of these factors.

2 Hydrostatic Pressure The hydrostatic pressure of a column of drilling fluid is determined, in theory, by the density, and vertical height of the fluid above a point of interest. The density of the drilling fluid and the height of the fluid column are related to the hydrostatic pressure as follows: Hydrostatic pressure (psi) = MW (SG) X D (m)

X

1.421

Figure 3.1 shows a sample calculation.

3 Equivalent Mud Weight, EMW The most convenient method of describing downhole pressure is in terms of an equivalent mud weight (EMW). EMW is used in order that downhole pressure can easily, and without confusion, be related to the density of a mud column. EMW can therefore be used to describe a formation pressure as well as a pressure applied by a column of mud. The hydrostatic pressure of the mud column acts as a result of the height of fluid between the flowline and the point of interest in the wellbore. The EMW must therefore be referenced to the flowline.

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BP WELL CONTROL MANUAL

Figure 3.1 Hydrostatic Pressure

B

A

VERTICAL DEPTH = 1000m

MEASURED DEPTH = 1200m

MUD @ 1.5 SG The hydrostatic pressure at total depth in well A and well B = Density of the (SG) x vertical depth (m) x 1.421 = 1.5 x 1000 x 1.421 = 2130 psi WEOX02.123

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BP WELL CONTROL MANUAL

It is important therefore that the effect of flowline elevation be considered when describing formation pressures in terms of an equivalent mud weight. This is because formation pressures are originally referred to sea-level, or the surface elevation, depending on whether the well is offshore or on land. Figure 3.2 shows an example of the calculation of the EMW of a normally pressured formation referenced to the flowline of a semi-submersible drilling rig.

4 Circulating Pressures and ECD When the well is static, the applied pressure at a given point in the well is equal to the hydrostatic pressure exerted by the head of fluid above that point. Therefore if the hole is full to the flowline of 1.5 SG fluid, the EMW at any point in the hole, referenced to the flowline, is 1.5 SG. However, if the pumps are started, the EMW at every point in the well will no longer be equal to the weight of the mud. The EMW will be greater than 1.5 SG at every point in the wellbore. The increase in EMW is due to the frictional pressure resulting from the flow of the mud up the annulus. At each point in the well the EMW is increased by a factor reflecting the total frictional pressure above that point. Consider the example of a land well in Figure 3.3. As shown, when the well is being circulated, the downhole pressures are described as equivalent circulating density or ECD. There are many factors that can affect the ECD in a particular well, however the most fundamental factors are: •

The hole depth.

•

The circulation rate.

•

The mud weight.

•

The rheology of the mud.

•

The size of the hole.

•

The OD of the drillstring.

•

The quantity of cuttings in the annulus. (The presence of cuttings and drilled solids in the mud will have the effect of increasing the effective mud weight and changing the mud rheology.)

It is clearly important to be able to estimate circulating pressure losses in order to be able to predict both the pump pressure and downhole ECD at specified circulating rates. The next paragraph details the formulae that can be used to estimate circulating pressure␣losses.

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Figure 3.2 The Effect of Flowline Elevation – shown in relation to calculation of formation pressure

1

NORMALLY PRESSURED SHOWING SAND @ 300m BELOW SEA LEVEL

2

SAND EQUIVALENT MUD WEIGHT REFERENCED TO THE FLOWLINE OF A SEMISUBMERSIBLE DRILLING RIG

FLOWLINE ELEVATION

SEA LEVEL

25m

100m

SEA BED

200m

Formation pressure at 325m BRT = 1.03 x 1.421 x 300 = 439psi Normal pore pressure gradient = 1.03 SG

Formation pressure at this point referenced to the flowline, in EMW = 439 = 1.421 x 325 = 0.95 SG

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Figure 3.3 Example Calculation of the Equivalent Circulating Density (ECD)

A

HOLE STATIC

B

HOLE BEING CIRCULATED

PUMP

1.5 SG MUD IN THE HOLE

2000m

Pressure drop = 100psi

500m

Total pressure at shoe = (1.5 x 2000 x 1.421) + 100 = 4363psi ECD at shoe = 4363 2000 x 1.421 = 1.54 SG Pressure drop = 150psi

Hydrostatic pressure EMW = 1.5 SG

Total pressure at TD = (1.5 x 2500 x 1.421) + 250 = 5579psi ECD at TD = 5577 2500 x 1.421 = 1.57 SG

Hydrostatic pressure EMW = 1.5 SG

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5 Calculating the Circulating Pressure Losses There are various models that attempt to describe the rheology of drilling fluids. The most widely used are the Bingham, Power Law and Modified Power Law Models. The best results have been obtained using the Modified Power Law to model the behaviour of water base drilling fluids. Very large discrepancies have been recorded between predicted and actual circulating pressures when using the Modified Power Law to model the behaviour of oil base drilling fluids. The cause of this discrepancy is considered to be primarily the variation in rheological characteristics of the oil mud under the influence of downhole conditions. The Bingham Model is considerably easier to use than the Modified Power Law and, as a result, it is recommended for field use when the BP Hydraulics Programme is not available. It is recognised that, at low velocity, the Bingham model may overestimate the friction pressure of a mud that exhibits low gel strength. The following procedure can be used to approximate circulating pressure losses using the Bingham Model.

(a) For use inside the pipe: 1. Calculate PV and YP. PV = Ø600 – Ø300 and YP = Ø300 – PV 2. Calculate the mud velocity. v = 7.47 X Q d i2

(m/min)

3. Calculate the pressure loss for the pipe section, assuming laminar flow. P=

L X PV X v 8361.5 X d i2

+

L X YP 68.6 X d i

(psi)

4. Calculate the effective viscosity. µ = 8361.5 X P X d i2 (centipoise) LXv 5. Calculate the Reynolds number. Re =

422.8 X MW µ

X

v

X

d i2

The critical Reynolds number is assumed to be 2000 for Bingham fluids. If Re is␣less than 2000, the flow is assumed to be laminar and the pressure loss is calculated␣using the formula in step 3. If Re is greater than 2000, the flow is assumed to be non␣laminar and the pressure loss must be re-calculated using the formulae in steps 6 and 7:

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BP WELL CONTROL MANUAL

6. Calculate the Fanning friction factor. f=

0.079 Re 0.25

7. Calculate the pressure loss for the pipe section in non laminar flow. P=

f

X

L X MW X v 2 315.8 X d i

(psi)

8. Calculate the critical velocity. (ie the velocity above which the flow will be non laminar) vc =

7.76

X

PV + [7.76

X

(PV2 + (102.79 MW X di

X

YP

X

1

MW X di2 ) )2 ]

(m/min)

(b) For use in the annulus: 1. Calculate the mud velocity. v = 7.47 X Q dhc 2 – d o2

(m/min)

2. Calculate the pressure loss for the section of annulus assuming laminar␣flow . P=

L X PV X v + L X YP 5574.32 (dhc – d o)2 60.96 (dhc – do )

(psi)

3. Calculate the effective viscosity. µ=

5574.32

X

P X (dhc – d o)2 LXv

(centipoise)

4. Calculate the Reynolds number. Re =

422.8 X MW

X

µ

v

X

(dhc – d o)

The critical Reynolds number is assumed to be 3000 for Bingham fluids. If Re is less than 3000, the flow in this section of the annulus is assumed to be laminar and the pressure loss is calculated using the formula in step 2. If Re is greater than 3000, the flow is assumed to be non laminar and the pressure loss must be re-calculated using the formulae in steps 5 and 6: 5. Calculate the Fanning friction factor. f = 0.079 Re 0.25 6. Calculate the pressure loss for the section of the annulus in non laminar flow. P=

f X L X MW X v 2 315.8 X (dhc – d o)

(psi)

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BP WELL CONTROL MANUAL

7. Calculate the critical velocity. (The velocity above which the flow will be non laminar)

vc =

11.63

X

PV + [11.63

X

(PV2 + (51.46 X MW MW X (dhc – do)

X

1

YP X (dhc – do)2))2 ]

(m/min)

(c) To calculate the pressure drop across the bit: 1. Calculate the nozzle velocity. vn =

Q An X 10.23

(m/sec)

2. Calculate the bit pressure loss. ∆Pbit = where v vn Q di dhc do L PV YP MW µ Ø600 Ø300 An P ∆Pbit

vn2 X MW (psi) 12.49 = = = = = = = = = = = = = = = =

mud velocity (m/min) nozzle velocity (m/min) pump output (gal/min) ID of pipe (in.) ID of hole/casing (in.) OD of pipe (in.) length of section of pipe/annulus (m) plastic viscosity (centipiose) yield point (lb/100ft2) mud weight (SG) effective viscosity (centipiose) Fann viscometer reading at 600 rpm (lb/100ft2) Fann viscometer reading at 300 rpm (lb/100ft2) total nozzle area (in.2) section pressure loss (psi) bit pressure loss (psi)

These formulae can be used to estimate the pressure drop in each section of pipe and annulus. The standpipe circulating pressure can be estimated from the sum of the pressure losses across the bit and in all sections of the pipe and the annulus. The ECD at the bottom of the hole can be estimated from the total annulus pressure loss. The annulus pressure losses may also be estimated when circulating by subtracting the calculated pressure drop in the drillstring and the bit from the actual standpipe pressure (accounting also for surface pressure losses). This technique is likely to yield a more accurate estimate of the annulus pressure losses for the following reasons: •

The inside measurements of the drillstring are more accurate than the openhole internal diameter.

•

The pressure drop through the bit is accurately modelled by the formula presented.

•

The effect of loading the annulus with cuttings is measured directly.

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BP WELL CONTROL MANUAL

The main disadvantage of this technique stems from the fact that the majority of the pressure loss in the system is in the drillstring and across the bit. Therefore, a small error in the calculated pressure drop will cause a relatively large error in the estimate of the annulus pressure loss.

6 Swab and Surge Pressures Swab and surge pressures are caused by the movement of pipe in and out of the wellbore. Traditionally swab and surge pressures have been calculated using a steady state model that is based on the assumption that swab and surge pressures are caused by three effects: •

Viscous drag of the mud as the pipe is moved.

•

Inertial forces of the mud when the speed of the pipe is changed.

•

Breaking the mud gel.

Therefore the factors that determine the magnitude of swab and surge pressures are assumed to be: •

The annular clearance.

•

The viscosity of the mud.

•

The gel strength of the mud.

•

The speed of the pipe.

•

The length of low clearance pipe in the hole.

•

The position of the low clearance pipe in the hole in relation to the point of interest.

•

The acceleration or deceleration of the pipe.

On the basis of these assumptions, typical variations in wellbore pressure due to swab and surge pressures whilst tripping pipe are shown in Figures 3.4 and 3.5. Recent studies however, have shown that steady state models are not adequate to model the behaviour of the mud while the pipe is tripped. It has been shown that swab and surge pressures are best modelled as a transient, rather than a steady state phenomenon. The transient model assumes that a pressure wave is propogated at the instant that the pipe begins to move; the wave then travels down the well at the speed of sound and is reflected back up the hole. As a result of this effect, the pressure at a point in the well oscillates. The oscillations will continue until either the pipe reaches a steady speed, or the pipe has stopped and the reflected pressure waves have diminished.

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Figure 3.4 Theoretical Variation in Swab/Surge Pressure – when tripping pipe at constant speed

1

RUNNING IN THE HOLE

2

PULLING OUT OF THE HOLE

1 Increase due to BHA

4 Reduction due to removal of BHA from the hole

MAX SURGE PRESSURE WHEN BIT IS AT POINT OF INTEREST

A

3 Decrease as BHA passes point A

4 Constant stage pressure due to drillpipe in the casing

SURGE PRESSURE AT A

3 Reduction due to removal of drillpipe from the hole

BIT DEPTH

A

BIT DEPTH

2 Increase due to drillpipe

MAX SWAB PRESSURE WHEN BIT IS AT POINT OF INTEREST

2 Influence of BHA

1 Constant swab pressure due to drillpipe in the casing

SWAB PRESSURE AT A

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D

A Negative Surge – Pipe Lifted from Slips B Positive Pressure to Break Mud Gel C Minimum Pipe Velocity D Maximum Pipe Velocity E Negative Surge – Sudden Pipe Stoppage

PRESSURE

B

0 C

E

A TIME

WEOX02.127

Figure 3.5 Pressure Surges associated with Lowering Pipe into a Borehole The latest swab/surge software models the behaviour of the mud as a transient phenomenon and also accounts for the following factors: •

The compressibility of the mud.

•

The elasticity of the wellbore.

•

The change in rheological properties of the mud with pressure and temperature.

•

The temperature profile in the wellbore.

•

The elasticity of the pipe.

7 Swab and Surge Calculations The swab/surge software that is able to model the transient response of the mud to pipe movement has been developed by Sunbury. The software used by mud logging companies currently uses a steady state model. The swab/surge pressures predicted by this model are subject to inaccuracy; especially in deep wells when the transient response of the mud is most significant.

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BP WELL CONTROL MANUAL

The formulae used for the steady state model are relatively easy to use and, as such, may be used in the field to approximate swab/surge pressures. The following procedure should be used to calculate swab/surge pressure for either open or closed pipe: 1. Estimate the velocity of the mud for a given pipe running speed. For closed pipe: v = CL +

For open pipe: v = CL +

do 2 dhc2 – do 2

X

do 2 – di 2 dhc2 – do 2 – di

2

vp

X

vp

where v = velocity of the mud (m/min) CL = clinging constant vp = average running speed of the pipe (m/min) The clinging constant, K, is assumed to equal 0.45 in the absence of detailed formula that are used to predict this quantity. 2. Determine the maximum mud velocity. The maximum mud velocity is generally taken to be 1.5 calculated in (1)).

X

the average velocity (as

3. Determine the swab/surge pressures due to the pipe movement. The swab/surge pressure resulting from the pipe movement can be estimated by substituting the maximum annular mud velocity as calculated in (2) into the formulae for annular pressure loss (Bingham or Power Law). The swab/surge pressure is added to the hydrostatic pressure of the mud if the pipe is being run into the hole and subtracted if the pipe is being pulled. Therefore: EMW at point of interest = MW ±

sumP (SG) D X 1.421

where sumP = total swab/surge pressure (psi) D = vertical depth to point of interest (m) Preston Moore’s method can be used to approximate swab/surge pressures due to the movement of a drillstring that contains a bit with nozzles. The range of values for the resultant swab/surge pressure that are predicted by this technique should be treated with some caution, as it is generally assumed that it will predict low values of swab/surge pressures. The upper limit for swab/surge pressures for a drillstring with a bit and nozzles will be represented by the value calculated for closed pipe.

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BP WELL CONTROL MANUAL

The procedure for calculating swab/surge pressures for a drillstring that contains a bit and nozzles is as follows: 1. Calculate the velocity of the mud around the drillpipe for open pipe. Use the formulae as shown for the previous technique. 2. Calculate the swab/surge pressure generated by the drillpipe due to the pipe movement. The swab/surge pressure can be calculated by substituting the annular mud velocity in the formulae for annular pressure loss (Bingham or Power Law). 3. Calculate the velocity of the mud around the collars. Use the following formulae: v(drillcollar) = v(drillpipe) X Adp Adc where Adp = cross-sectional area of drillpipe annulus (in.2) Adc = cross-sectional area of drillcollar annulus (in.2 ) 4. Calculate the swab/surge pressure generated at the collars due to pipe␣movement. Use the formulae for annular pressure loss (Bingham or Power Law) and v(drillcollar) as calculated in (3). 5. Calculate the total annular swab/surge pressure. This is equal to the sum of the swab/surge pressures at the drillpipe and the collars, or the sum of (2) and (3). 6. Calculate the swab/surge pressure inside the drillstring. Using Preston Moore’s assumption that the fluid level outside the pipe equals the level inside the pipe, the velocity of the mud inside the pipe equals the velocity outside. 7. Calculate the swab/surge pressure generated inside the drillpipe. Assuming that the mud velocity outside the pipe equals that inside the pipe, use the formulae for internal pressure loss (Bingham or Power Law). 8. Calculate the swab/surge pressure generated inside the drillcollar. Assuming that the mud velocity outside the drillcollar equals that inside the collar, use the formulae for internal pressure loss (Bingham or Power Law). 9. Calculate the swab/surge pressure generated at the bit. Using the formulae: vn =

Q An X 10.23

∆P bit = vn2 X MW 12.49

(m/sec) (psi)

where in this case the mud flowrate, Q, is equal to the mud flowrate through the collars.

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BP WELL CONTROL MANUAL

10. Calculate the total internal swab/surge pressure due to the pipe movement. This is equal to the sum of the swab/surge pressures inside the drillstring, (6) plus (8), plus the bit swab/surge pressure as calculated in (9). 11. Estimate the actual swab/surge pressure due to the pipe movement. It is assumed that the actual swab/surge pressure will be between the values calculated in (5) and (10). The resultant swab/surge pressure is added to the hydrostatic pressure of the mud if the pipe is being run into the hole and subtracted if the pipe is being pulled. Therefore: EMW at the point of interest = MW ± D

sumP X 1.421

(SG)

where sum P = total swab/surge pressure (psi) D = vertical depth to point of interest (m)

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BP WELL CONTROL MANUAL

4 FRACTURE GRADIENT Paragraph

Page

1

General

4-2

2

Stresses in the Earth

4-2

3

Fracture Orientation

4-3

4

Fracture Gradient Prediction

4-4

5

Daines’ Method of Fracture Gradient Prediction

4-4

6

An Example Pressure Evaluation Log

4-7

7

Leak Off Tests

4-9

8

Leak Off Test Procedure

4-10

9

Interpretation of Results

4-11

Illustrations 4.1

Principal Stress Orientation

4-3

4.2

Poisson’s Ratio for Different Lithologies

4-5

4.3

An Example Pressure Evaluation Log

4.4

A Typical Fracture Test

4-12

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BP WELL CONTROL MANUAL

1 General The absolute upper limit of primary well control is the point at which the wellbore pressure equals the fracture pressure of the exposed formation. At this point a fracture is initiated and the wellbore can no longer be considered to be a closed system. This will lead to loss of mud from the hole and the possibility of the loss of primary control. In order to drill a well safely therefore, it is useful for the Drilling Engineer to be able to predict and measure fracture pressures. At the well planning stage, the fracture gradient can be estimated from offset well data. If␣this information is not available then Daines’ Method can be used to predict the fracture gradient. As the well is drilled, Leak Off Tests are carried out to assess the mud holding capability of the openhole. It is Company policy that these tests be carried out to leak off point, which in most cases will represent a pressure that is less than the actual fracture initiation pressure. The leak off pressure is converted to an equivalent mud weight which determines the upper limit of primary control for the next hole section. LO tests are generally carried out once in each openhole section after drilling out of the shoe. However the test should be repeated when weaker zones are drilled into. It is not practical to conduct a leak off test at every change in formation and consequently it is useful to be able to predict the fracture gradient of new formations without conducting further leak off tests. Before covering the techniques that are used to predict fracture gradient, it is appropriate to explain the origins of the stresses that occur naturally below the surface of the earth.

2 Stresses in the Earth At any point below the earth’s surface, the resultant stress in the rock can be resolved into three principal stresses that act at right angles to each other; these being: •

The maximum stress.

•

The intermediate stress.

•

The minimum stress.

In most cases, the maximum stress will be vertical, due to the pressure of the overlying rock and pore fluid. This is defined as the overburden pressure. In a tectonically relaxed area the maximum stress will, in most cases, be vertical and the stresses in the horizontal plane will be equal. At shallow depths however, the horizontal stress may be greater than the vertical stress, even in a tectonically relaxed area. Figure 4.1 shows the effect of tectonic forces on the principal stresses. A small tectonic force ensures that the two principal stresses in the horizontal plane are no longer equal. This has the effect of creating an actual intermediate stress.

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BP WELL CONTROL MANUAL

σ'1 = maximum principal stress σ'2 = intermediate principal stress σ'3 = minimum principal stress

σ'3

σ'1

σ'1 σ'2

σ'2 σ'3

σ'3

1 – Tectonically relaxed area – σ'1 is vertical – σ'2 = σ'3 – induced fractures will be vertical

σ'2

2 – under the influence of a small tectonic stress – σ'1 is vertical – σ'2 = σ3 an actual intermediate stress is created

σ'1

3 – in an area that is significantly affected by tectonic stress – σ'1 is horizontal – induced fractures will be horizontal

WEOX02.128

Figure 4.1 Principal Stress Orientation In an area where tectonic stresses are particularly high, it is possible that the maximum principal stress acts horizontally. This may be the case, for example, in a mountainous region where the formations may be severely folded. However, this is unlikely to occur at great depths where the overburden pressure is generally the predominant factor.

3 Fracture Orientation A fracture will be created if wellbore pressures exceed the minimum principal stress at any point in the openhole. The fracture will propogate along the path of minimum resistance, which will be at right angles to the direction of the minimum principal stress. Fractures will therefore be vertical when the minimum principal stress is horizontal, and horizontal if the minimum principal stress is vertical. (See Figure 4.1). Consequently induced fractures will be vertical in areas where tectonic forces are negligible, except possibly at very shallow depths. However horizontal fractures may be formed in areas where tectonic forces are significant. In effect, it is necessary for the applied pressure to lift the weight of the overburden for horizontal fractures to be formed. This is unlikely to occur at depth when overburden pressure will, in most cases, be greater than pressures due to tectonic forces.

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BP WELL CONTROL MANUAL

4 Fracture Gradient Prediction Many different techniques can be used to estimate fracture gradients. Hubbert and Willis were the first to derive a method, but they were followed, amongst others, by Ben Eaton whose technique is currently used by Anadrill, Geoservices and Gearhart. Eaton’s Method was refined by Daines, in 1982, whose technique has since been used by Exlog. Eaton’s Method is most applicable to predicting fracture pressures in areas where a great deal of data relating to subsurface stress regimes is already available. Eaton’s Method relies on the availability of accurate locally calculated stress coefficients to predict fracture pressures. When such information is available, such as in the Gulf Coast, this method has been shown to be very accurate. However, in areas where the subsurface stress regime is relatively unknown, it is not possible to use Eaton’s Method with any degree of accuracy. Daines’ Method is particularly useful in wildcat areas, because the result of the first LO test carried out in a competent formation is used to measure the subsurface stress regime directly. The coefficients that are used to calculate the fracture pressures are specific to each lithology, but are applicable worldwide. As a result, once the first LO test has been carried out, it is possible to predict the fracture pressure in subsequent formations with reasonable accuracy. This technique has proved particularly accurate in wildcat wells in the North Sea.

5 Daines’ Method of Fracture Gradient Prediction Having conducted the first LO test in a competent formation, Daines’ Method can be used to predict fracture pressures in all types of formation types, with the use of the values for Poisson’s ratio as shown in Figure 4.2. The following procedure can be used after the first LO Test (assuming the maximum effective stress to be vertical and due to the overburden): 1. Calculate the magnitude of the tectonic stress. The magnitude of the tectonic stress is calculated at the depth of the first LO test. This is done using the following formula:

σt = Pfrac – σ'l where σt = Pfrac = σ'1 = µ = Pf =

µ – Pf l–µ

tectonic stress (psi) fracture pressure (psi) maximum effective principle stress (psi) Poisson’s ratio for the rock formation pore pressure (psi)

and σ'1 = S – Pf where S = overburden pressure (psi)

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BP WELL CONTROL MANUAL

Figure 4.2 Poisson’s Ratio for Different Lithologies

Clay, very wet

0.50

Clay

0.17

Conglomerate

0.20

Dolomite

0.21

Greywacke: coarse fine medium

0.07 0.23 0.24

fine, medium medium, calcarenitic porous stylolitic fossiliferous bedded fossils shaley

0.28 0.31 0.20 0.27 0.09 0.17 0.17

coarse coarse, cemented fine very fine medium poorly sorted, clayey fossiliferous

0.05 0.10 0.03 0.04 0.06 0.24 0.01

Calcereous (